Federal Register / Vol. 74, No. 166 / Friday, August 28, 2009 / Proposed Rules 44313 

Monday through Friday, except Federal 

holidays. The Docket Office (telephone 

(800) 647–5527) is located at the street 

address stated in the ADDRESSES section. 

Comments will be available in the AD 

docket shortly after receipt. 

List of Subjects in 14 CFR Part 39 

Air transportation, Aircraft, Aviation 

safety, Incorporation by reference, 

Safety. 

The Proposed Amendment 

Accordingly, under the authority 

delegated to me by the Administrator, 

the FAA proposes to amend 14 CFR part 

39 as follows: 

PART 39—AIRWORTHINESS 

DIRECTIVES 

1. The authority citation for part 39 

continues to read as follows: 

Authority: 49 U.S.C. 106(g), 40113, 44701. 

§ 39.13 [Amended] 

2. The FAA amends § 39.13 by 

removing Airworthiness Directive (AD) 

91–18–19, Amendment 39–8022 (56 FR 

42224, August 24, 1991), and adding the 

following new AD: 

Hawker Beechcraft Corporation (Type 

Certificate Numbers 3A15, 3A16, and 

A23CE formerly held by Raytheon 

Aircraft Company; formerly held by 

Beech Aircraft Corporation):Docket No. 

FAA–2009–0797; Directorate Identifier 

2009–CE–032–AD. 

Comments Due Date 

(a) We must receive comments on this 

airworthiness directive (AD) action by 

October 27, 2009. 

Affected ADs 

(b) This AD supersedes AD 91–18–19, 

Amendment 39–8022. 

Applicability 

(c) This AD applies to the following 

airplane models and serial numbers that are 

certificated in any category: 

(1) Group 1 Airplanes (retains the actions 

and applicability from AD 91–18–19): 

Model Serial Nos. (SNs) 

58, 58A ............... TH–733 through TH– 

1609. 

58P, 58PA .......... TJ–3 through TJ–497. 

58TC, 58TCA ..... TK–1 through TK–151. 

95–B55, 95– 

B55A.

TC–1947 through TC– 

2456. 

A36 ..................... E–825 through E–2578. 

B36TC ................ EA–242 and EA–273 

through EA–509. 

Model Serial Nos. (SNs) 

E55, E55A .......... TE–1078 through TE– 

1201. 

F33A ................... CE–634 through CE– 

1536. 

V35B .................. D–9862 through D– 

10403. 

(2) Group 2 Airplanes (aligns certain SNs 

applicability to Models A36TC airplanes): 

Model SNs 

A36TC ................ EA–1 through EA–241 

and EA–243 through 

EA–272. 

Unsafe Condition 

(d) This AD results from reports of 

incorrect washers installed in the pilot and 

copilot shoulder harnesses on certain Beech 

33, 35, 36, 55, 58, and 95 series airplanes. We 

are issuing this AD to detect and correct an 

incorrect washer installed in the pilot and 

copilot shoulder harnesses. This failure 

could result in a malfunctioning shoulder 

harness. Such a failure could lead to 

occupant injury. 

Compliance 

(e) To address this problem, you must do 

the following, unless already done: 

Actions Compliance Procedures 

(1) Inspect the washers on the ‘‘D’’ ring of the 

pilot and copilot shoulder harnesses for correct metal, inner and outer diameter, and 

thickness.

(i) For Group 1 Airplanes: Within the next 100 

hours time-in-service (TIS) after October 

21, 1991 (the effective date of AD 91–18– 

19).

(ii) For Group 2 Airplanes: Within the next 100 

hours TIS after the effective date of this AD.

Follow Beechcraft Mandatory Service Bulletin 

No. 2394, dated December 1990. 

(2) If you find, as a result of the inspection required by paragraph (e)(1) of this AD, any 

washer does not meet the criteria for correct 

metal, inner and outer diameter, and thickness, replace the incorrect washer with part 

number 100951X060YA washer.

Before further flight, after the inspection required by paragraph (e)(1) of this AD.Follow Beechcraft Mandatory Service Bulletin 

No. 2394, dated December 1990. 

Alternative Methods of Compliance 

(AMOCs) 

(f) The Manager, Wichita Aircraft 

Certification Office (ACO), FAA, has the 

authority to approve AMOCs for this AD, if 

requested using the procedures found in 14 

CFR 39.19. Send information to ATTN: Steve 

Potter, Aerospace Engineer, ACE–118W, 

Wichita Aircraft Certification Office (ACO), 

1801 Airport Road, Room 100, Wichita, 

Kansas 67209; telephone: (316) 946–4124; 

fax: (316) 946–4107. Before using any 

approved AMOC on any airplane to which 

the AMOC applies, notify your appropriate 

principal inspector (PI) in the FAA Flight 

Standards District Office (FSDO), or lacking 

a PI, your local FSDO. 

(g) In reviewing the docket and project 

files, we found no AMOCs submitted for AD 

91–18–19. Since there are no AMOCs 

approved for AD 91–18–19 to approve for 

this AD, transfer of AMOCs to this AD does 

not apply. 

Related Information 

(h) To get copies of the service information 

referenced in this AD, contact Hawker 

Beechcraft Corporation, P.O. Box 85, Wichita, 

Kansas 67201–0085; telephone: (800) 429– 

5372 or (316) 676–3140; Internet: http:// 

pubs.hawkerbeechcraft.com. To view the AD 

docket, go to U.S. Department of 

Transportation, Docket Operations, M–30, 

West Building Ground Floor, Room W12– 

140, 1200 New Jersey Avenue, SE., 

Washington, DC 20590, or on the Internet at 

http://www.regulations.gov. 

Issued in Kansas City, Missouri, on 

August 20, 2009. 

Kim Smith, 

Manager, Small Airplane Directorate, Aircraft 

Certification Service. 

[FR Doc. E9–20832 Filed 8–27–09; 8:45 am] 

BILLING CODE 4910–13–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 49 

[EPA–R09–OAR–2009–0598; FRL–8950–6] 

Assessment of Anticipated Visibility 

Improvements at Surrounding Class I 

Areas and Cost Effectiveness of Best 

Available Retrofit Technology for Four 

Corners Power Plant and Navajo 

Generating Station: Advanced Notice 

of Proposed Rulemaking 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Advanced Notice of Proposed 

Rulemaking. 

SUMMARY: The Environmental Protection 

Agency is providing an Advanced 

Notice of Proposed Rulemaking (ANPR) 


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concerning the anticipated visibility 

improvements and the cost effectiveness 

for different levels of air pollution 

controls as Best Available Retrofit 

Technology (BART) for two coal-fired 

power plants, Four Corners Power Plant 

(FCPP) and Navajo Generating Station 

(NGS), located on the Navajo Nation. 

This ANPR briefly describes the 

provisions in Part C, Subpart II of the 

Clean Air Act (CAA or Act), EPA’s 

implementing regulations, and the 

Tribal Authority Rule (TAR) for 

promulgating Federal Implementation 

Plans (FIPs) to protect visibility in 

national parks and wilderness areas 

known as Class I Federal areas. 

The specific purpose of this ANPR is 

for EPA to collect additional 

information that we may consider in 

modeling the degree of anticipated 

visibility improvements in the Class I 

areas surrounding FCPP and NGS and 

for determining whether BART controls 

are cost effective at this time. EPA is 

also requesting any additional 

information that any person believes the 

agency should consider in promulgating 

a FIP establishing BART for FCPP and 

NGS. 

EPA intends to publish separate FIPs 

proposing our BART determinations for 

FCPP and NGS approximately 60 days 

after receiving information from this 

ANPR. EPA will not respond to 

comments or information submitted in 

response to this ANPR. The information 

submitted in response to this ANPR will 

be used in developing the subsequent 

proposed FIPs containing our detailed 

BART determinations for FCPP and 

NGS. 

The FCPP and NGS FIP proposals 

following this ANPR will request further 

public comment. During the public 

comment period for the proposed FIPs 

containing the FCPP and NGS BART 

determinations, EPA intends to hold 

separate public hearings at locations to 

be determined near each facility. 

EPA will not hold a public hearing for 

this ANPR. This ANPR also serves to 

begin EPA’s 60-day consultation period 

with the Federal Land Managers (FLMs) 

within the Departments of Interior and 

Agriculture. Information necessary to 

initiate consultation is contained in this 

ANPR and supporting documentation 

included in the docket for this ANPR. 

