Federal Register / Vol. 75, No. 201 / Tuesday, October 19, 2010 / Proposed Rules 64221 

accordance with this interpretation. 

OSHA welcomes comments from 

interested parties on this proposed 

interpretation. 

Authority: 29 U.S.C. 655; 29 CFR 

1910.95(b)(1) & 1926.52(b); Secretary’s Order 

5–200, 72 FR 31160, June 5, 2007. 

Signed at Washington, DC, October 12, 

2010. 

David Michaels, 

Assistant Secretary of Labor for Occupational 

Safety and Health. 

[FR Doc. 2010–26135 Filed 10–18–10; 8:45 am] 

BILLING CODE 4510–29–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 49 

[EPA–R09–OAR–2010–0683; FRL–9213–7] 

Source Specific Federal 

Implementation Plan for Implementing 

Best Available Retrofit Technology for 

Four Corners Power Plant: Navajo 

Nation 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: The Environmental Protection 

Agency (EPA) is proposing to 

promulgate a source specific Federal 

Implementation Plan (FIP) requiring the 

Four Corners Power Plant (FCPP), 

located on the Navajo Nation, to achieve 

emissions reductions required by the 

Clean Air Act’s Best Available Retrofit 

Technology (BART) provision. In this 

action, EPA is proposing to require 

FCPP to reduce emissions of oxides of 

nitrogen (NOX) and particulate matter 

(PM). These pollutants are significant 

contributors to visibility impairment in 

the numerous mandatory Class I Federal 

areas surrounding FCPP. For NOX

emissions, EPA is proposing to require 

FCPP to meet an emission limit of 0.11 

lb/MMBtu, representing an 80% 

reduction from current NOX emissions. 

This NOX limit is achievable by 

installing and operating Selective 

Catalytic Reduction (SCR) technology 

on Units 1–5. For PM, EPA is proposing 

to require FCPP to meet an emission 

limit of 0.012 lb/MMBtu for Units 1–3 

and 0.015 lb/MMBtu for Units 4 and 5. 

These emissions limits are achievable 

by installing and operating any of 

several equivalent controls on Units 

1–3, and through proper operation of 

the existing baghouse on Units 4 and 5. 

EPA is proposing to require FCPP to 

meet a 10% opacity limit on Units 1– 

5 to ensure proper operation of the PM 

controls. EPA is requesting comment on 

whether APS can satisfy BART on Units 

1–3 by operating the existing venturi 

scrubbers to meet an emission limit of 

0.03 lb/MMBtu with a 20% opacity 

limit. EPA is also proposing to require 

FCPP to comply with a 20% opacity 

limit on its coal and material handling 

operations. 

DATES: Comments must be submitted no 

later than December 20, 2010. 

ADDRESSES: Submit comments, 

identified by docket number EPA–R09– 

OAR–2010–0683, by one of the 

following methods: 

Federal eRulemaking Portal: http:// 

www.regulations.gov. Follow the on-line 

instructions. 

E-mail: r9air_fcppbart@epa.gov. 

Mail or deliver: Anita Lee (Air-3), U.S. 

Environmental Protection Agency 

Region IX, 75 Hawthorne Street, San 

Francisco, CA 94105–3901. 

Instructions: All comments will be 

included in the public docket without 

change and may be made available 

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

including any personal information 

provided, unless the comment includes 

Confidential Business Information (CBI) 

or other information whose disclosure is 

restricted by statute. Information that 

you consider CBI or otherwise protected 

should be clearly identified as such and 

should not be submitted through 

http://www.regulations.gov or e-mail. 

http://www.regulations.gov is an 

‘‘anonymous access’’ system, and EPA 

will not know your identity or contact 

information unless you provide it in the 

body of your comment. If you send email directly to EPA, your e-mail 

address will be automatically captured 

and included as part of the public 

comment. If EPA cannot read your 

comment due to technical difficulties 

and cannot contact you for clarification, 

EPA may not be able to consider your 

comment. 

Hearings: EPA intends to hold public 

hearings in two locations in New 

Mexico to accept oral and written 

comments on the proposed rulemaking. 

EPA anticipates these hearings will 

occur in Shiprock and Farmington. EPA 

will provide notice and additional 

details at least 30 days prior to the 

hearings in the Federal Register, on our 

Web site, and in the docket. 

Docket: The index to the docket for 

this action is available electronically at 

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

copy at EPA Region IX, 75 Hawthorne 

Street, San Francisco, California. While 

all documents in the docket are listed in 

the index, some information may be 

publicly available only at the hard copy 

location (e.g., copyrighted material), and 

some may not be publicly available in 

either location (e.g., CBI). To inspect the 

hard copy materials, please schedule an 

appointment during normal business 

hours with the contact listed in the FOR

FURTHER INFORMATION CONTACT section. 

FOR FURTHER INFORMATION CONTACT: 

Anita Lee, EPA Region IX, (415) 972– 

3958, r9air_fcppbart@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Throughout this document, ‘‘we’’, ‘‘us’’, 

and ‘‘our’’ refer to EPA. 

Table of Contents 

I. Background 

A. Statutory and Regulatory Framework for 

Addressing Visibility 

B. Statutory and Regulatory Framework for 

Addressing Sources Located in Indian 

Country 

C. Statutory and Regulatory Framework for 

BART Determinations 

D. Factual Background 

1. Four Corners Power Plant 

2. Relationship of NOX and PM to 

Visibility Impairment 

II. EPA’s Proposed Action Based on Five 

Factors Test 

A. A BART Determination for FCPP Is 

Necessary or Appropriate 

B. Summary of Proposed BART Emission 

Limits 

C. Available and Feasible Control 

Technologies and Five Factor Analysis 

for NOX Emissions 

i. Factor 1: Cost of Compliance 

ii. Factor 2: Energy and Non-Air Quality 

Impacts 

iii. Factor 3: Existing Controls at the 

Facility 

iv. Factor 4: Remaining Useful Life of 

Facility 

v. Factor 5: Degree of Visibility 

Improvement 

D. Available and Feasible Control 

Technologies and Five Factor Analysis 

for PM Emissions 

i. Factor 1: Cost of Compliance 

ii. Factor 2: Energy and Non-Air Quality 

Impacts 

iii. Factor 3: Existing Controls at the 

Facility 

iv. Factor 4: Remaining Useful Life of 

Facility 

v. Factor 5: Degree of Visibility 

Improvement 

III. EPA’s Proposed Action on Material 

Handling Limits 

IV. Administrative Requirements 

A. Executive Order 12866: Regulatory 

Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 


jlentini on DSKJ8SOYB1PROD with PROPOSALS
64222 Federal Register / Vol. 75, No. 201 / Tuesday, October 19, 2010 / Proposed Rules 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

I. Background 

A. Statutory and Regulatory Framework 

for Addressing Visibility 

Part C, Subpart II, of the Act, 

establishes a visibility protection 

program that sets forth ‘‘as a national 

goal the prevention of any future, and 

the remedying of any existing, 

impairment of visibility in mandatory 

class I Federal areas which impairment 

results from manmade air pollution.’’ 42 

U.S.C. 7491A(a)(1). The terms 

‘‘impairment of visibility’’ and ‘‘visibility 

impairment’’ are defined in the Act to 

include a reduction in visual range and 

atmospheric discoloration. Id. 

7491A(g)(6). A fundamental 

requirement of the visibility protection 

program is for EPA, in consultation with 

the Secretary of the Interior, to 

promulgate a list of ‘‘mandatory Class I 

Federal areas’’ where visibility is an 

important value. Id. 7491A(a)(2). These 

areas include national wilderness areas 

and national parks greater than six 

thousand acres in size. Id. 7472(a). 

On November 30, 1979, EPA 

identified 156 mandatory Class I Federal 

areas where visibility is an important 

value, including for example: Grand 

Canyon National Park in Arizona (40 

CFR 81.403); Mesa Verde National Park 

and La Garita Wilderness Area in 

Colorado (Id. 81.406); Bandelier 

Wilderness Area in New Mexico (Id. 

81.421); and Arches, Bryce Canyon, 

Canyonlands and Capitol Reef National 

Parks in Utah (Id. 81.430). These 

mandatory Class I Federal areas are 

within an approximately 300 km (or 186 

mile) radius of FCPP. 

On December 2, 1980, EPA 

promulgated the first phase of the 

required visibility regulations, codified 

at 40 CFR 51.300–307. 45 FR 80084. The 

1980 regulations deferred regulating 

regional haze from multiple sources 

finding that the scientific data were 

inadequate at that time. Id. at 80086. 

Congress added Section 169B to the 

Act in the 1990 CAA Amendments, 

requiring EPA to take further action to 

reduce visibility impairment in broad 

geographic regions. 42 U.S.C. 7492. In 

1993, the National Academy of Sciences 

released a comprehensive study 

required by the 1990 Amendments 

concluding that ‘‘current scientific 

knowledge is adequate and control 

technologies are available for taking 

regulatory action to improve and protect 

visibility.’’ Protecting Visibility in 

National Parks and Wilderness Areas, 

Committee on Haze in National Parks 

and Wilderness Areas, National 

Research Council, National Academy 

Press (1993). 

EPA promulgated regulations to 

address regional haze on April 22, 1999. 

64 FR 35765. Consistent with the 

statutory requirement in 42 U.S.C. 

7491(b)(2)(a), EPA’s 1999 regional haze 

regulations include a provision 

requiring States to require certain major 

stationary sources ‘‘in existence on 

August 7, 1977, but which ha[ve] not 

been in operation for more than fifteen 

years as of such date’’ which emit 

pollutants that are reasonably 

anticipated to cause or contribute to any 

visibility impairment to procure, install 

and operate BART. In determining 

BART, States are required to take into 

account five factors identified in the 

CAA and EPA’s regulations. 42 U.S.C. 

7491(g)(2) and 40 CFR 51.308. 

B. Statutory and Regulatory Framework 

for Addressing Sources Located in 

Indian Country 

When the Clean Air Act was amended 

in 1990, Congress included a new 

provision, Section 301(d), granting EPA 

authority to treat Tribes in the same 

manner as States where appropriate. See 

40 U.S.C. 7601(d). Congress also 

recognized, however, that such 

treatment may not be appropriate for all 

purposes of the Act and that in some 

circumstances, it may be inappropriate 

to treat tribes identically to states. 

Therefore, Section 301(d)(2) of the Act 

directed EPA to promulgate regulations 

‘‘specifying those provisions of [the 

CAA] for which it is appropriate to treat 

Indian tribes as States.’’ Id. 7601(d)(2). 

In addition, Congress provided that ‘‘[i]n 

any case in which [EPA] determines that 

the treatment of Indian tribes as 

identical to States is inappropriate or 

administratively infeasible, the 

Administrator may provide, by 

regulation, other means by which the 

Administrator will directly administer 

such provisions so as to achieve the 

appropriate purpose.’’ Id. 7601(d)(4). 

In 1998, EPA promulgated regulations 

at 40 CFR part 49 (which have been 

referred to as the Tribal Authority Rule 

or TAR) relating to implementation of 

CAA programs in Indian Country. See 

40 CFR part 49; see also 59 FR 43956 

(Aug. 25, 1994) (proposed rule); 63 FR 

7254 (Feb. 12, 1998) (final rule); Arizona 

Public Service Company v. EPA, 211 

F.3d 1280 (DC Cir. 2000), cert. den., 532 

U.S. 970 (2001) (upholding the TAR). 

The TAR allows EPA to treat eligible 

Indian Tribes in the same manner as 

States ‘‘with respect to all provisions of 

the [CAA] and implementing 

regulations, except for those provisions 

[listed] in 49.4 and the [EPA] 

regulations that implement those 

provisions.’’ 40 CFR 49.3. EPA 

recognized that Tribes were in the early 

stages of developing air planning 

programs known as Tribal 

Implementation Plans (TIPs) and that 

Tribes would need additional time to 

develop air quality programs. 62 FR 

7264–65. Thus, EPA determined that it 

was not appropriate to treat Tribes in 

the same manner as States for purposes 

of those provisions of the CAA imposing 

air program submittal deadlines. See 59 

FR at 43964–65; 63 FR at 7264–65. 