EPA will address any matters raised by 

the FLMs in this 60-day consultation 

period when we propose the BART FIPs 

for FCPP and NGS. 

DATES: Comments on this ANPR must be 

submitted no later than September 28, 

2009. 

ADDRESSES: Submit comments, 

identified by docket number EPA–R09– 

OAR–2009–0598, by one of the 

following methods: 

1. Federal eRulemaking Portal: 

www.regulations.gov. Follow the on-line 

instructions. 

2. E-mail: lee.anita@epa.gov. 

3. Mail or delivery: 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 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 

www.regulations.gov or e-mail. 

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 e-mail 

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. 

Docket: The index to the docket for 

this action is available electronically at 

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, lee.anita@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 on Tribal 

Lands 

C. Statutory and Regulatory Framework for 

BART Determinations 

D. EPA’s Intended Action Subsequent to 

ANPRM 

E. Factual Background 

1. Four Corners Power Plant 

2. Navajo Generating Station 

3. Relationship of NOX and PM to 

Visibility Impairment 

II. Request for Public Comment 

A. Factor 1: Cost of Compliance 

1. FCPP 

a. Estimated Cost of Controls 

b. Cost Effectiveness of Controls 

2. NGS 

a. Estimated Cost of Controls 

b. Cost Effectiveness of Controls 

B. Factor 5: Degree of Visibility 

Improvement 

1. FCPP 

a. Visibility Modeling Scenarios 

b. EPA Modifications to Emission Rate 

Inputs 

c. Ammonia Background 

d. Natural Background 

e. Visibility Modeling Results 

2. NGS 

a. Visibility Modeling Scenarios 

b. EPA Modifications to Emission Rate 

Inputs 

c. Ammonia Background and Natural 

Background 

d. Visibility Modeling Results 

C. Factor 2: Energy and Non-Air Quality 

Impacts 

1. FCPP 

2. NGS 

D. Factor 3: Existing Controls at the 

Facility 

1. FCPP 

2. NGS 

E. Factor 4: Remaining Useful Life of 

Facility 

1. FCPP 

2. NGS 

III. Statutory and Executive Order Reviews 

I. Background 

A. Statutory and Regulatory Framework 

for Addressing Visibility 

Part C, Subsection 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 man-made 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 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, including for example: Grand 

Canyon National Park in Arizona (40 


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1 ‘‘Protecting Visibility in National Parks and 

Wilderness Areas’’, Committee on Haze in National 

Parks and Wilderness Areas, National Research 

Council, National Academy Press (1993). 

2 ‘‘Clean Air Markets—Data and Maps’’ at 

http://camddataandmaps.epa.gov/gdm/. 

CFR 81.403); Mesa Verde National Park 

and La Garita Wilderness Area in 

Colorado (Id. 81.406); Bandolier 

Wilderness Area in New Mexico (Id. 

81.421); and Arches, Bryce Canyon, 

Canyonlands and Capitol Reef National 

Parks in Utah (Id. 81.430). All of these 

mandatory Class I Federal areas and 

many others are within a 300-km radius 

of either FCPP or NGS. 

On December 2, 1980, EPA 

promulgated what it described as the 

first phase of the required visibility 

regulations, codified at 40 CFR 51.300– 

51.307 (45 FR 80084). The 1980 

regulations deferred regulating regional 

haze from multiple sources finding that 

the scientific data was inadequate at 

that time. Id. at 80086. 

Congress added Section 169B to the 

Act in the 1990 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 1

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.’’ 

EPA first promulgated regulations to 

address regional haze on April 22, 1999. 

64 FR 35765 (April 22, 1999). EPA’s 

1999 regional haze regulations included 

a provision requiring States to review 

BART-eligible sources for potentially 

mandating further air pollution controls. 

Congress defined BART-eligible sources 

as ‘‘each major station stationary source 

which is in existence on August 7, 1977, 

but which has not been in operation for 

more than fifteen years as of such date’’ 

which emits pollutants that are 

reasonably anticipated to cause or 

contribute to visibility impairment. 42 

U.S.C. 7479(b)(2)(A). 

EPA’s 1999 regulations followed the 

five factor approach set forth in the 

statutory definition of BART. However, 

the regulations treated the fifth factor, 

the degree of visibility improvement, on 

an area-wide rather than source specific 

basis. 64 FR 35741. The Court remanded 

the 1999 regulations to EPA on that 

issue. American Corn Growers Assoc. v. 

EPA, 291 F.3d 1 (DC Cir. 2002). EPA 

promulgated revisions to the regulations 

in June 2003, which were remanded on 

narrow grounds not relevant to this 

action. Center for Energy and Economic 

Development v. EPA, 398 F.3d 653 (DC 

Cir. 2005). Finally, EPA revised regional 

haze regulations in March 2005, which 

were upheld by the Court of Appeals for 

the District of Columbia Circuit. Utility 

Air Regulatory Group v. EPA, 471 F.3d 

1333 (DC Cir. 2006). 

B. Statutory and Regulatory Framework 

for Addressing Sources Located on 

Tribal Lands 

The 1990 Amendments included 

Section 301(d)(4) of the Act directing 

EPA to promulgate regulations for 

controlling air pollution on Tribal lands. 

EPA promulgated regulations to 

implement this Congressional directive, 

known as the Tribal Authority Rule 

(TAR), in 1998. 63 FR 7264 (1998) 

codifed at 40 CFR 49.1–49.11. See 

generally Arizona Public Service v. EPA, 

211 F.3d 1280 (DC Cir. 2000). 

Section 49.11 of the TAR authorizes 

EPA to promulgate a FIP when EPA 

determines such regulations are 

‘‘necessary or appropriate’’ to protect air 

quality. 40 CFR 49.11(a). Pursuant to the 

authority in the TAR, EPA promulgated 

a source specific FIP for FCPP 2006. The 

Court of Appeals for the Tenth Circuit 

considered the regulatory language in 40 

CFR 49.11(a) and concluded that ‘‘[i]t 

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 (10th Cir. 2009). 

C. Statutory and Regulatory Framework 

for BART Determinations 

FCPP and NGS are the only BART 

eligible sources located on the Navajo 

Nation. EPA’s guidelines for evaluating 

BART are set forth in Appendix Y to 40 

CFR Part 51. The Guidelines include a 

‘‘five factor’’ analysis for BART 

determinations. Id. at IV.A. Those 

factors, from the definition of BART, 

are: (1) 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). 

D. EPA’s Intended Action Subsequent to 

the ANPR 

After receiving information from this 

ANPR, EPA intends to propose separate 

FIPs for FCPP and NGS containing our 

determination of what level of control 

technology is BART for each power 

plant. EPA has determined it has 

authority to promulgate these FIPs 

under CAA Section 301(d)(4), 40 CFR 

Part 49.11, and 40 CFR 51.308(e). Any 

person may submit information 

concerning EPA’s authority during the 

30 day comment period for this ANPR. 

As discussed more fully below, EPA 

is specifically seeking information in 

this ANPR on two of the listed 

considerations in the five factor test: (1) 

The data inputs to model the degree of 

improvement in visibility which may 

reasonably be anticipated from different 

levels of air pollution controls as BART 

and (2) the costs of compliance of those 

potential BART controls. We anticipate 

that those two factors will generate the 

most comments on our subsequent 

proposed BART FIPs for FCPP and NGS. 

Information on the other three factors in 

the five factor test may also be 

submitted in response to this ANPR. 

E. 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 2006 emissions data from 

the EPA Clean Air Markets Division,2

FCPP is the largest source of NOX

emissions in the United States (nearly 

45,000 tons per year (tpy) of NOX). 

FCPP, located near the Four Corners 

region of Arizona, New Mexico, Utah, 

and Colorado, is within 300 kilometers 

(km) of sixteen mandatory Class I areas: 

Arches National Park (NP), Bandolier 

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 


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3 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. 

4PM emissions from Units 4 and 5 at FCPP are 

already controlled by baghouses. 

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 will be referred to as 

AECOM throughout this document) 

dated January 2008, a BART visibility 

modeling report prepared by AECOM 

dated January 2008, and 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, and March 16, 2009. 

2. Navajo Generating Station 

NGS is a coal-fired power plant 

located on the Navajo Nation Indian 

Reservation, just east of Page, Arizona, 

approximately 135 miles north of 

Flagstaff, Arizona. The facility is coowned by six different entities: U.S. 

Bureau of Reclamation (24.3%), SRP, 

which also acts as the facility operator 

(21.7%), Los Angeles Department of 

Water and Power (21.2%), APS (14%), 

Nevada Power Company (11.3%), and 

Tucson Electric Power (7.5%). 

Based on 2006 emissions data from 

the EPA Clean Air Markets Division, 

NGS is the fourth largest source of NOX

emissions in the United States (nearly 

35,000 tpy). NGS, in northern Arizona, 

is located within 300 km of eleven Class 

I areas: Arches NP, Bryce Canyon NP, 

Canyonlands NP, Capitol Reef NP, 

Grand Canyon NP, Mazatzal WA, Mesa 

Verde NP, Petrified Forest NP, Pine 

Mountain WA, Sycamore Canyon WA, 

and Zion NP. 

SRP submitted to EPA a BART 

modeling protocol prepared by AECOM 

dated September 2007, and a BART 

Analysis, conducted by AECOM, dated 

November 2007. SRP provided 

supplemental information regarding 

cost on July 29, 2008, a revised BART 

Analysis, dated December 2008, and 

additional information regarding 

modeling and emission control rates on 

June 3, 2009. 

3. Relationship of NOX and PM to 

Visibility Impairment 

Particulate matter (PM) less than 10 

microns (millionths of a meter) in size 

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, for 

example from materials handling, 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 they are formed from the 

buildup of individual molecules. Thus, 

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 ammonia are two 

examples of precursors to secondary 

PM. 

NOX is a gaseous pollutant that can be 

oxidized to form nitric acid. In the 

atmosphere, nitric acid in the presence 

of ammonia can form particulate 

ammonium nitrate. The formation of 

ammonium nitrate is also dependent on 

temperature and relative humidity. 

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 impact from 

concentrations measured by the 

Interagency Monitoring of Protected 

Visual Environments (IMPROVE) 

monitoring network covering Class I 

areas.3

II. Request for Public Comment 

A. Factor 1: Cost of Compliance 

1. FCPP 

a. Estimated Cost of Controls 

APS, through its contractor B&V, 

evaluated the BART cost of compliance 

analysis using the EPA Coal Utility 

Environmental Cost (CUECost) program, 

information supplied by equipment 

vendors, estimates from previous 

projects, and projected costs from FCPP. 

The cost estimates provided by APS 

(updated in the March 16, 2009 

submission to EPA) are included in 

Table 1 for four different levels of 

control technology to reduce NOX and 

in Table 2 for four different levels of 

control options to reduce PM on Units 

1–3. The NOX control technology 

options in Table 1 are: (1) Low NOX

Burners (LNB) on Units 1 and 2 and 

LNB plus overfire air (OFA) on Units 3– 

5; (2) selective catalytic reduction (SCR) 

on all units (units 1–5); (3) SCR plus 

LNB on all units (Units 1–5); and (4) 

SCR plus LNB + OFA on all units (units 

1–5). The PM control options for Units 

1–3 4 are: (1) Electrostatic precipitators 

(ESP) upstream of current air quality 

control equipment, i.e., venturi 

scrubbers; (2) pulse jet fabric filter 

(baghouse) upstream of current air 

quality control equipment; (3) wet metal 

ESP downstream of venturi scrubber, 

and (4) wet membrane ESP downstream 

of venturi scrubber. 

TABLE 1—FCPP COSTS OF COMPLIANCE FOR NOX BASED ON APS’S ANALYSIS

LNB/LNB + OFA5 SCR SCR + LNB SCR + LNB + OFA 

Total Capital Investment 

Unit 1 ... $4,109,000 $110,664,000 $111,609,000 $112,058,000 

Unit 2 ... 4,109,000 119,010,000 121,066,000 121,496,000 

Unit 3 ... 4,701,000 113,084,000 115,420,000 114,851,000 

Unit 4 ... 15,260,000 265,406,000 273,892,000 279,444,000 


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5Capital and annual cost values are for LNB on 

Units 1 and 2, and LNB + OFA on Units 3–5. 6Upstream refers to a location before the existing 

venturi scrubbers. 

7This estimate was reported by APS in their 

December 2007 analysis. EPA believes this value 

was reported by APS in error because it is unlikely 

a wet ESP would equal the cost of a baghouse for 

Unit 3, but not Units 1 and 2. 

TABLE 1—FCPP COSTS OF COMPLIANCE FOR NOX BASED ON APS’S ANALYSIS—Continued 

LNB/LNB + OFA5 SCR SCR + LNB SCR + LNB + OFA 

Unit 5 ... 15,260,000 265,406,000 273,892,000 279,444,000 

Total Annual Costs 

Unit 1 ... $922,000 $22,297,000 $21,764,000 $21,685,000 

Unit 2 ... 922,000 23,634,000 23,468,000 23,385,000 

Unit 3 ... 1,055,000 23,173,000 23,010,000 22,729,000 

Unit 4 ... 3,447,000 55,755,000 56,883,000 57,237,000 

Unit 5 ... 3,447,000 55,755,000 56,883,000 57,237,000 

TABLE 2—FCPP COSTS OF COMPLIANCE FOR PM BASED ON APS’S ANALYSIS

Upstream 6 ESP Upstream baghouse Wet metal ESP Wet membrane ESP 

Total Capital Investment 

Unit 1 ... $37,236,000 $50,515,000 $32,136,000 $23,360,000 

Unit 2 ... 45,702,000 60,992,000 32,879,000 23,901,000 

Unit 3 ... 40,135,000 59,594,000 59,594,000 7 26,988,000 

Total Annual Costs 

Unit 1 ... $10,169,000 $13,950,000 $8,781,000 $5,652,000 

Unit 2 ... 11,011,000 14,481,000 8,972,000 6,658,000 

Unit 3 ... 10,925,000 16,559,000 10,309,000 7,557,000 

b. Cost Effectiveness of Controls 

To determine the cost effectiveness of 

controls, typically expressed in cost per 

ton of pollutant reduced ($/ton), 

estimating the amount of NOX and PM 

that will be reduced from the various 

control options is necessary. The 

estimated reduction of the pollutant is 

determined by establishing the baseline 

emissions and the degree of emissions 

reduction from the control technology. 

40 CFR Part 51, App. Y, Step 4, c. 

APS estimated NOX emissions 

reductions by starting with baseline 

emission rates of NOX of: 0.78 pounds 

of NOX per million BTU heat input (lb/ 

MMBtu) for Unit 1; 0.64 lb/MMBtu for 

Unit 2; 0.59 lb/MMBtu for Unit 3; and 

0.49 lb/MMBtu from Units 4 and 5 each. 

For the four control technology options, 

APS estimated FCPP could achieve the 

following emissions reductions: (1) LNB 

on Units 1 and 2 would reduce NOX

45% and 33%, respectively and 

LNB + OFA on Units 3, and 4–5 would 

reduce NOX 44% and 29%, respectively; 

(2) SCR on Units 1–5 would reduce NOX

approximately 88–91%; (3) SCR + LNB 

on Units 1–5 would reduce NOX by 88– 

93%; and (4) SCR + LNB + OFA on Units 

1–5 would reduce NOX by 

approximately 88—93%. 

APS estimated PM emissions 

reductions using baseline emission rates 

of PM of: 0.025 lb/MMBtu for Unit 1; 

0.029 lb/MMBtu for Unit 2; and 0.029 

lb/MMBtu for Unit 3. APS estimated 

that the four different PM control 

options would all achieve 52% control 

on Unit 1 and 59% control on Units 2 

and 3. 

Table 3 lists the reduction in NOX

emissions and cost effectiveness 

estimated by APS for the four control 

technology options listed in Table 1. 

Table 4 provides the corresponding 

estimates for PM. 