Similarly, EPA determined that it would 

be inappropriate to treat Tribes the same 

as States for purposes of the related 

CAA provisions establishing sanctions 

and federal oversight mechanisms 

where States fail to meet applicable air 

program submittal deadlines. Id. Thus, 

one of the CAA provisions that EPA 

determined was not appropriate to 

apply to Tribes is Section 110(c)(1). See 

40 CFR 49.4(d). In particular, EPA found 

that it was inappropriate to impose on 

Tribes the provisions in Section 

110(c)(1) for EPA to promulgate a FIP 

within 2 years after a State fails to make 

a required plan submission. 

Although EPA determined that the 

requirements of CAA section 110(c)(1) 

were not applicable to Tribes, EPA also 

determined that under other provisions 

of the CAA it has the discretionary 

authority to promulgate ‘‘such federal 

implementation plan provisions as are 

necessary or appropriate to protect air 

quality’’ when a Tribe has not submitted 

a TIP. 40 CFR 49.11. EPA determined in 

promulgating the TAR that it could 

exercise discretionary authority to 

promulgate FIPs based on Section 301(a) 

of the CAA, which authorizes EPA to 

prescribe such regulations as are 

necessary to carry out the Act, and 

Section 301(d)(4), which authorizes EPA 

to directly administer CAA provisions 

for which EPA has determined it is 

inappropriate or infeasible to treat 

Tribes as identical to States. 40 CFR 

49.11. See also 63 FR at 7265. 

Specifically, 40 CFR 49.11(a) provides 

that EPA shall promulgate without 

unreasonable delay such Federal 

implementation plan provisions as are 

necessary or appropriate to protect air 

quality, consistent with the provisions 

of sections 301(a) and 301(d)(4), if a 

tribe does not submit a tribal 

implementation plan or does not receive 

EPA approval of a submitted tribal 

implementation plan. 

EPA has previously promulgated FIPs 

under the TAR to regulate air pollutants 

emitted from the two coal fired electric 

generating facilities on the Navajo 


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Nation, FCPP and Navajo Generating 

Station (NGS). In 1991, EPA also revised 

an existing FIP that applied to Arizona 

to include a requirement for NGS to 

substantially reduce its SO2 emissions 

by installing scrubbers based on finding 

that the SO2 emissions were 

contributing to visibility impairment at 

the Grand Canyon National Park. 56 FR 

50172 (Oct. 3, 1991); see also Central 

Arizona Water Conservation District v. 

United States Environmental Protection 

Agency, 990 F.2d 1531 (9th Cir. 1993). 

In 1999, after several years of 

negotiations, EPA proposed concurrent 

but separate FIPs for FCPP and NGS. 

Those FIPs proposed to fill the 

regulatory gap that existed because 

permits and SIP rules by New Mexico 

(for FCPP) and Arizona (for NGS) were 

not applicable or enforceable on the 

Navajo Nation, and the Tribe had not 

sought approval of a TIP covering the 

plants. 64 FR 48731 (Sept. 8, 1999). 

Before EPA finalized the 1999 FIPs, 

the operator of FCPP began negotiations 

to reduce SO2 emissions from FCPP by 

making upgrades to improve the 

efficiency of its SO2 scrubbers. The 

negotiations resulted in an agreement 

for FCPP to increase the SO2 control 

from a 72% reduction of the potential 

SO2 emissions to an 88% reduction. As 

a result of this increased scrubber 

efficiency, FCPP’s SO2 emissions 

decreased by a total of 57% from the 

historical levels. The parties to the 

negotiations requested EPA to make 

those SO2 reductions enforceable 

through a source specific FIP. Therefore, 

EPA proposed new FIPs for FCPP and 

NGS in September 2006. 71 FR 53631 

(Sept. 12, 2006). In these concurrent but 

separate FIPs, EPA proposed to make 

emissions limits contained in State 

permits or rules that had previously 

been followed by FCPP and NGS 

federally enforceable. In addition, for 

FCPP, EPA proposed to establish a 

significantly lower SO2 emissions limit 

based on the increased scrubber 

efficiency, resulting in a reduction of 

approximately 22,000 tons of SO2 per 

year. EPA indicated in the final FIP for 

FCPP that the new SO2 emissions limits 

were close to or the equivalent of the 

emissions reductions that would have 

been required in a BART determination. 

72 FR 25698 (May 7, 2007). The FIP also 

required FCPP to comply with a 20% 

opacity limit on both the combustion 

and fugitive dust emissions coal 

handling operations. EPA finalized the 

FIP for FCPP in May 2007. Id. 

APS, the operator of FCPP, and the 

Sierra Club each filed Petitions seeking 

judicial review of EPA’s promulgation 

of the 2007 FIP for FCPP, on separate 

grounds. APS argued that EPA did not 

have authority to promulgate a sourcespecific FIP for FCPP without its 

consent. APS also argued that EPA did 

not have authority to promulgate a 20% 

opacity standard on the combustion 

equipment unless we provided an 

exemption for malfunctions. Finally, 

APS argued that EPA had not 

established an adequate basis for 

requiring a 20% opacity limit on the 

fugitive dust from the coal handling 

operations. In contrast, Sierra Club 

argued that EPA could not promulgate 

a ‘‘gap filling’’ FIP that did not include 

modeling and an analysis to show 

continued attainment of the NAAQS. 

The Court of Appeals for the Tenth 

Circuit rejected both Petitions. With 

respect to the Sierra Club’s arguments, 

the Court considered the regulatory 

language in 40 CFR 49.11(a) and 

concluded that ‘‘[t]his language does not 

impose upon the EPA the duty the 

Environmentalists propose. It provides 

the EPA discretion to determine what 

rulemaking is necessary or appropriate 

to protect air quality and requires the 

EPA to promulgate such rulemaking.’’ 

Arizona Public Service v. EPA, 562 F.3d 

1116, 1125 (10th Cir. 2009). The Court 

also rejected arguments by APS that 

EPA could not impose a continuous 

opacity limitation during operations, 

provided EPA set forth a reasonable 

basis for its decision. Id. at 1129 (‘‘That 

APS does not agree with the EPA’s 

rejection of the substance of its 

proposed 0.2% allowance is irrelevant; 

as long as EPA’s decision making 

process may reasonably be discerned, 

we will not set aside the federal plan on 

account of a less-than-ideal 

explanation.’’ [citation omitted]). The 

Court agreed with EPA’s request for a 

voluntary remand of the opacity limit 

for the fugitive dust for the material 

handling operations and remanded that 

narrow aspect of the 2007 FIP. Id. at 

1131. 

The FIP that EPA is proposing today 

is promulgated under the same 

authority in 40 CFR 49.11(a). EPA is 

proposing to find that it is necessary or 

appropriate to establish BART 

requirements for NOX and PM emissions 

from FCPP, and is proposing specific 

NOX and PM limits as BART. EPA is 

proposing to establish a 10% opacity 

limit from Units 1–5 to ensure 

continuous compliance with the PM 

emissions limit. EPA is also proposing 

a 20% opacity limit to apply to FCPP’s 

material handling operations in 

response to the remand from the 2007 

FIP. 

C. Statutory and Regulatory Framework 

for BART Determinations 

When Congress enacted Section 169A 

of the CAA to protect visibility, it 

directed EPA to promulgate regulations 

that, inter alia, would require applicable 

implementation plans to include a 

determination of BART for certain major 

stationary sources. 42 U.S.C. 

7491(b)(2)(A) & (g). These major 

stationary sources are fossil-fuel fired 

steam electric plants of more than 250 

MMBtu/hr heat input, kraft pulp mills, 

Portland cement plants and other listed 

industrial sources that came into 

operation between 1962 and 1977 and 

are ‘‘reasonably anticipated to cause or 

contribute to any impairment of 

visibility in any [Class I area].’’ Id. EPA 

guidelines must be followed in making 

BART determinations for fossil fuel 

fired electric generating plants larger 

than 750 MW. See 40 CFR Part 51, 

Appendix Y. 

FCPP and NGS are the only eligible 

BART sources located on the Navajo 

Nation. See Western Regional Air 

Partnership, http://www.wrapair.org/ 

forums/ssjf/bart.html, XLS Spreadsheet, 

Line 184, 185, Column N. An eligible 

BART source with a predicted impact of 

0.5 dv or more of impairment in a Class 

I area ‘‘contributes’’ to visibility 

impairment and is subject to BART. 70 

FR 39104, 39121 (July 6, 2005). FCPP 

contributes to impairment at many 

surrounding Class I areas well in excess 

of this threshold. 

EPA’s guidelines for evaluating BART 

for such sources are set forth in 

Appendix Y to 40 CFR Part 51. See also 

40 CFR 51.308(e)(1)(ii)(A). Consistent 

with statutory and regulatory 

requirements, the Guidelines require 

consideration of ‘‘five factors’’ in making 

BART determinations. Id. at IV.A. Those 

factors, from the Act’s statutory 

definition of BART, which are applied 

to all technically feasible control 

technologies, are: (1) The costs of 

compliance, (2) the energy and non-air 

quality environmental impacts of 

compliance, (3) any pollution control 

equipment in use or in existence at the 

source, (4) the remaining useful life of 

the source, and (5) the degree of 

improvement in visibility which may 

reasonably be anticipated to result from 

the use of such technology. 40 CFR 

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

In this proposed action, EPA has 

taken into consideration each of the five 

factors after identifying feasible control 

technologies for FCPP’s NOX and PM 

emissions. 


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1 ‘‘Clean Air Markets—Data and Maps: http:// 

camddataandmaps.epa.gov/gdm/. 

2 Guidance for Estimating Natural Visibility 

Conditions Under the Regional Haze Rule, U.S. 

Environmental Protection Agency’’, EPA–454/B–03– 

005, September 2003; http://www.epa.gov/ttn/ 

oarpg/t1pgm.html. 

3Clean Air Markets Division—Data—Maps. 

D. Factual Background 

1. Four Corners Power Plant 

FCPP is a privately owned and 

operated coal-fired power plant located 

on the Navajo Nation Indian Reservation 

near Farmington, New Mexico. Based on 

lease agreements signed in 1960, FCPP 

was constructed and has been operating 

on real property held in trust by the 

Federal government for the Navajo 

Nation. The facility consists of five coalfired electric utility steam generating 

units with a total capacity of 2060 

megawatts (MW). Units 1, 2, and 3 at 

FCPP are owned entirely by Arizona 

Public Service (APS), which serves as 

the facility operator, and are rated to 

170 MW (Units 1 and 2) and 220 MW 

(Unit 3). Units 4 and 5 are each rated to 

a capacity of 750 MW, and are co-owned 

by six entities: Southern California 

Edison (48%), APS (15%), Public 

Service Company of New Mexico (13%), 

Salt River Project (SRP) (10%), El Paso 

Electric Company (7%), and Tucson 

Electric Power (7%). 

Based on 2009 emissions data from 

the EPA Clean Air Markets Division,1

FCPP is the largest source of NOX

emissions in the United States (over 

40,000 tons per year (tpy) of NOX). 

FCPP, located near the Four Corners 

region of Arizona, New Mexico, Utah, 

and Colorado, is approximately 300 

kilometers (km) from sixteen mandatory 

Class I Federal areas: Arches National 

Park (NP), Bandelier National 

Monument (NM), Black Canyon of the 

Gunnison Wilderness Area (WA), 

Canyonlands NP, Capitol Reef NP, 

Grand Canyon NP, Great Sand Dunes 

NP, La Garita WA, Maroon BellsSnowmass WA, Mesa Verde NP, Pecos 

WA, Petrified Forest NP, San Pedro 

Parks WA, West Elk WA, Weminuche 

WA, and Wheeler Park WA. 

APS provided information relevant to 

a BART analysis to EPA on January 29, 

2008. The information consisted of a 

BART engineering and cost analysis 

conducted by Black and Veatch (B&V) 

dated December 4, 2007 (Revision 3), a 

BART visibility modeling protocol 

prepared by ENSR Corporation (now 

called AECOM and referred to as 

AECOM throughout this document) 

dated January 2008, a BART visibility 

modeling report prepared by AECOM 

dated January 2008, and a document 

titled APS BART Analysis conclusions, 

dated January 29, 2008. APS provided 

supplemental information on cost and 

visibility modeling in correspondence 

dated May 28, 2008, June 10, 2008, 

November 2008, March 16, 2009, 

October 29, 2009, and April 22, 2010. 