TABLE 3—FCPP EMISSIONS REDUCTIONS AND COST EFFECTIVENESS FOR NOX

LNB/LNB + OFA8 SCR SCR + LNB SCR + LNB + OFA 

Tons of NOX Reduced per Year (tpy) 

Unit 1 ... 2,569 5,138 5,285 5,285 

Unit 2 ... 1,573 4,344 4,344 4,344 

Unit 3 ... 2,465 5,025 5,025 5,023 

Unit 4 ... 3,798 11,665 11,665 11,665 

Unit 5 ... 3,798 11,665 11,665 11,665 

Cost Effectiveness of Controls ($/ton) 

Unit 1 ... 359 4,343 4,118 4,103 

Unit 2 ... 586 5,484 5,403 5,384 

Unit 3 ... 428 4,582 4,579 4,523 


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8Capital and annual cost values are for LNB on 

Units 1 and 2, and LNB + OFA on Units 3–5. 

TABLE 3—FCPP EMISSIONS REDUCTIONS AND COST EFFECTIVENESS FOR NOX—Continued 

LNB/LNB + OFA8 SCR SCR + LNB SCR + LNB + OFA 

Unit 4 ... 908 4,872 4,780 4,907 

Unit 5 ... 908 4,872 4,780 4,907 

TABLE 4—FCPP EMISSIONS REDUCTIONS AND COST EFFECTIVENESS FOR PM 

Upstream ESP Upstream baghouse Wet metal 

ESP Wet membrane ESP 

Tons of PM Reduced per Year (tpy) 

Unit 1 ... 95 95 95 95 

Unit 2 ... 127 127 127 127 

Unit 3 ... 161 161 161 161 

Cost Effectiveness of Controls ($/ton) 

Unit 1 ... 106,571 146,195 92,024 59,233 

Unit 2 ... 86,485 113,739 70,470 52,294 

Unit 3 ... 67,785 102,741 63,963 46,888 

EPA’s regulations recommend using 

the EPA’s Office of Air Quality Planning 

and Standards’ Air Pollution Cost 

Control Manual (Sixth Edition, January 

2002) for estimating costs of 

compliance. 40 CFR Part 51, App. Y, 

Step 4.a.4. The Air Pollution Cost 

Control Manual provides guidance and 

methodologies for developing accurate 

and consistent estimates of cost for air 

pollution control devices. The costs that 

may be estimated include capital costs, 

operation and maintenance expenses, 

and other annual costs. Chapter 2 (Cost 

Estimation: Concepts and Methodology) 

states that total capital costs may 

include equipment costs, freight, sales 

tax, and installation costs. For existing 

facilities, retrofit costs should also be 

considered, and may include auxiliary 

equipment, handling and erection, 

piping, insulation, painting, site 

preparation, off-site facilities, 

engineering, and lost production 

revenue. Finally, annual costs are 

estimated from costs of raw materials, 

maintenance labor and materials, 

utilities, waste treatment and disposal, 

replacement materials, overhead, 

property taxes, insurance, and 

administrative charges. 

For the estimated costs that FCPP 

submitted, in Tables 1 & 2 above, APS 

provided line-item estimates for the 

direct and indirect capital costs, as well 

as direct and indirect annual costs. 

APS’s estimate, however, included 

several costs that are not included in the 

EPA Air Pollution Cost Control Manual, 

including costs of unintended 

consequences, such as new Continuous 

Emission Monitors (CEMs) and costs of 

Relative Accuracy Test Audits (RATA) 

for the CEMs. Additionally, FCPP 

included costs of performance tests and 

‘‘owner’s costs’’ in the indirect capital 

investment, such as financing, project 

management, and construction support 

costs, as well as legal assistance, permits 

and offsets, and public relations costs. 

In reviewing APS’s estimate, EPA 

found that the ratio of annual costs to 

the total capital costs for all control 

technologies projected by APS are 

considerably higher than those 

projected by other facilities that were 

amortized over the same 20 year time 

frame. For example, the total capital 

investment of SCR for Units 4 and 5 at 

FCPP is comparable to the most costly 

SCR retrofit (Unit 2) at NGS. However, 

total annual costs for FCPP are 

approximately 20% of the total capital 

costs for NOX control, and 

approximately 17–28% of total capital 

costs for PM control. In contrast, the 

total annual cost estimates by NGS for 

LNB and SCR are approximately 12– 

14% of the total capital costs. Other 

facilities in Arizona, New Mexico, and 

Oregon presented annual costs that 

ranged from 12–15% of total capital 

investments. 

In Tables 5 and 6, EPA re-calculated 

the total annual cost of the NOX and PM 

control technologies based on an annual 

to capital cost ratio of 15% to be 

consistent with annual costs estimated 

by other facilities. EPA did not adjust 

APS’s estimates for capital costs. 

TABLE 5—FCPP COSTS OF COMPLIANCE FOR NOX BASED ON EPA REVISIONS

LNB/LNB + OFA SCR SCR + LNB SCR + LNB + OFA 

Total Annual Costs 

Unit 1 ....................................................................................... $616,350 $16,599,600 $16,741,350 $16,808,700 

Unit 2 ....................................................................................... 616,350 17,851,500 18,159,900 18,224,400 

Unit 3 ....................................................................................... 705,150 16,962,600 17,313,000 17,227,650 

Unit 4 ....................................................................................... 2,289,000 39,810,900 39,810,900 41,916,600 

Unit 5 ....................................................................................... 2,289,000 39,810,900 39,810,900 41,916,600 


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9White Paper: Selective Catalytic Reduction 

(SCR) Control of NOX Emissions from Fossil FuelFired Electric Power Plants, Prepared by Institute of Clean Air Companies Inc., May 2009. 

10See http://www.azdeq.gov/environ/air/permits/ 

download/pastmonth.pdf. 

TABLE 6—FCPP COSTS OF COMPLIANCE FOR PM BASED ON EPA REVISIONS

Upstream ESP Upstream 

baghouse 

Wet metal 

ESP 

Wet membrane 

ESP 

Total Annual Costs 

Unit 1 ....................................................................................... $5,585,400 $7,577,250 $4,820,400 $3,504,000 

Unit 2 ....................................................................................... 6,855,300 9,148,800 4,931,850 3,585,150 

Unit 3 ....................................................................................... 6,020,250 8,939,100 8,939,100 4,048,200 

In addition to the total annual cost, 

other factors, such as estimated control 

efficiency and how the emissions 

reductions are calculated influence the 

cost effectiveness of controls. See 40 

CFR Part 51, App. Y, Step 4.a.4. APS 

estimated that SCR could achieve NOX

control of approximately 90% or greater 

from the baseline emissions. For new 

facilities, 90% or greater reduction in 

NOX from SCR can be reasonably 

expected. See May 2009 White Paper on 

SCR from Institute of Clean Air 

Companies.9 For SCR retrofits on an 

existing coal-fired power plant, Arizona 

Department of Environmental Quality 

(ADEQ) determined that 75% control 

from SCR (following upstream 

reductions by LNB) was appropriate for 

the Coronado Generating Station in 

Arizona.10 Based on this data, EPA has 

determined that an 80% control 

efficiency for SCR alone, rather than the 

90+% control assumed by APS, is 

appropriate. Accordingly, EPA 

calculated post-SCR control NOX

emissions from FCPP to be higher than 

the values of 0.06 and 0.08 lb/MMBtu 

used by APS, ranging from 0.10 lb/ 

MMBtu from Units 4 or 5 to a maximum 

of 0.16 lb/MMBtu from Unit 1. 

APS reported baseline PM emissions 

from Unit 3 to be 0.029 lb/MMBtu, 

however, EPA has determined that 0.05 

lb/MMBtu for Unit 3 is the appropriate 

emission rate to use based on source test 

information collected in October 2007. 

PM emissions determined from three 

one-hour test runs on October 19, 2007 

were 0.041 lb/MMbtu, 0.372 lb/MMbtu, 

and 0.121 lb/MMbtu. APS shut down 

Unit 3 for repairs after receiving the test 

results. Subsequent testing when the 

unit was brought back on line showed 

the unit barely met its 0.05 lb/MMbtu 

emission limit. Prior year test results for 

Unit 3 have also shown emissions at or 

near the 0.05 lb/MMBtu limit. 

Tables 7 and 8 contain EPA’s recalculated emissions reductions and 

cost effectiveness for NOX and PM based 

on adjusting the annual costs, the NOX

control efficiency for SCR and the 

baseline PM emissions as discussed 

above. 

TABLE 7—FCPP COST EFFECTIVENESS FOR NOX BASED ON EPA REVISIONS

LNB/LNB + OFA SCR SCR + LNB SCR + LNB + OFA 

Tons of NOX Reduced per Year (tpy) 

Unit 1 ....................................................................................... 2,478 4,417 5,097 5,097 

Unit 2 ....................................................................................... 1,524 3,716 4,210 4,210 

Unit 3 ....................................................................................... 2,563 4,652 5,224 5,224 

Unit 4 ....................................................................................... 3,275 9,171 10,060 10,060 

Unit 5 ....................................................................................... 3,284 9,195 10,086 10,086 

Cost Effectiveness of Controls ($/ton) 

Unit 1 ....................................................................................... 249 3,758 3,284 3,298 

Unit 2 ....................................................................................... 404 4,803 4,314 4,329 

Unit 3 ....................................................................................... 275 3,646 3,314 3,298 

Unit 4 ....................................................................................... 699 4,341 3,957 4,167 

Unit 5 ....................................................................................... 697 4,330 3,947 4,156 

TABLE 8—FCPP COST EFFECTIVENESS FOR PM BASED ON EPA REVISIONS

Upstream ESP Upstream 

baghouse Wet metal ESP Wet membrane ESP 

Tons of PM Reduced per Year (tpy) 

Unit 1 ....................................................................................... 92 92 92 92 

Unit 2 ....................................................................................... 123 123 123 123 

Unit 3 ....................................................................................... 375 375 375 375 

Cost Effectiveness of Controls ($/ton) 

Unit 1 ....................................................................................... 60,691 82,334 52,378 38,074 

Unit 2 ....................................................................................... 55,556 74,143 39,968 29,054 

Unit 3 ....................................................................................... 16,074 23,867 23,867 10,808 


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11http://www.eia.doe.gov/cneaf/electricity/epm/ 

table5_6_b.html 

The National Park Service (NPS) 

calculated the cost effectiveness of SCR 

using only the estimates and allowed 

categories of costs from EPA’s Air 

Pollution Control Costs Manual. The 

NPS costs of compliance and cost 

effectiveness are shown in Table 9. NPS 

assumed post-SCR NOX emissions of 

0.06 lb/MMBtu. The capital and annual 

costs of SCR the NPS estimated using 

the EPA Control Cost Manual are 

considerably lower than those estimated 

by APS. 

TABLE 9—NPS’S ESTIMATED SCR COSTS OF COMPLIANCE FOR FCPP 

Total capital cost Total annual cost Cost effectiveness 

(ton) 

Unit 1 ......................................................................................................................... $18,508,764 $2,983,004 $1,558 

Unit 2 ......................................................................................................................... 18,508,764 3,052,010 1,469 

Unit 3 ......................................................................................................................... 22,187,577 3,497,117 1,684 

Unit 4 ......................................................................................................................... 52,788,968 9,838,997 1,185 

Unit 5 ......................................................................................................................... 52,788,968 9,213,942 1,357 

In Tables 10 and 11, EPA has 

calculated the expected increase in 

electricity generation costs to be borne 

by consumers in terms of dollars per 

kilowatt hour ($/kWh), assuming 85% 

capacity. The calculation is based on 

EPA’s annual cost estimates in Tables 5 

and 6. DOE provides information on the 

average cost of electricity by state in a 

given year.11 In 2009, the average cost 

of electricity in Arizona for residential 

consumers was $0.0994/kWh, which 

was below the U.S. average ($0.1128/ 

kWh) and the continental U.S. 

maximum of $0.1993/kWh in 

Connecticut. 

TABLE 10—INCREASE IN ELECTRICITY COSTS FROM NOX CONTROLS AT FCPP 

LNB/LNB + OFA 

kWh 

SCR 

kWh 

SCR + LNB 

kWh 

SCR + LNB + OFA 

kWh 

Unit 1 ....................................................................................... $0.001 $0.015 $0.015 $0.015 

Unit 2 ....................................................................................... 0.001 0.016 0.016 0.016 

Unit 3 ....................................................................................... 0.001 0.011 0.012 0.012 

Unit 4 ....................................................................................... 0.001 0.009 0.009 0.009 

Unit 5 ....................................................................................... 0.001 0.009 0.009 0.009 

TABLE 11—INCREASE IN ELECTRICITY COSTS FROM PM CONTROLS AT FCPP 

Upstream ESP 

kWh 

Upstream 

baghouse 

kWh 

Wet metal ESP 

kWh 

Wet membrane 

ESP 

kWh 

Unit 1 ....................................................................................... $0.005 $0.007 $0.004 $0.003 

Unit 2 ....................................................................................... 0.006 0.008 0.004 0.003 

Unit 3 ....................................................................................... 0.004 0.006 0.006 0.003 

EPA requests comments on the data 

used to estimate the cost of compliance 

for the different levels of control for 

NOX and PM for FCPP. 

2. NGS 

a. Cost of Compliance 

The cost estimates provided by SRP 

(updated in the 2008 submissions to 

EPA) are included in Table 12 for 

different control options for NOX. The 

NOX control options included in Table 

12 are (1) LNB plus Separated Overfire 

Air (SOFA) on all three units, (2) SCR 

on Units 1 and 3, LNB + SOFA on Unit 

2, and (3) SCR + LNB + SOFA on all 

three units. 

TABLE 12—NGS COSTS OF COMPLIANCE FOR NOX BASED ON SRP ANALYSIS

LNB + SOFA 

(All units) 

SCR + LNB + SOFA 

(Units 1 & 3); 

LNB + SOFA 

(Unit 2) 

SCR + LNB + SOFA 

(All units) 

Total Capital Investment 

Unit 1 ....................................................................................................................... $14,000,000 $212,000,000 $212,000,000 

Unit 2 ....................................................................................................................... 14,000,000 14,000,000 281,000,000 

Unit 3 ....................................................................................................................... 14,000,000 212,000,000 212,000,000 


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12See July 29, 2008 Letter from Kevin Wanttaja 

(SRP) to Deborah Jordan (EPA) and its attachment: 

July 25, 2008 Final Report for SCR and SNCR Cost 

Study, prepared by Sargent and Lundy. 

TABLE 12—NGS COSTS OF COMPLIANCE FOR NOX BASED ON SRP ANALYSIS—Continued 

LNB + SOFA 

(All units) 

SCR + LNB + SOFA 

(Units 1 & 3); 

LNB + SOFA 

(Unit 2) 

SCR + LNB + SOFA 

(All units) 

Total Annual Cost 

Unit 1 ....................................................................................................................... 1,622,000 28,951,500 28,951,500 

Unit 2 ....................................................................................................................... 1,622,000 36,945,000 36,945,000 

Unit 3 ....................................................................................................................... 1,622,000 28,951,500 28,951,500 

The higher retrofit cost of SCR on 

Unit 2 compared to Units 1 and 3 is a 

result of the physical layout of the coal 

conveyor and its supports in relation to 

Unit 2. Because of limited access for 

construction cranes and equipment, and 

to make room for the SCR and fans by 

demolishing the remainder of the old 

Unit 2 chimney, costs for the Unit 2 

retrofit are anticipated to be higher than 

for Units 1 and 3.12

b. Cost Effectiveness 

In determining the cost effectiveness 

of controls, SRP estimated NOX

emissions reductions using baseline 

emission rates of: 0.49 lb/MMBtu for 

Unit 1; 0.45 lb/MMBtu for Unit 2; 0.46 

lb/MMBtu for Unit 3. For the various 

control options, SRP estimated 

emissions reductions from: LNB + 

SOFA of 47–51% to achieve 0.24 lb/ 

MMBtu; and from SCR of 82–84% to 

achieve 0.08 lb/MMBtu. 

Table 13 lists the reduction in NOX

emissions and cost effectiveness 

estimated by SRP for the three control 

scenarios listed in Table 12. 