All of these documents are available in 

the docket for this proposal. 

2. Relationship of NOX and PM to 

Visibility Impairment 

Particulate matter less than 10 

microns (millionths of a meter) in size 

(PM10) interacts with light. The smallest 

particles in the 0.1 to 1 micron range 

interact most strongly as they are about 

the same size as the wavelengths of 

visible light. The effect of the 

interaction is to scatter light from its 

original path. Conversely, for a given 

line of sight, such as between a 

mountain scene and an observer, light 

from many different original paths is 

scattered into that line. The scattered 

light appears as whitish haze in the line 

of sight, obscuring the view. 

PM emitted directly into the 

atmosphere, also called primary PM, is 

emitted both from the boiler stacks and 

from material handling. Of primary PM 

emissions, those in the smaller particle 

size range, less than 2.5 microns, tend 

to have the most impact on visibility. 

PM emissions from the boiler stacks can 

have varying particle size makeup 

depending on the PM control 

technology. PM from material handling, 

though, tends to be coarse, i.e. around 

10 microns, since it is created from the 

breakup of larger particles of soil and 

rock. 

PM that is formed in the atmosphere 

from the condensation of gaseous 

chemical pollutants, also called 

secondary PM, tends to be fine, i.e. 

smaller than 1 micron, since it is formed 

from the buildup of individual 

molecules. This secondary PM tends to 

contribute more to visibility impairment 

than primary PM because it is in the 

size range where it most effectively 

interacts with visible light. NOX and 

SO2 emissions from coal fired power 

plants are two examples of gaseous 

chemical pollutants that react with 

other compounds in the atmosphere to 

form secondary PM. Specifically, NOX is 

a gaseous pollutant that can be oxidized 

to form nitric acid. In the atmosphere, 

nitric acid in the presence of ammonia 

forms particulate ammonium nitrate. 

The formation of particulate ammonium 

nitrate is dependent on temperature and 

relative humidity, and therefore, varies 

by season. Particulate ammonium 

nitrate can grow into the size range that 

effectively interacts with light by 

coagulating together and by taking on 

additional pollutants and water. The 

same principle applies to SO2 and the 

formation of particulate ammonium 

sulfate. 

In air quality models, secondary PM 

is tracked separately from primary PM 

because the amount of secondary PM 

formed depends on weather conditions 

and because it can be six times more 

effective at impairing visibility. This is 

reflected in the equation used to 

calculate visibility impacts from 

concentrations measured by the 

Interagency Monitoring of Protected 

Visual Environments (IMPROVE) 

monitoring network covering Class I 

areas.2

II. EPA’s Proposed Action on the Five 

Factor Test 

A. A BART Determination for FCPP Is 

Necessary or Appropriate 

The numerous Class I areas that 

surround FCPP are sometimes known as 

the Golden Circle of National Parks. See 

http://www.nps.gov/history/history/

online_books/nava/adhi/adhi4e.htm. 

Millions of tourists visit these areas, 

many visiting from other countries to 

view the unique vistas of the Class I 

areas in the Four Corners region. 

As Congress recognized, visibility is 

an important value and must be 

protected in these areas. Yet, air quality 

and visibility are impaired in the 16 

Class I areas surrounding FCPP. The 

National Park Service noted in 2008 that 

‘‘[v]isibility is impaired to some degree 

at all units where it is being measured 

and remains considerably higher than 

the target national conditions in many 

places, particularly on the haziest days.’’ 

Air Quality in National Parks, 2008 

Annual Performance & Progress Report, 

National Resource Report NPS/NRPC/ 

ARD/NRR–2009/151, September 2009, 

p. 30. Mesa Verde, Grand Canyon, Bryce 

Canyon and Canyonlands are among the 

areas the Park Service is monitoring. Id. 

Table 3, p. 19. Although not directly 

related to visibility, NOX is also a 

precursor to ozone formation and the 

National Park Service also determined 

that ozone concentrations in Mesa 

Verde appears to be trending upward 

over the 1994–2007 period and the 

Park’s annual 4th-highest 8-hour ozone 

concentrations ‘‘are approaching the 

[NAAQS] standard.’’ Id. at 16. FCPP, 

which emitted over 42,000 tons of NOX

in 2009,3 was built roughly four decades 

ago and has not installed any new NOX

controls since the 1990’s, including 

modern combustion technology such as 

post-2000 low-NOX burners (LNB) or 

separated overfire air. 

Based on the importance of visibility 

as a value in this Golden Circle of 


jlentini on DSKJ8SOYB1PROD with PROPOSALS
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4Presumptive limits for Unit 3 based on drybottom wall-fired boiler and Units 4 and 5 on cell 

burner boilers. Presumptive limits do not apply to 

Units 1 and 2 because they are smaller than 200 

MW. 

5From 2008–01_APS_4_Corners_BART_Analysis_

Conclusions.pdf. 

6From APS’s Comment Letter to EPA dated 

October 28, 2009. 

National Parks, and the substantial NOX

and PM emissions generated by 

operating FCPP, EPA is proposing to 

find that BART emission limits are 

necessary or appropriate. 

B. Summary of Proposed BART 

Emissions Limits 

On August 28, 2009, EPA published 

an Advanced Notice of Proposed 

Rulemaking (ANPRM) concerning two 

of the five factors in the BART analysis: 

Cost of compliance and anticipated 

visibility improvement. 74 FR 44314. 

EPA received numerous comments on 

the ANPRM, including comments from 

the Navajo Nation, APS, National Park 

Service and environmental groups. EPA 

has considered relevant comments we 

received on the ANPRM in determining 

which NOX and PM emission 

limitations we are proposing today as 

BART for FCPP. 

Based on the available control 

technologies and the five factors 

discussed in more detail below, EPA is 

proposing to require FCPP to meet a 

NOX emission limit on Units 1–5 of 0.11 

lb/MMBtu. EPA is proposing a PM 

emission limit on Units 1–3 of 0.012 lb/ 

MMBtu and on Units 4 and 5 of 0.015 

lb/MMBtu as BART. EPA is taking 

comment on an alternative PM 

emissions limit for Units 1–3 described 

in more detail in Section II.D. 

EPA is not proposing to require each 

unit to achieve the specified NOX

emission limit. EPA is proposing to 

require FCPP to meet a plant-wide heat 

input weighted 30-day rolling average 

emission limit of 0.11 lb/MMBtu for 

NOX for Units 1–5. For PM, we are 

proposing a BART emission limit of 

0.012 lb/MMBtu from Units 1–3 on a 6- 

hour average basis and 0.015 lb/MMBtu 

averaged over a 6-hour period for Units 

4 and 5, which should be achievable 

with proper operation of the existing 

baghouses. EPA is also proposing that 

Units 1–5 meet a 10% opacity limit 

which will reasonably assure 

continuous compliance with the PM 

emission limits. EPA is taking comment 

on an alternative PM emission limit for 

Units 1–3. 

The available control technologies 

and EPA’s evaluation of each of the five 

factors supporting our proposed BART 

emissions limits for NOX and PM are 

discussed in more detail below and in 

EPA’s accompanying Technical Support 

Document (TSD). 

C. Available and Feasible Control 

Technologies and Five Factor Analysis 

for NOX Emissions 

APS identified sixteen options as 

available retrofit technologies to control 

NOX. Generally, NOX control techniques 

use: (1) Combustion control to reduce 

the production of NOX from fuel-bound 

nitrogen and high temperature 

combustion; (2) post-combustion add-on 

control to reduce the amount of NOX

emitted in flue gas by converting NOX

to diatomic nitrogen (N2); or (3) a 

combination of combustion and postcombustion controls. EPA approached 

the five factor analysis using a top-down 

method. A top-down analysis entails 

ranking the control options in 

descending order starting with the most 

stringent option. The top control option 

is evaluated and if eliminated based on 

one of the five factors, the next most 

stringent option is considered, and so 

on. The top option for NOX control is a 

combination of a post-combustion addon control, i.e., selective catalytic 

reduction (SCR), and combustion 

controls, i.e., low-NOX burners plus 

overfire air (LNB + OFA). SCR without 

LNB + OFA represents the next most 

stringent option, and LNB + OFA 

without SCR represents a low-mid level 

of control. As described in detail below, 

EPA believes LNB + OFA are not likely 

to be effective control technologies at 

FCPP due to the inherent limitations of 

the existing boilers on all units. 

Therefore, EPA started our top-down 

analysis of the five factors with SCR 

without combustion controls. More 

details on the control options are 

provided in Section 2 of the TSD. 

As described in our ANPRM, APS has 

claimed that combustion controls (i.e., 

low-NOX burners (LNB) on Units 1 and 

2 and low NOX burners plus overfire air 

(LNB + OFA) on Units 3–5) would 

provide NOX reductions sufficient to 

meet the presumptive limits for NOX

identified in the BART Guidelines (40 

CFR Part 51 Appendix Y). Table 1 

shows the presumptive NOX limits for 

boilers burning either sub-bituminous or 

bituminous coal and the emission limits 

APS considers achievable for Units 1–5. 

APS submitted NOX emission limits it 

considers achievable to EPA in January 

2008, March 2009, and October 2009. 

The coal burned at FCPP has 

historically been classified as subbituminous. APS, however, in its BART 

analysis has claimed that the coal is 

bituminous. 

TABLE 1—PRESUMPTIVE NOX LIMITS4 AND NOX EMISSIONS (IN LB/MMBTU) FROM LNB (UNITS 1 AND 2) LNB + OFA 

(UNITS 3–5) CLAIMED ACHIEVABLE BY APS 

Bituminous coal Sub-Bituminous 

coal 

Emissions after 

LNB or 

LNB+OFA 

(Jan 2008 5) 

Emissions after 

LNB or 

LNB+OFA 

(Oct 2009 6) 

Unit 1 ............................................................................................... N/A N/A 0.48 0.40 

Unit 2 ............................................................................................... N/A N/A 0.48 0.40 

Unit 3 ............................................................................................... 0.39 0.23 0.39 0.32 

Unit 4 ............................................................................................... 0.40 0.45 0.40 0.35 

Unit 5 ............................................................................................... 0.40 0.45 0.40 0.35 

EPA, however, disagrees with APS’s 

contention that EPA should rely only on 

presumptive limits for BART for NOX

and with APS’s claim that LNB and LNB 

+ OFA will be effective at achieving 

NOX emissions lower than the 

presumptive BART emissions limits. 


jlentini on DSKJ8SOYB1PROD with PROPOSALS
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7 ‘‘Assessment of Potential for Further NOX

Reduction by Combustion-Based Control at the Four 

Corners Steam Electric Station’’, April 5, 2004. 

8EPA received the Andover Report only a few 

days prior to signature of the ANPRM. Therefore the 

report was not considered in the ANPRM or made 

available in the ANPRM docket. APS claimed the 

report Confidential Business Information (CBI) and 

on July 9, 2010, EPA’s Regional Counsel determined 

this report was not CBI. 

EPA’s presumptive BART limits were 

not intended to supplant a case-by-case 

BART determination. For NOX, for most 

types of boilers, EPA’s presumptive 

BART limits were intended to indicate 

what should generally be achievable 

with combustion modifications such as 

modern LNB with OFA for a given type 

of boiler firing either bituminous or subbituminous coal. In establishing the 

presumptions, EPA concluded that 

these controls were highly cost-effective 

at large power plants generally and that 

installation of such controls would 

result in meaningful visibility 

improvement at any 750 MW power 

plant. Thus, these controls are required 

at a minimum at these facilities unless 

there are source-specific circumstances 

that would justify a different 

conclusion. EPA did not consider the 

question of what more stringent control 

technologies might be appropriately 

determined to be BART, however, 

especially in the case where the 

visibility benefits may be substantial. A 

full case-by-case BART analysis is 

required for each facility. In this 

instance, given the fact that FCPP is the 

largest source of NOX emissions in the 

United States and that it is surrounded 

by 16 mandatory Class I areas, EPA 

considers it appropriate to carefully 

consider NOX emission limits based on 

a full analysis of the five BART factors. 

In this rulemaking, EPA is undertaking 

a complete BART analysis for the FCPP 

for the first time, an analysis that is 

specific to FCPP and that takes into 

consideration the five factors set forth in 

the CAA. 