TABLE 13—SRP EMISSIONS REDUCTIONS AND COST EFFECTIVENESS FOR NOX

LNB + SOFA 

(All units) 

SCR + LNB + SOFA 

(Units 1 & 3); 

LNB + SOFA 

(Unit 2) 

SCR + LNB + SOFA 

(All units) 

NOX Emissions Reductions (tpy) 

Unit 1 ....................................................................................................................... 9,631 15,794 15,794 

Unit 2 ....................................................................................................................... 8,667 8,667 15,271 

Unit 3 ....................................................................................................................... 8,824 15,241 15,241 

Cost Effectiveness ($/ton) 

Unit 1 ....................................................................................................................... 168 1,833 1,833 

Unit 2 ....................................................................................................................... 187 187 2,419 

Unit 3 ....................................................................................................................... 184 1,900 1,900 

Appendix Y of the BART Guidelines 

states that average cost effectiveness 

should be based on the annualized cost 

and the difference between baseline 

annual emissions and annual emissions 

with the control technology. In 

calculating the cost effectiveness, it 

appears SRP used the same 24-hour 

average actual emission rate from the 

highest emitting day used for its 

modeling inputs, rather than an annual 

average rate. Therefore, EPA has revised 

SRP’s estimated NOX emissions 

reductions by starting with baseline 

emission rates for NOX averaged over 

2004–2006 of: 0.35 lb/MMBtu for Unit 

1; 0.37 lb/MMBtu for Unit 2; 0.31 lb/ 

MMBtu for Unit 3. The revised emission 

reductions and cost effectiveness 

estimates are provided in Table 14. 

TABLE 14—EPA EMISSIONS REDUCTIONS AND COST EFFECTIVENESS FOR NOX

LNB + SOFA 

(All units) 

SCR + LNB + SOFA 

(Units 1 & 3); 

LNB + SOFA 

(Unit 2) 

SCR + LNB + SOFA 

(All units) 

NOX Emissions Reductions (tpy) 

Unit 1 ....................................................................................................................... 3,658 9,643 9,643 

Unit 2 ....................................................................................................................... 4,208 4,208 9,888 

Unit 3 ....................................................................................................................... 2,284 8,158 8,158 

Cost Effectiveness ($/ton) 

Unit 1 ....................................................................................................................... 443 3,002 3,002 

Unit 2 ....................................................................................................................... 385 385 3,736 


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44322 Federal Register / Vol. 74, No. 166 / Friday, August 28, 2009 / Proposed Rules 

13CALPUFF is the model that is recommended 

for use in predicting visibility impact under the 

Regional Haze Guidelines. 40 CFR Part 51, App. Y, 

III.A.3 (‘‘CALPUFF is the best regulatory modeling 

application currently available for predicting a 

single source’s contribution to visibility impairment 

and is currently the only EPA-approved model for 

use in estimating single source pollutant 

concentrations resulting from the long range 

transport of primary pollutants. [note omitted]’’). 

TABLE 14—EPA EMISSIONS REDUCTIONS AND COST EFFECTIVENESS FOR NOX—Continued 

LNB + SOFA 

(All units) 

SCR + LNB + SOFA 

(Units 1 & 3); 

LNB + SOFA 

(Unit 2) 

SCR + LNB + SOFA 

(All units) 

Unit 3 ....................................................................................................................... 710 3,549 3,549 

The NPS calculated the cost 

effectiveness of SCR + LNB + SOFA 

using only the estimates and allowed 

categories of costs from EPA’s Air 

Pollution Control Costs Manual. The 

NPS costs of compliance and cost 

effectiveness are shown in Table 15. 

NPS assumed post-SCR NOX emissions 

of 0.05 lb/MMBtu. NPS accounts for the 

higher retrofit costs associated with Unit 

2 by applying a larger retrofit factor 

associated with physically difficult 

retrofits on Unit 2 compared to Units 1 

and 3. Note that the capital and annual 

costs of SCR estimated using the EPA 

Control Cost Manual are considerably 

lower than those estimated by SRP. 

TABLE 15—NPS COSTS OF CONTROLS AND COST EFFECTIVENESS FOR SCR 

Total capital cost Total annual cost Cost effectiveness 

(ton) 

Unit 1 ......................................................................................................................... $71,983,100 $12,065,299 $1,059 

Unit 2 ......................................................................................................................... 66,138,162 14,589,766 1,528 

Unit 3 ......................................................................................................................... 68,642,323 11,870,003 1,317 

EPA calculated the expected increase 

in electricity generation costs to 

consumers in $/kWh, assuming 85% 

capacity in Table 16. 

TABLE 16—INCREASE IN ELECTRICITY COSTS FROM NOX CONTROLS AT NGS 

LNB + SOFA 

(All Units) 

kWh 

SCR + LNB + SOFA 

(Units 1&3); 

LNB + SOFA 

(Unit 2) 

kWh 

SCR + LNB + SOFA 

(All Units) 

kWh 

Unit 1 ....................................................................................................................... $0.0003 $0.006 $0.006 

Unit 2 ....................................................................................................................... 0.0003 0.0003 0.007 

Unit 3 ....................................................................................................................... 0.0003 0.006 0.006 

In addition to the three NOX control 

scenarios, EPA considered another SCR 

control option that was not addressed 

by SRP. Based on EPA’s understanding 

of the location of the coal-feed line and 

the physical layout of Unit 2, EPA is 

requesting comment on the application 

of half an SCR to Unit 2. As configured, 

the flue gas from Unit 2 is split in half 

with each half containing its own 

separate hot-side ESP and FGD. Because 

the flue gas is already split, and because 

the coal-feed line impedes only one side 

of the Unit 2 split, SCR may be applied 

to half of Unit 2 so that the difficult 

retrofit associated with the relocation of 

the coal-feed line can be avoided. EPA 

estimates that the application of halfSCR on Unit 2 would require a total 

capital investment of $106 million, a 

total annual cost of $14.5 million, result 

in NOX reductions of over 7000 tpy 

(based on control to 0.14 lb/MMBtu) 

with a cost effectiveness of $2000/ton 

and an increased electricity generation 

cost of $0.003/kWh. 

In the November 2007 BART 

Analysis, SRP states that PM emissions 

controlled by hot-side ESPs in 

combination with wet scrubbers 

effectively limited PM emissions to less 

than 0.03 lb/MMBtu and did not 

include a BART analysis for further 

retrofit controls for PM10. In a letter 

dated December 12, 2008, NGS 

proposed a BART emission limit for PM 

of 0.05 lb/MMBtu. No additional 

discussions of modeling or other 

analyses for PM control at NGS are 

included in this ANPR. 

EPA requests comment on the data 

provided above to estimate the costs of 

compliance for BART controls at NGS. 

B. Factor 5: Degree of Visibility 

Improvement 

1. FCPP 

a. Visibility Modeling Scenarios 

APS’s contractor, AECOM, conducted 

visibility modeling using CALPUFF 13

based on a number of selected inputs. 

APS used its modeling results to 

estimate anticipated visibility 

improvement from the four different 

control technology options at the 

mandatory Class I Federal areas within 

a 300 km radius. 

EPA disagrees with and is requesting 

comment on a number of the inputs 

APS used for modeling. EPA has 

selected alternative inputs that we have 

determined are more representative. We 

have also modeled the resulting 

visibility improvement at the Class I 

areas based on our revised inputs. EPA 

is specifically requesting comment on 

EPA’s and APS’s selection of inputs. 

EPA’s modeled results, also using 

CALPUFF, are presented below in 

Tables 17–21. The modeling scenarios 

are: 


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14Estimating Total Sulfuric Acid Emissions from 

Stationary Power Plants—Technical Update, 

Electric Power Research Institute (EPRI), Palo Alto, 

CA, 2008. EPRI Product ID: 1016384. 

15We use penetration factor as 1-control factor, 

such that a penetration factor of 0.9 means 90% of 

the sulfuric acid penetrates through the control 

equipment. 

16Battye, W, and Boyer, K. Catalog of Global 

Emissi113on Inventories and Emission Inventory 

Tools for Black Carbon. EPA Contract No. 68–D– 

98–046, 2002. 

17Hydrogen Chloride and Hydrogen Fluoride 

Emission Factors for the NAPAP Inventory, EPA– 

600/7–85–041, U.S. Environmental Protection 

Agency, October 1985. 

18See Reference 1 of Table A–1 from the 1985 

EPA report. 