Because EPA is relying on the fivefactor analysis and not the presumptive 

NOX levels in the BART guidelines, it is 

not necessary for EPA to make a 

determination on the classification of 

coal used by APS as bituminous or subbituminous. EPA is taking the coal 

characteristics into account in 

establishing the NOX BART emission 

limit, but the classification as 

bituminous or sub-bituminous is only 

relevant for choosing presumptive 

limits, which we are not doing in this 

proposal. Although the emissions level 

claimed by APS for LNB + OFA retrofit 

of Units 4 and 5 are below the 

presumptive limits for both subbituminous coal and bituminous coal, 

we note that the presumptive levels of 

0.40 and 0.45 lb/MMBtu provide little 

reduction of baseline NOX emissions 

(0.49 lb/MMBtu) from these units. 

In our ANPRM, EPA questioned the 

ability of LNB and LNB + OFA to result 

in the magnitude of NOX reductions 

being claimed as achievable by APS. 

APS has submitted two different reports 

concerning the potential for NOX

reductions at FCPP. The first report 

written by Andover Technology 

Partners 7 (Andover Report) was 

submitted by APS by letter dated 

August 7, 2009, prior to the publication 

of the ANPRM.8 The Andover Report 

outlined the considerable challenges 

associated with LNB and OFA retrofits 

on each unit, including boiler design 

and size, and FCPP coal characteristics. 

Although four different technology 

suppliers claimed they could achieve 

NOX reductions with burner retrofits, 

the Andover Report concluded that LNB 

retrofits were not likely to be beneficial 

for the boilers at FCPP because the risk 

of adverse operational side effects 

outweighed the potentially modest 

improvement in emissions performance. 

The fireboxes for Units 1, 2 and 3 are 

considered to be too small to effectively 

use modern approaches to low NOX

combustion, which require separated 

OFA. Unit 2 was retrofitted with a 1990- 

designed LNB and, according to APS, 

had considerable operational problems 

subsequent to this retrofit. Units 1 and 

2 are identical boilers. Thus due to 

operational difficulties following the 

Unit 2 retrofit, APS did not attempt a 

retrofit on Unit 1, which continues to 

emit NOX at a concentration as high as 

0.8 lb/MMBtu. 

Units 4 and 5 were originally 

designed and operated with cell 

burners. This type of combustion burner 

inherently creates more NOX than 

conventional wall-fired burners. 

Although the type of burners in the cell 

boilers were replaced in the 1980s, the 

design of a cell boiler limits the NOX

reduction that can be achieved with 

modern low NOX combustion 

techniques. EPA set different 

presumptive levels of 0.40 lb/MMBtu or 

0.45 lb/MMBtu for the expected 

achievable NOX reductions for cell 

burner boilers with combustion 

modifications due to this design 

limitation. Thus, the efficacy of LNB + 

OFA on Units 4 and 5 will also be 

limited by their inherent design. Even if 

retrofit of Units 4 and 5 results in some 

improvement in NOX performance 

(approaching 0.40 lb/MMBtu), the 

Andover Report did not recommend 

burner retrofits because potential 

operational problems on the two largest 

units at FCPP were not worth the small 

incremental reduction in NOX

emissions. 

A subsequent report prepared by APS 

and submitted to EPA as Attachment J 

of its October 28, 2009 comment letter 

on the ANPRM, indicated that Units 1 

and 2 could achieve 0.40 lb/MMBtu 

with LNB retrofit, Unit 3 could achieve 

0.32 lb/MMBtu and Units 4 and 5 could 

achieve 0.35 lb/MMBtu with a 

combination of LNB + OFA retrofit. See 

Table 1 above. APS cited examples of 

several boilers with LNB or LNB + OFA 

retrofits that achieve emission rates of 

0.4 lb/MMBtu or below. 

EPA Clean Air Markets Division 

(CAMD) evaluated the boiler examples 

from Attachment J to assess the 

emissions reductions that have been 

achieved with modern combustion 

modification retrofits. CAMD concluded 

that other boilers have achieved NOX

emissions of approximately 0.4 lb/ 

MMBtu, but could not determine if 

Units 3–5 at FCPP were indeed 

comparable to those boilers. APS did 

not provide enough information in 

Attachment J to assess the level of 

similarity. Based on information 

provided in the Andover Report and the 

EPA CAMD review of Attachment J 

provided by APS, EPA determined that 

combustion controls are not likely to be 

effective control technologies at FCPP 

due to the inherent limitations of the 

existing boilers on all units. Therefore, 

EPA rejected the top control option, 

SCR in combination with LNB + OFA, 

and focused our five factor analysis on 

the next most stringent technology, SCR 

without LNB + OFA, which can reduce 

NOX emissions by 80%. 

i. Factor 1: Cost of Compliance 

The cost effectiveness of controls is 

expressed in cost per ton of pollutant 

reduced ($/ton). 40 CFR Part 51, App. Y, 

IV.D.4.c. Cost effectiveness is calculated 

by first estimating the total capital and 

annual costs of the BART controls. The 

second step requires calculating the 

amounts of the pollutants which will be 

reduced by the control technology 

selected as BART. This second step 

compares the uncontrolled baseline 

emissions (i.e. emissions from current 

operations) to the proposed BART 

emissions limits. Id. 

APS submitted cost estimates for all 

feasible control options in January 2008 

and submitted revised cost estimates for 

SCR on March 16, 2009 to reflect higher 

costs of construction services and 

materials. In our August 28, 2009 

ANPRM, we presented APS’s cost 

estimates for emissions controls for 

NOX, which included the revised SCR 

costs submitted in March 2009, and cost 

estimates from the National Park Service 


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(NPS). In the ANPRM, EPA revised the 

annual operating cost estimates 

submitted by APS based on the ratio of 

annual to capital costs from other 

facilities in the western United States. 

NPS conducted an independent analysis 

strictly adhering to the EPA Control Cost 

Manual and calculated significantly 

lower cost effectiveness. In subsequent 

comments on the ANPRM, NPS 

submitted revised cost estimates for 

each unit. All of these cost estimates are 

described in detail in the TSD. 

Subsequent to the ANPRM, APS 

submitted revised cost estimates for the 

NOX control technologies. APS 

provided these revised cost estimates to 

EPA via electronic mail on April 22, 

2010, in a report dated February 10, 

2010. Costs estimated for Unit 1–3 were 

dated May 2008, whereas revised cost 

estimates were provided for Units 4 and 

5 were dated February 2010. All cost 

estimates in the 2010 submission were 

lower than those submitted previously. 

The report updated cost estimates for 

Units 4 and 5 in 2010 dollars and 

provided cost estimates for Units 1–3 in 

2008 dollars that are lower than the 

costs APS submitted in March 2009 

upon which the ANPRM relied. Because 

APS only recently withdrew a claim of 

confidentiality for the 2010 cost 

estimates, however, this proposal is 

based on the costs submitted in March 

2009. The TSD also contains a further 

discussion of these costs. 

For this NPR, EPA evaluated the 

capital and annual cost estimates APS 

submitted in March 2009 against the 

EPA Control Cost Manual. Although 

EPA has generally accepted the costs 

estimates APS submitted, we have 

eliminated any line item costs that are 

not explicitly included in the EPA 

Control Cost Manual and we have 

revised the costs where EPA determined 

alternate costs were more appropriate, 

e.g., cost of catalysts, or interest rates. 

Additional detailed information and the 

results of our revisions to the cost 

estimates are included in Table 13 of the 

TSD. EPA’s cost effectiveness estimates 

and those estimated by NPS and APS 

are shown in Table 2. 

TABLE 2—EPA, NPS, AND APS COST EFFECTIVENESS FOR SCR ON UNITS 1–5 

EPA Cost 

effectiveness 

($/ton) 

NPS Cost 

effectiveness 

($/ton) 

APS Cost 

effectiveness 

($/ton) 

Unit 1 ......................................................................................................................... $2,515 $1,326 $4,887 

Unit 2 ......................................................................................................................... 3,163 1,882 6,170 

Unit 3 ......................................................................................................................... 2,678 1,390 5,142 

Unit 4 ......................................................................................................................... 2,622 1,453 5,197 

Unit 5 ......................................................................................................................... 2,908 1,598 5,764 

EPA’s cost effectiveness calculations 

in this NPR are lower than we presented 

in the ANPRM. The estimates continue 

to be lower than those estimated by APS 

but higher than those estimated by NPS. 

The range of cost effectiveness that EPA 

has calculated and upon which this 

proposal is based, from $2,515–$3,163/ 

ton of NOX removed, is lower than or 

within the range of other BART 

evaluations. Some BART analyses for 

other electric generating facilities 

evaluated SCR with a range of costs: 

Pacificorps Jim Bridger Units 2–4: 

$2,256–$4,274/ton of NOX removed; 

Pacificorps Naughton Units 1–3: 

$2,751–$2,830/ton of NOX removed; 

PGE Boardman: $3,096/ton of NOX

removed; M.R. Young Units 1 and 2: 

$3,950–$4,250/ton of NOX removed; and 

Centralia Power Plant Units 1 and 2: 

$9,091/ton of NOX removed. San Juan 

Generating Station in Farmington, New 

Mexico, is a nearby coal fired power 

plant that was built shortly after FCPP 

and uses coal with almost identical 

characteristics. On June 21, 2010, the 

New Mexico Environmental Department 

proposed requiring SCR as BART for the 

four units at San Juan Generating 

Station based on cost-effectiveness 

calculations ranging from $5,946/ton 

NOX reduced to $7,398/ton NOX

reduced. 

EPA considers its revised costeffectiveness estimates of $2,515– 

$3,163/ton of NOX removed to be more 

accurate and representative of the actual 

cost of compliance. However, even if 

EPA had decided to accept APS’s worstcase cost estimates of $4,887–$6,170/ton 

of NOX removed, EPA considers that 

estimate to be cost effective for the 

purpose of proposing an 80% reduction 

in NOX, achievable by installing and 

operating SCR as BART at FCPP. 

ii. Factor 2: Energy and Non-Air Quality 

Impacts 

The Navajo Nation has expressed 

concerns that requiring additional 

controls at FCPP could result in lost 

Navajo employment and royalties if 

FCPP were to shut down or curtail 

operations. EPA has received no 

definitive information indicating that 

FCPP intends to shut down or curtail 

operations, but to assess the possibility 

that today’s proposed BART limits 

could have such an effect, EPA 

conducted an economic analysis that 

looked at the impact of requiring SCR 

on FCPP. 

Based on an economic analysis of the 

increase in electricity generation costs 

as a result of SCR compared to the 

estimated cost to purchase electricity on 

the wholesale market, FCPP is expected 

to remain competitive relative to the 

wholesale market, suggesting that the 

incremental cost increase for SCR alone 

should not force FCPP to shut down. 

This analysis estimates that the average 

cost of electricity generation over the 20 

year amortization period as a result of 

SCR implementation will increase by 

22%, or $0.00740/kWh. 

Retail electricity consumers, however, 

pay more than just the generation costs 

of power. Retail rates include the cost to 

transmit and distribute electricity as 

well as generate electricity. 

Additionally, for APS customers, for 

example, the generation cost increase on 

FCPP due to SCR would flow into a 

broader retail rate impact calculation 

based on the entire portfolio of APS 

generation assets and purchases power 

contracts, which include coal (of which 

FCPP is only a portion of APS’ total coal 

portfolio), natural gas, nuclear, and 

some renewables. For these reasons, 

EPA expects the potential rate increase 

to APS rate payers resulting from SCR 

on FCPP to be significantly lower than 

22%. This topic is discussed in more 

detail in the TSD. 

In addition to concerns about possible 

facility shut down, EPA received 

comments regarding potential impacts 

of increased transportation emissions 

associated with urea deliveries to FCPP 

for SCR and concerns of the affect of 

SCR on salability of fly ash. EPA 

conducted an analysis to evaluate any 

increase in health risks resulting from 

increased diesel truck traffic to and from 

FCPP and determined that the increase 

in cancer and non-cancer health risks 


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associated with transportation 

emissions in the most impacted census 

block in San Juan County, New Mexico, 

are well below background levels and 

will not result in a significant health 

risk. 

The Salt River Pima Maricopa Indian 

Community expressed concern about 

the impact of SCR on their Phoenix 

Cement Company fly ash business unit 

at FCPP. Ammonia adsorption (resulting 

from ammonia injection from SCR or 

selective noncatalytic reduction— 

SNCR) to fly ash is generally less 

desirable due to odor but does not 

impact the integrity of the use of fly ash 

in concrete. However, other NOX control 

technologies, including LNB, also have 

undesirable impacts on fly ash. LNBs 

increase the amount of unburned carbon 

in the fly ash, also known as Loss of 

Ignition (LOI), which does affect the 

integrity of the concrete. Commercialscale technologies exist to remove 

ammonia and LOI from fly ash. 

Therefore, EPA has determined that the 

impact of SCR on the fly ash at FCPP is 

smaller than the impact of LNB on the 

fly ash, and in both cases, the adverse 

effects can be mitigated. 

EPA concludes that the energy and 

non-air quality impacts of SCR do not 

warrant elimination of SCR as the top 

control option for NOX.

iii. Factor 3: Existing Controls at the 

Facility 

There are some existing controls at 

FCPP for NOX. APS has installed a 

variety of LNB on Units 2–5 although 

these controls are all about 20 years old 

and there have been significant 

advances in the technology for most 

EGU boilers. Unit 1 does not have any 

NOX controls. The controls that APS is 

operating at FCPP for NOX do not result 

in the magnitude of NOX emissions 

reduction that are consistent with BART 

and do not represent current control 

technologies. 

iv. Factor 4: Remaining Useful Life of 

Facility 

The remaining useful life of the 

facility can be relevant if the facility 

may shut down before the end of the 

amortization period used to annualize 

the costs of control for a technology. In 

its analysis, APS used an amortization 

period of 20 years, the standard 

amortization period recommended by 

EPA, and indicated that it anticipated 

that the remaining useful life of Units 

1–5 is at least 20 years. As it appears 

that the FCPP facility will continue to 

operate for at least 20 years, EPA agrees 

with the use of an amortization period 

of 20 years to estimate costs. 

v. Factor 5: Degree of Visibility 

Improvement 

The fifth factor to consider under 

EPA’s BART Guidelines is the degree of 

visibility improvement from the BART 

control options. See 59 FR at 39170. The 

BART guidelines recommend using the 

CALPUFF air quality dispersion model 

to estimate the visibility improvements 

of alternative control technologies at 

each Class I area, typically those within 

a 300 km radius of the source, and to 

compare these to each other and to the 

impact of the baseline (i.e., current) 

source configuration. APS included 

sixteen Class I Areas in its modeling 

analysis; fifteen are within 300 km of 

FCPP and one Class I area, Grand 

Canyon National Park, is just beyond 

300 km from FCPP. These areas are 

listed in Table 22 of the TSD. 

The BART guidelines recommend 

comparing visibility improvements 

between control options using the 98th 

percentile of 24-hour delta deciviews, 

which is roughly equivalent to the 

facility’s 8th highest visibility impact 

day. The ‘‘delta’’ refers to the difference 

between total deciview impact from the 

facility plus natural background, and 

deciviews of natural background alone, 

so ‘‘delta deciviews’’ is the estimate of 

the facility’s impact. Visibility is 

traditionally described in terms of 

visual range in kilometers or miles. 

However, the visual range scale does not 

correspond to how people perceive 

visibility because how a given increase 

in visual range is perceived depends on 

the starting visibility against which it is 

compared. Thus, an increase in visual 

range may be perceived to be a big 

improvement when starting visibility is 

poor, but a relatively small 

improvement when starting visibility is 

good. 

The ‘‘deciview’’ scale is designed to 

address this problem. It is linear with 

respect to perceived visibility changes 

over its entire range, and is analogous to 

the decibel scale for sound. This means 

that a given change in deciviews will be 

perceived as the same amount of 

visibility change regardless of the 

starting visibility. Lower deciview 

values represent better visibility and 

greater visual range, while increasing 

deciview values represent increasingly 

poor visibility. In the BART guidelines, 

EPA noted that a 1.0 deciview impact 

from a source is sufficient to ‘‘cause’’ 

visibility impairment and that a source 

with a 0.5 deciview impact must 

‘‘contribute’’ to visibility impairment. 

Generally, 0.5 deciviews is the amount 

of change that is just perceptible to a 

human observer. 

Under the BART guidelines, the 

improved visibility in deciviews from 

installing controls is determined by 

using the CALPUFF air quality model. 

CALPUFF, generally, simulates the 

transport and dispersion of FCPP 

emissions, and the conversion of SO2

emitted from FCPP to particulate sulfate 

and NOX to particulate nitrate, at a rate 

dependent on meteorological conditions 

and background ozone concentration. 

These concentrations are then converted 

to delta deciviews by the CALPOST 

post-processor. The CALPUFF model 

and CALPOST post-processing are 

explained in more detail in the TSD. 

The ‘‘delta deciviews’’ estimated by 

the modeling represents the facility’s 

impact on visibility at the Class I areas. 

Each modeled day and location in the 

Class I area will have an associated delta 

deciviews. For each day, the model 

finds the maximum visibility impact of 

all locations (i.e., receptors) in the Class 

I area. From among these daily values, 

the BART guidelines recommend use of 

the 98th percentile, which is roughly 

equivalent to the 8th highest day for a 

given year, for comparing the base case 

and the effects of various controls. The 

98th percentile is recommended rather 

than the maximum value to avoid 

undue influence from unusual 

meteorological conditions. 

Meteorological conditions are modeled 

using the CALMET model. 

APS conducted modeling for FCPP 

according to a modeling protocol 

submitted to EPA. See BART Visibility 

Modeling Protocol for the Arizona 

Public Service Four Corners Power 

Plant, ENSR Corporation, January 2008. 

APS’s modeling used the CALMET and 

CALPUFF versions recommended by 

EPA but in blending in meteorological 

station wind observations, APS used a 

lower radius of influence for stations. 

This change resulted in smoother wind 

fields. After initial input from the 

Federal Land Managers, EPA requested 

APS to change certain other CALMET 

option settings. These changes resulted 

in a more refined approach that is more 

consistent with approaches used in PSD 

permit application modeling. Further 

details about the CALPUFF and 

CALMET modeling are in the TSD, and 

the relevant CALMET settings are listed 

in Table 23. 

In addition to the different CALPUFF 

emission rates described above, EPA’s 

evaluation of anticipated visibility 

improvement used revised postprocessor settings from those originally 

used by APS. The USFS informed EPA 

that the ammonia background 

concentrations modeled by APS in 

January 2008 were lower than observed 


jlentini on DSKJ8SOYB1PROD with PROPOSALS
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9Letter from Rick Cables (Forest Service R2 

Regional Forester) and Corbin Newman (Forest 

Service R3 Regional Forester) to Deborah Jordan 

(EPA Region 9 Air Division Director) dated March 

17, 2009. 

10 Interagency Workgroup 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. 11Mark E. Sather et al., 2008. ‘‘Baseline ambient 

gaseous ammonia concentrations in the Four 

Corners area and eastern Oklahoma, USA’’. Journal 

of Environmental Monitoring, 2008, 10, 1319–1325, 

DOI: 10.1039/b807984f. 12U.S. Environmental Protection Agency, EPA– 

454/B–03–005, September 2003, on web page 

http://www.epa.gov/ttn/oarpg/t1pgm.html, with 

direct link http://www.epa.gov/ttn/oarpg/t1/

memoranda/rh_envcurhr_gd.pdf. 

13EPA did not average the 98th percentiles from 

each year as did APS, rather EPA used the 98th 

percentile from all three years taken together. This 

does not significantly affect the overall results. 

concentrations.9 The USFS 

recommended a method of backcalculating the ammonia background 

based on monitored values of sulfate 

and nitrate. EPA’s ANPRM provided 

results based on using the USFS’s backcalculation methodology. 

The visibility modeling supporting 

today’s proposal, however, uses a 

constant ammonia background of 1 ppb, 

which is the default value 

recommended for western areas. 

IWAQM Phase 2 document.10 The TSD 

contains supplemental modeling using 

back-calculated ammonia 

concentrations, a thorough discussion of 

the back-calculation methodology and 

the sensitivity results based on selecting 

different concentrations of background 

ammonia. 

The background values of ammonia 

are important because it is a precursor 

to particulate ammonium sulfate and 

ammonium nitrate, both of which 

degrade visibility. Ammonia is present 

in the air from both natural and 

anthropogenic sources. The latter may 

include livestock operations, fertilizer 

application associated with farming, 

and ammonia slip from the use of 

ammonia in SCR and SNCR 

technologies to control NOX emissions. 

Sensitivity of the model results to other 

ammonia assumptions are discussed in 

the TSD, and do not change the ranking 

of control options for evaluating 

visibility improvement, or the overall 

conclusions of the visibility analysis. 

In our modeling input for ammonia, 

EPA assumed that the remaining 

ammonia in the flue gas following SCR 

reacts to form ammonium sulfate or 

ammonium bisulfate before exiting the 

stack. This particulate ammonium is 

represented in the modeling as sulfate 

(SO4) emissions. Thus, EPA addressed 

ammonia solely as a background 

concentration. 

In the supplemental sensitivity 

analyses using different ammonia values 

described in the TSD, ammonia 

concentrations for Mesa Verde National 

Park were not based on the backcalculation method, but instead were 

derived from measured ammonia 

concentrations in the Four Corners area, 

as described in Sather et al., (2008).11

Monitored data were available within 

Mesa Verde NP, but because particulate 

formation happens within a pollutant 

plume as it travels, rather than 

instantaneously at the Class I area, EPA 

also examined data at locations outside 

Mesa Verde NP itself. Monitored 3-week 

average ammonia at the Substation site, 

some 30 miles south of Mesa Verde, 

were as high as 3.5 ppb, though 

generally levels were less than 1.5 ppb. 

Maximum values in Mesa Verde were 

0.6 ppb, whereas other sites’ maxima 

ranged from 1 to 3 ppb, but generally 

values were less than 2 ppb. EPA used 

values estimated from Figure 5 of Sather 

et al., (2008), in the mid-range of the 

various stations plotted. The results 

ranged from 1.0 ppb in winter to 1.5 ppb 

in summer. See TSD, Table 33. 

The BART determination guidelines 

recommend that visibility impacts 

should be estimated in deciviews 

relative to natural background 

conditions. CALPOST, a CALPUFF 

post-processor, uses background 

concentrations of various pollutants to 

calculate the natural background 

visibility impact. EPA used background 

concentrations from Table 2–1 of 

‘‘Guidance for Estimating Natural 

Visibility Conditions Under the 

Regional Haze Rule.’’ 12 Although the 

concentration for each pollutant is a 

single value for the year, this method 

allows for monthly variation in its 

visibility impact, which changes with 

relative humidity. The resulting 

deciviews differ by roughly 1% from 

those resulting from the method 

originally used by APS. 

To assess results from the CALPUFF 

model and post-processing steps, in 

addition to considering deciview 

changes directly, EPA used a leastsquares regression analysis of all 

visibility modeling output from the 

2001–2003 modeling period to 

determine the percent improvement in 

FCPP’s visibility impact (in delta 

deciviews) resulting from the 

application of control technologies 

compared to the FCPP’s baseline 

impacts. 

As outlined in the 1999 Regional Haze 

rule (64 FR 35725, July 1, 1999), a one 

deciview change in visibility is a small 

but noticeable change in visibility under 

most circumstances when viewing 

scenes in a Class I area. Table 3 presents 

the visibility impacts of the 98th 

percentile of daily maxima for each 

Class I area for each year, averaged over 

2001–2003.13 The modeled visibility 

improvement at all Class I areas exceeds 

0.5 deciviews and at most Class I areas 

exceeds 1 deciview. 