A. Baseline Visibility Impact (modeled by 

APS and EPA) 

B. Wet ESP for PM Control on Units 1–3 

(modeled by APS and EPA) 

C1. LNB + OFA for NOX on Units 1–5 

(modeled by APS) 

C2. LNB for NOX on Units 1 and 2 and LNB 

+ OFA on Units 3–5 (modeled by EPA) 

D. SCR for NOX on Units 3–5 (modeled by 

EPA) 

E1. SCR + LNB + OFA for NOX on Units 1– 

5 (modeled by APS) 

E2. SCR for NOX on Units 1–5 (modeled by 

EPA) 

APS and EPA modeled baseline and 

control scenarios using meteorological 

data from 2001–2003. The baseline 

scenario uses heat input and pollutant 

emission rates based on the 24-hour 

average actual emission rate from the 

highest emitting day of the 

meteorological period. The modeling 

scenarios listed above in C1/C2 and 

E1/E2 are based on the application of 

the same, or similar, control 

technologies but are listed as distinct 

modeling scenarios because EPA used 

different emission inputs than APS. 

b. EPA Modifications to Emission Rate 

Inputs 

The Appendix Y BART Guidelines 

state that baseline heat input and 

pollutant emission rates should be 

based on the 24-hour average actual 

emission rate from the highest emitting 

day of the meteorological period 

modeled. Although the modeling period 

for the BART analysis submitted by APS 

is 2001–2003, APS used heat input, 

NOX, SO2, and PM emission rates from 

2002–2006. Based on our review of the 

2001–2003 emissions data that APS 

reported to the EPA Clean Air Markets 

Division (CAMD), we have determined 

that the heat input and baseline NOX

emission rates inputs were generally 

appropriate, except that several of the 

highest emitting days for NOX and heat 

input occurred in 2001. Therefore, EPA 

revised the highest heat input rate for 

Units 1, 3, and 5 based on the 2001– 

2003 meteorological period. For NOX

emissions, the highest emitting days for 

Units 1,2, 3, and 5 occurred in 2001 

(over the 2001–2003 period), therefore, 

we also revised the baseline NOX

emission rate for those units. Data from 

CAMD for Unit 2 and 4 generally agreed 

with emission inputs used by APS. For 

SO2 emissions, because the SO2 control 

efficiency for Units 4 and 5 recently 

increased to 88%, EPA considers it 

more appropriate to rely on a more 

recent period (2006–2007) for SO2

emissions for Units 4 and 5, rather than 

using SO2 data from the 2001–2003 

meteorological period. 

CALPUFF modeling requires 

additional inputs, including SO4, 

representing condensable inorganic PM 

and fine and coarse filterable PM. For 

SO4, APS estimated that the 

condensable inorganic PM was entirely 

represented by sulfuric acid (H2SO4) 

formed during the combustion process 

(Scenarios A—C), or from the 

combustion process together with 

reactions on the SCR catalyst (Scenarios 

D and E). APS and EPA both relied on 

the H2SO4 calculation methodology 

provided by the Electric Power Research 

Institute (‘‘EPRI’’). 14 The EPRI method 

relies on characterization of various 

sources and sinks of H2SO4 in the boiler 

and downstream components, such as 

the air preheater, and particulate matter 

(PM) and SO2 control devices. For the 

baseline and non-SCR emissions 

scenarios (Scenarios A–C), the main 

difference between APS’s and EPA’s 

calculations for H2SO4 arises from the 

assumed loss of H2SO4 in the air 

preheater. APS used a penetration 

factor 15 of 0.9 whereas EPA used a 

penetration factor of 0.49, which is 

consistent with the 2008 EPRI 

guidelines. 

Because CAMD data is not available 

for PM, we relied on filterable PM 

emissions used in APS’s revised 

modeling analysis (Supplemental 

submitted November 2008), based on 

the maximum of six stack test results 

from the 2002–2006 period for each 

unit. APS additionally provided the 

stack test results in a spreadsheet for 

each unit over 2002–2006. Although 

APS reported using the worst-case stack 

test values in their Supplemental 

Modeling Report, the lb/MMBtu PM 

values in Table 5–2 do not match the 

highest stack test results in the APS’s 

spreadsheet. Therefore, EPA revised the 

filterable PM values for Units 1–3. We 

then applied values from AP–42 that 

estimate for a dry bottom boiler with 

scrubber (Units 1–3), 71% of filterable 

PM is PM10, and 51% of filterable PM 

is fine PM10 (i.e., PM2.5), thus 20% of 

filterable PM is coarse PM10, i.e., 71%– 

51%. For a dry bottom boiler with a 

baghouse (Units 4 and 5), AP–42 

estimates that 92% of filterable PM is 

PM10, and 53% of filterable PM is fine 

PM10 (i.e., PM2.5), thus 39% of filterable 

PM is coarse PM10, i.e., 92%–53%. APS 

also estimated elemental carbon (EC) to 

be 3.7% of the PM2.5, based on Table 6 

of a 2002 draft report prepared for 

EPA.16

In addition to the estimates for PM 

fine described above, EPA additionally 

revised the modeling inputs for PM fine 

to include emissions of hydrogen 

chloride (HCl) and hydrogen fluoride 

(HF). AP–42 (1.1 Bituminous and 

Subbituminous Coal Combustion) 

provides a single emission factor each 

for HCl and HF from all coal and boiler 

types. APS assumed H2SO4 to be the 

only contributor to condensable 

inorganic PM, and the NPS raised 

concerns about the exclusion of HCl and 

HF and recommended these two 

compounds be factored into the CPM– 

IOR (SO4) modeling input. Method 202 

for measuring condensable PM does not 

capture HCl and HF, therefore, EPA 

added these emissions to PM fine rather 

than SO4. 

HCl and HF emission factors in AP– 

42 (Table 1.1–15) are based on a lb/ton 

coal basis (1.2 lbs HCl per ton of coal 

and 0.15 lb HF per ton of coal, which 

converts to 0.016 lb HCl/mmbtu and 

0.007 lb HF/mmbtu using 10496 Btu/lb 

coal). Footnote (a) to Table 1.1–15 in 

AP–42 states that these factors apply to 

both controlled and uncontrolled 

sources. The HCl and HF emission 

factors refer to a 1985 report on HCl and 

HF prepared for the NAPAP 

inventory.17 This 1985 report shows 

that the uncontrolled and controlled 

emission factors for HCl and HF were 

considered to be the same only because 

wet scrubbers and FGD systems, which 

are the only controls used on boilers 

that have a significant effect on HCl and 

HF removal, were (at the time) used to 

control only a small percentage of coal 

burned in utility boilers (see footnote (a) 

from Tables 3–6 and 3–7 from the 1985 

report). Given that 2 units at FCPP use 

wet FGD and 3 units use venturi 

scrubbers for SO2 control, EPA did not 

apply the AP–42 emission factor ‘‘as is’’ 

to FCPP. Furthermore, given that the 

chlorine content of the coal used by 

FCPP is much lower than coal from 

other parts of the U.S., we scaled the 

HCl emission factor (based on 46 sites 

from several parts of the country 18) for 

subbituminous coal to account for the 

low Cl content of FCPP coal compared 

to average Cl content of U.S. coal. 


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19Electric Utility Mercury Information Collection 

Request (OMB Control Number 2060–0396): 

http://www.epa.gov/ttn/atw/combust/utiltox/ 

utoxpg.html#DA2. 

20http://energy.er.usgs.gov/coalqual.htm#submit. 

21Based on samples D176206 and D202211. 

From the emission factor of 1.9 lb 

HCl/ton, EPA scaled the emission factor 

to 0.13 lb HCl/ton coal. Table 3–2 of the 

1985 report shows that average Cl 

content of coal by coal type ranges from 

63–1064 ppm (by weight) with lignite 

and eastern bituminous coals 

contributing the low and high values, 

respectively. Table 3–3 shows that 

average Cl content of coal ranges from 

20–1900 ppm (by weight), with 

Montana coal and Illinois coal 

contributing the low and high values, 

respectively. The average bituminous 

coal Cl content from the values reported 

in Table 3–2 is 736 ppm. From chlorine 

coal content data collected for the Clean 

Air Mercury Rule,19 FCPP coal was 

determined to have 50 ppm Cl. 

Therefore, we scaled the HCl emission 

factor of 1.9 by the Cl content ratio of 

FCPP to bituminous US coal (50/736) 

yielding an emission factor of 0.13 lb 

HCl/ton coal. 

For the fluorine content of coal, 

Tables 3–2 and 3–3 from the 1985 report 

show that average F content ranges from 

28–141 ppm depending on coal type 

(lignite and eastern bituminous, 

respectively), and from 45–124 

depending on the region in the U.S. 