TABLE 3—EPA MODELING RESULTS—8TH HIGH DELTA dv IMPROVEMENT AND PERCENT CHANGE IN DELTA DECIVIEW

(dv) IMPACT FROM NOX CONTROLS COMPARED TO BASELINE IMPACTS FROM 2001–2003 USING 1 PPB AMMONIA

BACKGROUND SCENARIO

Class I area 

Distance to 

FCPP 

Baseline 

impact 

Improvement from LNB/LNB + 

OFA 

Improvement from SCR 

Kilometers 

(km) 

Delta 

dv 

Delta 

dv % Delta dv % 

Arches National Park ............................... 245 4.11 0.87 18 2.40 55 

Bandelier Wilderness Area ...................... 216 2.90 0.54 21 1.62 57 

Black Canyon of the Gunnison WA ......... 217 2.36 0.46 23 1.42 60 

Canyonlands NP ...................................... 214 5.24 0.79 16 2.81 51 

Capitol Reef NP ....................................... 283 3.23 0.77 18 1.87 52 

Grand Canyon NP ................................... 345 1.63 0.34 20 0.88 55 

Great Sand Dunes NM ............................ 279 1.16 0.31 25 0.67 62 

La Garita WA ........................................... 202 1.72 0.44 25 1.05 62 

Maroon Bells Snowmass WA .................. 294 1.04 0.27 26 0.64 63 


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TABLE 3—EPA MODELING RESULTS—8TH HIGH DELTA dv IMPROVEMENT AND PERCENT CHANGE IN DELTA DECIVIEW

(dv) IMPACT FROM NOX CONTROLS COMPARED TO BASELINE IMPACTS FROM 2001–2003 USING 1 PPB AMMONIA

BACKGROUND SCENARIO—Continued 

Class I area 

Distance to 

FCPP 

Baseline 

impact 

Improvement from LNB/LNB + 

OFA 

Improvement from SCR 

Kilometers 

(km) 

Delta 

dv 

Delta 

dv % Delta dv % 

Mesa Verde NP ....................................... 62 5.95 0.62 13 2.43 45 

Pecos WA ................................................ 258 2.16 0.52 23 1.15 58 

Petrified Forest NP .................................. 224 1.40 0.27 21 0.65 56 

San Pedro Parks WA ............................... 160 3.88 0.68 19 2.02 53 

Weminuche WA ....................................... 137 1.87 0.49 25 1.19 62 

West Elk WA ............................................ 245 2.76 0.65 23 1.70 60 

Wheeler Peak WA ................................... 265 1.53 0.37 24 0.84 59 

Total Delta dv or Average % 

Change in Delta dv ....................... ........................ 42.94 8.39 21 23.34 57 

Because installation and operation of 

SCR at FCPP to reduce NOX emissions 

by 80% will provide perceptible and 

significant visibility improvements at all 

of the surrounding Class I areas, and 

because LNB will result in much less 

visibility improvement than SCR, EPA 

is proposing to require FCPP to reduce 

NOX by 80% by meeting a plant-wide 

emissions limit of 0.11 lb/MMBtu, 

which is achievable with SCR. Our 

analysis also shows that the visibility 

improvement from the emissions 

reductions achieved with LNB are 

significantly lower. 

D. Available and Feasible Control 

Technologies and Five Factor Analysis 

for PM Emissions 

For PM, APS identified seven options 

as available retrofit technologies that 

would rely on post-combustion capture 

of the emissions. APS determined three 

options were technically feasible for PM 

control on Units 1–3: Wet electrostatic 

precipitators (ESPs), dry ESPs, and 

pulse jet fabric filters (PJFF or 

baghouses). These three control options 

were determined to all have similar 

levels of PM control of 99.9%. One 

control option, called the GE–MAX–9 

hybrid, which is an ESP using a fabric 

filter collection bag, is estimated to have 

a PM control efficiency of 99.999% and 

has been used in a demonstration 

project, but has not been demonstrated 

on larger units. Therefore, EPA 

considered the other top three options, 

wet and dry ESP and baghouses, for PM 

control at FCPP. 

APS has been operating venturi 

scrubbers on Units 1–3 at FCPP since 

the 1970s resulting in PM reductions as 

well as SO2 reductions. PM is controlled 

on Units 4 and 5 with baghouses. 

Venturi scrubbers have been used by 

large coal fired electric generating units 

(EGUs), but since promulgation of the 

New Source Performance Standards, 

have largely been replaced by more 

advanced technology that can achieve 

better PM reductions and provide better 

compliance assurance. Units 1–3 at 

FCPP are the last EGUs in Region 9 to 

continue to operate venturi scrubbers. 

The other EGUs in Region 9 have 

generally been retrofit with baghouses. 

In this NPR, EPA is proposing to 

require APS to upgrade its PM controls 

as described below to meet an emission 

limit of 0.012 lb/MMBtu and 10% 

opacity on Units 1–3, which is 

achievable either through installing 

baghouses or ESPs. Because of the high 

incremental cost of both options, 

however, EPA is also asking for 

comment on whether APS can satisfy 

BART by operating the existing venturi 

scrubbers to meet an emissions limit of 

0.03 lb/MMBtu with a 20% opacity 

limit to demonstrate continuous 

compliance. EPA is proposing to require 

APS to operate the existing baghouse for 

Units 4 and 5 to meet an emissions limit 

of 0.015 lb/MMBtu and 10% opacity. 

i. Factor 1: Cost of Compliance 

EPA is proposing to require APS to 

install ESPs (wet or dry) or PJFFs for 

Units 1–3 to comply with an emissions 

limit of 0.012 lb/MMBtu and a 10% 

opacity limit. For Units 4 and 5, APS 

would not need to install any controls 

in addition to the baghouses currently 

in place but would be required to 

operate the baghouses to meet an 

emission limit of 0.015 lb/MMBtu and 

a 10% opacity limit. 

The wet-membrane ESP is the lowest 

cost approach to meeting the proposed 

PM BART limit of 0.012 lb/MMBtu for 

Units 1–3, but a wet membrane ESP 

would result in a very high cost 

effectiveness value for incremental cost 

because the existing venturi scrubbers 

are removing much of the PM. In other 

words, any control device, such as an 

ESP, placed downstream of the venturi 

scrubbers will result in a high 

incremental cost because the 

denominator (tons removed) of the cost 

effectiveness calculation will be 

relatively small. 

Alternatively, APS could install 

baghouses on Units 1–3 at FCPP 

upstream of the venturi scrubbers. The 

baghouses would be the most likely 

choice for APS for PM control if APS 

also wants to achieve significant 

mercury (‘‘Hg’’) reduction from these 

units. Installing baghouses would make 

those controls the primary PM control 

device (i.e. the downstream venturi 

scrubbers would primarily control SO2

emissions) and the cost effectiveness for 

Units 1–3 would average less than $110 

per ton of PM removed. These costs are 

discussed further in Section 3 of the 

TSD. 

Baghouses have already been installed 

on the four other coal fired EGUs in 

Region 9 that had historically used 

venturi scrubbers for PM control, 

including the only other venturi 

scrubber owned and operated by APS at 

its Cholla Unit 1. NV Energy Reid 

Gardner offered to install baghouses at 

Units 1, 2, and 3 as extra injunctive 

relief in a settlement agreement. Those 

baghouses are installed and operating 

(despite the high incremental dollars 

per ton of PM removed) to allow the 

units to achieve continuous compliance 

with PM and opacity limits and to 

prepare for the upcoming utility MACT 

regulation of Hg. 

EPA considers installation of either 

ESPs (wet or dry) or baghouses as 

reasonable-cost technology capable of 

achieving the proposed BART emission 

limit of 0.012 lb/MMBu for Units 1–3. 

However, because of the high 

incremental costs associated with ESPs 

or baghouses, EPA is also asking for 


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comment on whether APS can satisfy 

BART by continuing to operate the 

venturi scrubbers on Units 1–3, 

demonstrating compliance with an 

emissions limit of 0.03 lb/MMBtu with 

a continuous opacity limit of 20%. 

EPA’s basis for establishing a PM 

emissions limit of 0.03 lb/MMBtu is 

consistency with NSPS Subpart Da, 

which has been the applicable 

emissions limit for any boiler placed 

into service after 1978. We believe that 

an emissions limit that has been in 

place for over 35 years should be 

achievable with the venturi scrubbers. 

We provide further discussion of this 

issue in Subsection D.3 below and the 

TSD. 

ii. Factor 2: Energy and Non-Air Quality 

Impacts 

EPA is not aware of any energy and 

non-air quality impacts associated with 

any of the technologies discussed above 

that would eliminate them from 

consideration as BART. 

iii. Factor 3: Existing Controls at the 

Facility 

Units 1–3 are controlled by venturi 

scrubbers, which also are used for SO2

control. These scrubbers operate at 

pressure drops less than 10 inches of 

water. Venturi scrubbers have not been 

installed for PM pollution control on 

any coal fired EGU in Region 9 since the 

early 1970s. Venturi scrubbers have not 

been in use since that time principally 

due to concerns over the ability of 

venturi scrubbers to continuously meet 

the 0.10 lb/MMBtu standard established 

by a New Source Performance Standard 

in 1971. See 40 CFR Part 60 Subpart D. 

Fossil fuel fired boiler standards for coal 

fired units were revised for units built 

after 1978 and the PM limit was lowered 

to 0.03 lb/MMBtu. See 40 CFR Part 60 

Subpart Da. Most current coal fired 

boilers now use baghouses which are 

capable of meeting PM limits of about 

0.01 to 0.012 lb/MMBtu. 

As mentioned earlier in the cost 

discussion, baghouses have already 

been installed on the four other coal 

fired EGUs in Region 9 that had 

historically used venturi scrubbers for 

PM control, including APS’s Cholla 

Unit 1. These baghouses were installed, 

despite the very high incremental 

dollars per ton of PM removed, to allow 

the companies to continue to operate 

the units in continuous compliance 

with their PM and opacity limits. 

EPA notes that Units 1–3 at FCPP 

were operated with a re-heat of the 

scrubber exhaust. This allows the use of 

Continuous Opacity Monitors (COMs) in 

their stacks and provides an ongoing 

measurement of the opacity compliance. 

EPA understands that these three units 

originally installed and operated a reheat system, but FCPP discontinued its 

use. EPA Region 9 is not aware of when 

APS discontinued using the re-heat 

system. The three venturi-equipped 

units, Units 1–3, do not have COMs or 

opacity limits, which are required on all 

other EGUs in Region 9 and likely all 

across the U.S. because SIPs, such as 

Arizona’s, generally include a 20% 

opacity standard. Opacity standards are 

a regulatory tool that allows agencies 

and the public to ensure continuing 

compliance for PM. 

Over the past several years the PM 

source testing for Units 1 and 2 have 

consistently complied with the PM limit 

of 0.03 lb/MMBtu by operating the 

venturi scrubbers. Unit 3 exceeded the 

limit in 2007 but after subsequent 

source tests averages an emission rate of 

below 0.03 lb/MMBtu. 

EPA is requesting comment on 

allowing APS to continue to operate the 

venturi scrubbers on Units 1–3 provided 

it can demonstrate compliance with an 

emissions limit of 0.03 lb/MMBtu (as 

required by the NSPS Subpart Da for all 

post 1978 units) and a continuous 

opacity limit of 20%. 

iv. Factor 4: Remaining Useful Life of 

Facility 

As with NOX, EPA is assuming that 

the remaining useful life of the facility 

is 20 years. 

v. Factor 5: Degree of Visibility 

Improvement 

The modeled visibility improvements 

resulting from additional PM control are 

relatively small. See Table 4. 

TABLE 4—EPA MODELING RESULTS—8TH HIGH DELTA dv IMPROVEMENT AND PERCENT CHANGE IN DELTA DECIVIEW

(dv) IMPACT FROM PM CONTROL COMPARED TO BASELINE IMPACTS FROM 2001–2003 USING 1 PPB AMMONIA

BACKGROUND SCENARIO

Class I area 

Distance to 

FCPP 

Baseline impact Improvement from PM control 

Kilometers 

(km) 

Delta dv Delta dv % 

Arches National Park ..................................................................... 245 4.11 0 .01 0 

Bandelier Wilderness Area ............................................................ 216 2.90 0 .01 0 

Black Canyon of the Gunnison WA ............................................... 217 2.36 0 0 

Canyonlands NP ............................................................................ 214 5.24 0 .02 0 

Capitol Reef NP ............................................................................. 283 3.23 0 .01 0 

Grand Canyon NP ......................................................................... 345 1.63 0 .01 0 

Great Sand Dunes NM .................................................................. 279 1.16 0 0 

La Garita WA ................................................................................. 202 1.72 0 0 

Maroon Bells Snowmass WA ........................................................ 294 1.04 0 0 

Mesa Verde NP ............................................................................. 62 5.95 0 .02 1 

Pecos WA ...................................................................................... 258 2.16 0 .01 0 

Petrified Forest NP ........................................................................ 224 1.40 0 .01 0 

San Pedro Parks WA .................................................................... 160 3.88 0 .02 1 

Weminuche WA ............................................................................. 137 1.87 0 0 

West Elk WA .................................................................................. 245 2.76 0 0 

Wheeler Peak WA ......................................................................... 265 1.53 0 .01 0 

Total Delta dv or Average % Change in Delta dv ......................... ............................ 42.94 0 .13 0 

However, this factor may be 

somewhat misleading because the 

model does not include consideration of 

the visibility impairing plume that is 

almost always present after the steam 

plume from Units 1–3 evaporates. The 


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term EPA uses for this plume is a 

‘‘secondary visible plume’’. This 

secondary visible plume often stretches 

for over 20 miles from FCPP and is most 

apparent in the early mornings when 

the typical inversions cap the dispersion 

of the secondary visible plume. EPA 

does not have any information as to 

whether this secondary visible plume 

can be seen from Mesa Verde National 

Park, the closest Class 1 area to FCPP. 

EPA Region 9 staff has observed this 

secondary visible plume in New Mexico 

out as far as Aztec and Bloomfield en 

route to Farmington from Albuquerque. 

Therefore, EPA is specifically seeking 

information on this secondary visible 

plume, its frequency and persistence, 

and whether or not it affects or can be 

observed from any Class 1 area. 

In the TSD, EPA discusses this 

secondary visible plume and whether it 

is related to the poor control of fine 

particulates by the venturi scrubbers. 

EPA is also seeking information as to 

whether this plume has been observed 

from Units 4 and 5. Although the 

modeled visibility improvements from 

requiring additional PM controls are 

small, EPA considers eliminating the 

secondary visible plume from Units 

1–3 to be important for visibility in the 

area. EPA is proposing to require APS 

to install either ESPs (wet or dry) or 

baghouses to meet an emissions limit of 

0.012 lb/MMBtu with a 10% opacity 

limit. EPA is also taking comment on 

whether BART can be satisfied by 

allowing APS to continue to operate its 

existing venturi scrubbers on Units 1–3 

to demonstrate compliance with an 

emissions limit of 0.03 lb/MMBtu with 

a 20% opacity limit. 

III. EPA Proposed Action on Material 

Handling Limits 

EPA is also proposing dust control 

requirements for FCPP. These 

requirements were included in the FIP 

that EPA finalized in 2007. APS 

appealed this portion of the 2007 FIP 

and EPA agreed to a voluntary remand 

of the dust control requirements to 

provide further justification in the 

record. 

FCPP receives approximately 

10 million tons of coal per year for 

combusting in the Units 1–5. This 

material moves by conveyor belt across 

the property line through numerous 

transfer points before being loaded to 

the storage silos that feed the individual 

Units. Each of these transfer points 

along with the conveyor belts has the 

potential for PM emissions. The PM can 

be minimized by collecting devices or 

dust suppression techniques such as 

covered conveyors or spraying devices 

at the transfer points. 

After combustion, FCPP has a very 

large amount of ash that needs to be 

handled properly to prevent PM 

emissions to the air. The coal APS 

combusts at FCPP has as much as 25% 

ash. This means that there are over a 

million tons of ash that must be 

properly transported within the plant 

and then disposed. Some of this ash is 

stored in ash silos and is sold to 

companies that use it as an additive for 

making concrete. Much of the ash is 

currently disposed at a relatively new 

onsite ash landfill. All of this ash, 

which has the potential to become 

airborne PM, must be properly handled 

to prevent PM10 NAAQS issues. 

FCPP’s property line abuts the coal 

mine property and the entire coal 

handling and fly ash storage is within 

close proximity to Morgan Lake which 

is a recreational lake just beyond the 

FCPP’s property line. EPA has received 

numerous complaints from Navajo 

Tribal members concerning excess dust 

generated from the new landfill. For 

these reasons, EPA considers it 

necessary or appropriate for dust/PM 

suppression measures to be enforceable 

to protect the ambient air quality. 

EPA is proposing to require APS to 

implement a dust control plan and a 

20% opacity standard for all material 

handling operations. The dust plan 

must provide measures to ensure that 

the coal handling, ash handling and 

disposal and general dust generating 

sources do not exceed 20% opacity. 

Dust control measures at coal fired 

power plants are important for 

maintaining the PM10 NAAQS in the 

areas adjacent to the power plant 

properties. Most coal fired power plants 

that are grandfathered from the NSPS 

Subpart Y (40 CFR part 60) and from 

Prevention of Significant Deterioration 

(PSD) case by case BACT 

determinations are covered by general 

SIP rules regulating emissions and have 

associated opacity standards to assure 

proper operation of dust control or 

suppression measures during the times 

when stack testing is not conducted. 

Grandfathered facilities usually were 

subject to process weight PM limits 

under SIPs. These limits used an 

exponential equation approach to 

setting the allowable lb/hr PM based on 

the amount of material processed per 

hour. The limits typically become more 

stringent as a ratio of the allowable 

emissions to the throughput as the 

amount of material throughput 

increases. The SIPs also apply a general 

opacity limit to these PM emitting units. 

Because FCPP is located on the 

Navajo Reservation where generally 

applicable limits that often are included 

in SIPs do not exist, and because dust 

control measures at coal fired power 

plants are important for maintaining the 

PM10 NAAQS in the areas adjacent to 

the power plant properties, EPA finds 

that it is necessary or appropriate to 

impose measures to limit the amount of 

PM emissions from these material 

handling emission sources. EPA 

recently imposed similar dust control 

requirements at the Navajo Generating 

Station which is also on the Navajo 

Nation Reservation. 

IV. Administrative Requirements 

A. Executive Order 12866: Regulatory 

Planning and Review 

This proposed action is not a 

‘‘significant regulatory action’’ under the 

terms of Executive Order (EO) 12866 (58 

FR 51735, October 4, 1993) because it is 

a proposed rule that applies to only one 

facility and is not a rule of general 

applicability. This proposed rule, 

therefore, is not subject to review under 

EO 12866. This action proposes a 

source-specific FIP for the Four Corners 

Power Plant on the Navajo Nation. 

B. Paperwork Reduction Act 

This proposed action does not impose 

an information collection burden under 

the provisions of the Paperwork 

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

Under the Paperwork Reduction Act, a 

‘‘collection of information’’ is defined as 

a requirement for ‘‘answers to * * * 

identical reporting or recordkeeping 

requirements imposed on ten or more 

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

Because the proposed FIP applies to a 

single facility, Four Corners Power 

Plant, the Paperwork Reduction Act 

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

Burden means the total time, effort, or 

financial resources expended by persons 

to generate, maintain, retain, or disclose 

or provide information to or for a 

Federal agency. This includes the time 

needed to review instructions; develop, 

acquire, install, and utilize technology 

and systems for the purposes of 

collecting, validating, and verifying 

information, processing and 

maintaining information, and disclosing 

and providing information; adjust the 

existing ways to comply with any 

previously applicable instructions and 

requirements; train personnel to be able 

to respond to a collection of 

information; search data sources; 

complete and review the collection of 

information; and transmit or otherwise 

disclose the information. 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 


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14 ‘‘Representatives of State and local 

governments’’ include non-elected officials of State 

and local governments and any representative 

national organizations not listed in footnote 3. 

numbers for EPA’s regulations in 40 

CFR are listed in 40 CFR Part 9. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of today’s proposed rule on small 

entities, small entity is defined as: (1) A 

small business as defined by the Small 

Business Administration’s (SBA) 

regulations at 13 CFR 121.201; (2) a 

small governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

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

a small organization that is any not-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of this proposed action on small 

entities, I certify that this proposed 

action will not have a significant 

economic impact on a substantial 

number of small entities. The FIP for 

Four Corners Power Plant being 

proposed today does not impose any 

new requirements on small entities. See 

Mid-Tex Electric Cooperative, Inc. v. 

FERC, 773 F.2d 327 (DC Cir. 1985). 

D. Unfunded Mandates Reform Act 

(UMRA) 

This proposed rule, if finalized, will 

impose an enforceable duty on the 

private sector owners of FCPP. 

However, this rule does not contain a 

Federal mandate that may result in 

expenditures of $100 million (in 1996 

dollars) or more for State, local, and 

tribal governments, in the aggregate, or 

the private sector in any one year. EPA’s 

estimate for the total annual cost to 

install and operate SCR on all five units 

at FCPP and the cost to install and 

operate new PM controls on Units 1–3 

does not exceed $100 million (in 1996 

dollars) in any one year. Thus, this rule 

is not subject to the requirements of 

sections 202 or 205 of UMRA. This 

proposed action is also not subject to 

the requirements of section 203 of 

UMRA because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. This 

rule will not impose direct compliance 

costs on the Navajo Nation, and will not 

preempt Navajo law. This proposed 

action will, if finalized, reduce the 

emissions of two pollutants from a 

single source, the Four Corners Power 

Plant. 

E. Executive Order 13132: Federalism 

Under section 6(b) of Executive Order 

13132, EPA may not issue an action that 

has federalism implications, that 

imposes substantial direct compliance 

costs on State or local governments, and 

that is not required by statute, unless 

the Federal government provides the 

funds necessary to pay the direct 

compliance costs incurred by State and 

local governments, or EPA consults with 

State and local officials early in the 

process of developing the proposed 

action. In addition, under section 6(c) of 

Executive Order 13132, EPA may not 

issue an action that has federalism 

implications and that preempts State 

law, unless the Agency consults with 

State and local officials early in the 

process of developing the proposed 

action. 

EPA has concluded that this proposed 

action, if finalized, may have federalism 

implications because it makes calls for 

emissions reductions of two pollutants 

from a specific source on the Navajo 

Nation. However, the proposed rule, if 

finalized, will not impose substantial 

direct compliance costs on the Tribal 

government, and will not preempt 

Tribal law. Thus, the requirements of 

sections 6(b) and 6(c) of the Executive 

Order do not apply to this action. 

Consistent with EPA policy, EPA 

nonetheless consulted with 

representatives of Tribal governments 14

early in the process of developing the 

proposed action to permit them to have 

meaningful and timely input into its 

development. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

Executive Order 13175, entitled 

‘‘Consultation and Coordination with 

Indian Tribal Governments’’ (65 FR 

67249, Nov. 9, 2000), requires EPA to 

develop ‘‘an accountable process to 

ensure meaningful and timely input by 

tribal officials in the development of 

regulatory policies that have tribal 

implications.’’ Under Executive Order 

13175, to the extent practicable and 

permitted by law, EPA may not issue a 

regulation that has tribal implications, 

that imposes substantial direct 

compliance costs on Indian tribal 

governments, and that is not required by 

statute, unless the Federal government 

provides the funds necessary to pay 

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. In addition, to the extent 

practicable and permitted by law, EPA 

may not issue a regulation that has tribal 

implications and pre-empts tribal law 

unless EPA consults with tribal officials 

early in the process of developing the 

proposed regulation and prepares a 

tribal summary impact statement. 

EPA has concluded that this proposed 

rule, if finalized, may have tribal 

implications because it will require 

emissions reductions of two pollutants 

by a major stationary source located and 

operating on the Navajo reservation. 

However, this proposed rule, if 

finalized, will neither impose 

substantial direct compliance costs on 

tribal governments nor pre-empt Tribal 

law because the proposed FIP imposes 

obligations only on the owners or 

operator of the Four Corners Power 

Plant. 

EPA has consulted with officials of 

the Navajo Nation in the process of 

developing this proposed FIP. EPA had 

an in-person meeting with Tribal 

representatives prior to the proposal and 

will continue to consult with Tribal 

officials during the public comment 

period on the proposed FIP. In addition, 

EPA provided Navajo Nation and other 

tribal governments additional time to 

submit formal comments on our 

Advanced Notice of Proposed 

Rulemaking. Several tribes, including 

the Navajo, submitted comments which 

EPA considered in developing this NPR. 

Therefore, EPA has allowed the Navajo 

Nation to provide meaningful and 

timely input into the development of 

this proposed rule and will continue to 

consult with the Navajo Nation and 

other affected Tribes prior to finalizing 

our BART determination. 

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 

EPA has reason to believe may have a 

disproportionate effect on children. If 

the regulatory action meets both criteria, 

the Agency must evaluate the 

environmental health or safety effects of 

the planned rule on children, and 


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64234 Federal Register / Vol. 75, No. 201 / Tuesday, October 19, 2010 / Proposed Rules 

explain why the planned regulation is 

preferable to other potentially effective 

and reasonably feasible alternatives 

considered by the Agency. 

This proposed rule is not subject to 

Executive Order 13045 because it 

requires emissions reductions of two 

pollutants from a single stationary 

source. Because this proposed action 

only applies to a single source and is 

not a proposed rule of general 

applicability, it is not economically 

significant as defined under Executive 

Order 12866, and does not have a 

disproportionate effect on children. 

However, to the extent that the rule will 

reduce emissions of PM and NOX, 

which contributes to ozone formation, 

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. 

Consistent with the NTTAA, the 

Agency conducted a search to identify 

potentially applicable VCS. For the 

measurements listed below, there are a 

number of VCS that appear to have 

possible use in lieu of the EPA test 

methods and performance specifications 

(40 CFR Part 60, Appendices A and B) 

noted next to the measurement 

requirements. It would not be practical 

to specify these standards in the current 

proposed rulemaking due to a lack of 

sufficient data on equivalency and 

validation and because some are still 

under development. However, EPA’s 

Office of Air Quality Planning and 

Standards is in the process of reviewing 

all available VCS for incorporation by 

reference into the test methods and 

performance specifications of 40 CFR 

Part 60, Appendices A and B. Any VCS 

so incorporated in a specified test 

method or performance specification 

would then be available for use in 

determining the emissions from this 

facility. This will be an ongoing process 

designed to incorporate suitable VCS as 

they become available. EPA is 

requesting comment on other 

appropriate VCS for measuring opacity 

or emissions of PM and NOX. 

Particulate Matter Emissions—EPA 

Methods 1 though 5. 

Opacity—EPA Method 9 and 

Performance Specification Test 1 for 

Opacity Monitoring. 

NOX Emissions—Continuous 

Emissions Monitors. 

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. 

EPA has determined that this 

proposed rule, if finalized, will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority or low-income populations 

because it increases the level of 

environmental protection for all affected 

populations without having any 

disproportionately high and adverse 

human health or environmental effects 

on any population, including any 

minority or low-income population. 

This proposed rule requires emissions 

reductions of two pollutants from a 

single stationary source, Four Corners 

Power Plant. 

List of Subjects in 40 CFR Part 49 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Indians, 

Intergovernmental relations, Reporting 

and recordkeeping requirements. 

Dated: October 6, 2010. 

Jared Blumenfeld, 

Regional Administrator, Region IX. 

Title 40, chapter I of the Code of 

Federal Regulations is proposed to be 

amended as follows: 

PART 49—[AMENDED] 

1. The authority citation for part 49 

continues to read as follows: 

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

2. Section 49.23 is amended by 

adding paragraphs (i) and (j) to read as 

follows: 

§ 49.23 Federal Implementation Plan 

Provisions for Four Corners Power Plant, 

Navajo Nation. 

* * * * * 

(i) Regional Haze Best Available 

Retrofit Technology limits for this plant 

are in addition to the requirements in 

paragraphs (a) through (h) of this 

section. All definitions and testing and 

monitoring methods of this section 

apply to the limits in paragraph (i) of 

this section except as indicated in 

paragraphs (i)(1) through (4) of this 

section. Within 180 days of the effective 

date of this paragraph (i), the owner or 

operator shall submit a plan to the 

Regional Administrator that identifies 

the control equipment and schedule for 

complying with this paragraph (i). The 

owner or operator shall amend and 

submit this amended plan to the 

Regional Administrator as changes 

occur. The interim limits for each unit 

shall be effective 180 days after re-start 

of the unit after installation of SCR 

controls for that unit and until the 

plant-wide limit goes into effect. The 

plant-wide NOX limit shall be effective 

no later than 5 years after the effective 

date of this rule. APS may elect to meet 

the plant-wide limit early to remove the 

individual unit limits. Particulate limits 

for Units 1, 2, and 3 shall be effective 

180 days after re-start of the units after 

installation of the PM controls but no 

later than 5 years after the effective date 

of this paragraph (i). Particulate limits 

for Units 4 and 5 shall be effective 180 

days after re-start of the units after 

installation of the SCR controls. 

(1) Particulate Matter for units 1, 2, 

and 3 shall be limited to 0.012 lb/ 

MMBtu for each unit as measured by the 

average of 3 test runs with each run 

collecting a minimum of 60 dscf of 

sample gas and with a duration of at 

least 120 minutes. Sampling shall be 

performed according to 40 CFR Part 60 

Appendices A–1 through A–3, Methods 

1 through 4 and Method 5 or Method 5e. 

The averaging time for any other 

demonstration of the Particulate Matter 

compliance or exceedence shall be 


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Federal Register / Vol. 75, No. 201 / Tuesday, October 19, 2010 / Proposed Rules 64235 

based on a 6 hour average. Particulate 

testing shall be performed annually as 

required by paragraph (e)(3) of this 

section. This test with 2 hour test runs 

may be substituted and used to 

demonstrate compliance with the 

particulate limits in paragraph (d)(2) of 

this section. 

(2) Particulate Matter from units 4 and 

5 shall be limited to 0.015 lb/MMbtu for 

each unit as measured by the average of 

3 test runs with each run collecting a 

minimum of 60 dscf of sample gas and 

with a duration of at least 120 minutes. 

Sampling shall be performed according 

to 40 CFR Part 60 Appendices A–1 

through A–3, Methods 1 through 4 and 

Method 5 or Method 5e. The averaging 

time for any other demonstration of the 

particulate matter compliance or 

exceedence shall be based on a 6 hour 

average. 

(3) No owner or operator shall 

discharge or cause the discharge of 

emissions from the stacks of Units 1, 2, 

3, 4 or 5 into the atmosphere exhibiting 

greater than 10% opacity, excluding 

uncombined water droplets, averaged 

over any six (6) minute period. 

(4) Plantwide nitrogen oxide emission 

limits. 

(i) The plantwide nitrogen oxide 

limit, expressed as nitrogen dioxide, 

shall be 0.11 lb/MMbtu as averaged over 

a rolling 30 calendar day period. NO2

emissions for each calendar day shall be 

determined by summing the hourly 

emissions measured in pounds of NO2

for all operating units. Heat input for 

each calendar day shall be determined 

by adding together all hourly heat 

inputs, in millions of BTU, for all 

operating units. Each day the thirty day 

rolling average shall be determined by 

adding together that day and the 

preceding 29 days pounds of NO2 and 

dividing that total pounds of NO2 by the 

sum of the heat input during the same 

30 day period. The results shall be the 

30 day rolling pound per million BTU 

emissions of NOX. 

(ii) The interim NOX limit for each 

individual boiler with SCR control shall 

be as follows: 

(A) Unit 1 shall meet a rolling 30 

calendar day NOX limit of 0.21 lb/ 

MMBtu, 

(B) Unit 2 shall meet a rolling 30 

calendar day limit of 0.17 lb/MMBtu, 

(C) Unit 3 shall meet a rolling 30 

calendar day limit of 0.16 lb/MMBtu, 

(D) Units 4 and 5 shall meet a rolling 

30 calendar day limit of 0.11 lb/MMBtu, 

each. 

(iii) Testing and monitoring shall use 

the 40 CFR part 75 monitors and meet 

the 40 CFR part 75 quality assurance 

requirements. In addition to these 40 

CFR part 75 requirements, relative 

accuracy test audits shall be performed 

for both the NO2 pounds per hour 

measurement and the heat input 

measurement. These shall have relative 

accuracies of less than 20%. This testing 

shall be evaluated each time the 40 CFR 

part 75 monitors undergo relative 

accuracy testing. 

(iv) If a valid NOX pounds per hour 

or heat input is not available for any 

hour for a unit, that heat input and NOX

pounds per hour shall not be used in the 

calculation of the 30 day plant wide 

rolling average. 

(v) Upon the effective date of the 

plantwide NOX average, the owner or 

operator shall have installed CEMS and 

COMS software that complies with the 

requirements of this section. 

(j) Dust. Each owner or operator shall 

operate and maintain the existing dust 

suppression methods for controlling 

dust from the coal handling and ash 

handling and storage facilities. Within 

ninety (90) days after promulgation of 

this paragraph (j), the owner or operator 

shall develop a dust control plan and 

submit the plan to the Regional 

Administrator. The owner or operator 

shall comply with the plan once the 

plan is submitted to the Regional 

Administrator. The owner or operator 

shall amend the plan as requested or 

needed. The plan shall include a 

description of the dust suppression 

methods for controlling dust from the 

coal handling and storage facilities, ash 

handling, storage and landfilling, and 

road sweeping activities. Within 18 

months of promulgation of this 

paragraph (j) each owner or operator 

shall not emit dust with opacity greater 

than 20 percent from any crusher, 

grinding mill, screening operation, belt 

conveyor, or truck loading or unloading 

operation. 

[FR Doc. 2010–26262 Filed 10–18–10; 8:45 am] 

BILLING CODE 6560–50–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R06–OAR–2005–TX–0031; FRL–9215– 

1] 

Approval and Promulgation of Air 

Quality Implementation Plans; Texas; 

Revisions to Rules and Regulations for 

Control of Air Pollution; Permitting of 

Grandfathered and Electing Electric 

Generating Facilities 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: The EPA is proposing to 

partially approve and partially 

disapprove revisions of the Texas State 

Implementation Plan (SIP) submitted by 

the Texas Commission on 

Environmental Quality (TCEQ, or 

Commission) on January 3, 2000, and 

July 31, 2002, as supplemented on 

August 5, 2009. These revisions are to 

regulations of the TCEQ which relate to 

application and permitting procedures 

for grandfathered electric generating 

facilities (EGFs). The revisions address 

a mandate by the Texas Legislature 

under Senate Bill 7 to achieve nitrogen 

oxide (NOX), sulfur dioxide (SO2) and 

particulate matter (PM) emission 

reductions from grandfathered EGFs. 

These emissions reductions will 

contribute to achieving attainment and 

help ensure attainment and continued 

maintenance of the National Ambient 

Air Quality Standards (NAAQS) for 

ozone, sulfur dioxide, and particulate 

matter in the State of Texas. As a result 

of these mandated emissions reductions, 

in accordance with section 110(l) of the 

Federal Clean Air Act, as amended (the 

Act, or CAA), partial approval of these 

revisions will not interfere with 

attainment of the NAAQS, reasonable 

further progress, or any other applicable 

requirement of the Act. EPA is 

proposing that the revisions, but for a 

severable provision, meet section 110, 

part C, and part D of the Federal Clean 

Air Act (the Act or CAA) and EPA’s 

regulations. Therefore, EPA is proposing 

to approve the revisions but for a 

severable portion that allows collateral 

emissions increases of carbon monoxide 

(CO) created by the imposition of 

technology controls to be permitted 

under the State’s Standard Permit (SP) 

for Pollution Control Projects (PCP). 

EPA is proposing to disapprove this 

severable portion concerning the 

issuance of a PCP SP for the CO 

collateral emissions increases. EPA is 

taking comments on this proposal and 

plans to follow with a final action. 

DATES: Written comments must be 

received on or before November 18, 

2010. 

ADDRESSES: Submit your comments, 

identified by Docket No. R06–OAR– 

2005–TX–0031, by one of the following 

methods: 

• Federal eRulemaking Portal: http:// 

www.regulations.gov. 

• Follow the on-line instructions for 

submitting comments. 

• U.S. EPA Region 6 ‘‘Contact Us’’ 

Web site: http://epa.gov/region6/ 

r6comment.htm. Please click on ‘‘6PD 

(Multimedia)’’ and select ‘‘Air’’ before 

submitting comments. 


jlentini on DSKJ8SOYB1PROD with PROPOSALS