(Northern Great Plains and Gulf 

Province, respectively). Based on trace 

element data reported in the U.S. Coal 

Quality Database,20 coal burned by 

FCPP (from the Navajo Mine) has an 

average F content of 80 ppm.21 We 

scaled the HF emission factor of 0.23 lb/ 

ton by the F content ratio of FCPP coal 

to total US (80/102), resulting in an 

FCPP emission factor for HF of 0.18 lb 

HF/ton coal. 

Using the scaled emission factors of 

0.13 lb HCl/ton coal and 0.18 lb HF/ton 

coal, EPA accounted for additional loss 

of HCl and HF from the use of flue gas 

desulfurization (FGD) or venturi 

scrubbers. Page 19 of the 1985 EPA 

report describes that wet scrubbers are 

expected to provide approximately 80% 

control of HCl and HF from coal-fired 

utility boilers, and removal of HCl from 

flue gases with FGD systems is very 

high (with sodium bicarbonate systems 

providing 95% control), but little data 

are available to quantify the HF removal 

efficiency of FGD systems. We assumed 

the FGD and venturi scrubbers provided 

80% control of HCl and HF. Thus, our 

HCl and HF emission factors for FCPP 

are 0.015 lb HCl/MMBtu and 0.0020 lb 

HF/MMBtu. These HCl and HF 

emissions were applied as inputs to PM 

fine for all modeling scenarios. 

TABLE 17—APS AND EPA BASELINE EMISSION RATES

[Scenario A] 

Unit 1 Unit 2 Unit 3 Unit 4 Unit 5 

APS Modeling Inputs for Baseline Case (all units in lb/hr) 

SO2 ........................................................ 464.17 615.12 995.26 2,026.10 2,130.76 

SO4 ........................................................ 3.35 3.78 4.65 1.03 1.03 

NOX ........................................................ 1,841.37 1,567.66 1,926.23 5,015.98 4,444.04 

SOA ....................................................... 8.35 9.41 11.58 32.00 32.00 

PM fine ................................................... 30.74 47.87 52.90 100.93 48.00 

PM coarse .............................................. 12.52 19.49 21.54 77.12 36.67 

EC .......................................................... 1.18 1.84 2.03 3.88 1.84 

EPA Modeling Inputs for Baseline Case (all units in lb/hr) 

SO2 ........................................................ 522.54 615.12 1,042.09 2,026.10 2,131.85 

SO4 ........................................................ 2.06 2.06 2.65 0.51 0.51 

NOX ........................................................ 2,020.14 1,599.47 1,970.80 5,015.98 4,508.56 

SOA ....................................................... 9.40 9.41 12.13 32.00 32.20 

PM fine ................................................... 46.29 65.99 70.18 128.93 76.20 

PM coarse .............................................. 15.50 23.52 24.26 77.12 36.69 

EC .......................................................... 1.46 2.22 2.29 3.88 1.85 

TABLE 18—APS AND EPA EMISSION FOR PM CONTROL ON UNITS 1–3 

[Scenario B] 

Unit 1 Unit 2 Unit 3 Unit 4 Unit 5 

APS Modeling Inputs for Baseline Case (all units in lb/hr) 

SO2 ........................................................ 464.17 615.12 995.26 2,026.10 2,130.76 

SO4 ........................................................ 0.34 0.38 0.47 1.03 1.03 

NOX ........................................................ 1,841.37 1,567.66 1,926.23 5,015.98 4,444.04 

SOA ....................................................... 8.35 9.41 11.58 32.00 32.00 

PM fine ................................................... 15.34 20.39 22.54 100.93 48.00 

PM coarse .............................................. 11.72 15.58 17.22 77.12 36.67 

EC .......................................................... 0.59 0.78 0.87 3.88 1.84 

EPA Modeling Inputs for Baseline Case (all units in lb/hr) 

SO2 ........................................................ 522.54 615.12 1,042.09 2,026.10 2,131.85 

SO4 ........................................................ 0.21 0.21 0.27 0.51 0.51 

NOX ........................................................ 2,020.14 1,599.47 1,970.80 5,015.98 4,508.56 

SOA ....................................................... 9.40 9.41 12.13 32.00 32.20 


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22See http://www.azdeq.gov/environ/air/permits/ 

download/pastmonth.pdf. 

TABLE 18—APS AND EPA EMISSION FOR PM CONTROL ON UNITS 1–3—Continued 

[Scenario B] 

Unit 1 Unit 2 Unit 3 Unit 4 Unit 5 

PM fine ................................................... 25.49 28.63 34.21 128.93 76.20 

PM coarse .............................................. 13.19 15.58 18.03 77.12 36.69 

EC .......................................................... 0.66 0.78 0.91 3.88 1.85 

TABLE 19—APS AND EPA EMISSION FOR PM CONTROL ON UNITS 1–3 

[Scenario C] 

Unit 1 Unit 2 Unit 3 Unit 4 Unit 5 

APS Modeling Inputs for LNB + OFA (Scenario C1) (in lb/hr) 

SO2 ........................................................ 464.17 615.12 995.26 2,026.10 2,130.76 

SO4 ........................................................ 3.35 3.78 4.65 1.03 1.03 

NOX ........................................................ 1,010.91 1,051.90 1,078.69 3,561.35 3,155.27 

SOA ....................................................... 8.35 9.41 11.58 32.00 32.00 

PM fine ................................................... 30.74 47.87 52.90 100.93 48.00 

PM coarse .............................................. 12.52 19.49 21.54 77.12 36.67 

EC .......................................................... 1.18 1.84 2.03 3.88 1.84 

EPA Modeling Inputs for LNB/OFA (Scenario C2) (in lb/hr) 

SO2 ........................................................ 522.54 615.12 1,042.09 2,026.10 2,131.85 

SO4 ........................................................ 2.06 2.06 2.65 0.51 0.51 

NOX ........................................................ 1,109.06 1,073.25 1,103.65 3,561.35 3,201.08 

SOA ....................................................... 9.40 9.41 12.13 32.00 32.20 

PM fine ................................................... 46.29 65.99 70.18 128.93 76.20 

PM coarse .............................................. 15.50 23.52 24.26 77.12 36.69 

EC .......................................................... 1.46 2.22 2.29 3.88 1.85 

EPA also disagrees with APS’s 

evaluation of sulfuric acid emissions. 

Sulfuric acid emissions are estimated to 

increase as a result of operating an SCR 

due to additional oxidation of SO2 to 

SO3 on the SCR catalyst. APS used a 1% 

conversion rate from the SCR catalyst. 

Yet a Prevention of Significant 

Deterioration (PSD) permit issued June 

2, 2009, to Coronado Generating Station 

by the ADEQ 22 required the use of an 

ultra-low conversion catalyst (0.5% 

conversion) as Best Available Control 

Technology (BACT). EPA has 

determined that APS could also use an 

ultra-low conversion catalyst. Therefore, 

in our calculation of H2SO4 emissions 

from the addition of the SCR, we 

accounted for a 0.5% conversion of SO2

to SO3. 

For emissions of ammonia (NH3) 

resulting from SCR, EPA followed the 

calculation methodology APS used in 

its supplemental modeling analysis for 

FCPP (dated November 2008). 

TABLE 20—EPA EMISSIONS FOR SCR ON UNITS 3–5 

[Scenario D] 

Unit 1 Unit 2 Unit 3 Unit 4 Unit 5 

EPA Modeling Inputs for SCR on Units 3–5, No Control Units 1 and 2 (in lb/hr) 

SO2 ........................................................ 522.54 615.12 1,042.09 2,026.10 2,131.85 

SO4 ........................................................ 2.06 2.06 12.52 2.52 2.54 

NOX ........................................................ 2,020.14 1,599.47 472.99 1,203.84 1,082.05 

SOA ....................................................... 9.40 9.41 12.13 32.00 32.20 

PM fine ................................................... 46.29 65.99 70.18 128.93 76.20 

PM coarse .............................................. 15.50 23.52 24.26 77.12 36.69 

EC .......................................................... 1.46 2.22 2.29 3.88 1.85 

TABLE 21—APS AND EPA EMISSIONS FOR SCR ON UNITS 1–5 

[Scenario E] 

Unit 1 Unit 2 Unit 3 Unit 4 Unit 5 

APS Modeling Inputs for SCR + LNB + OFA (Scenario E1) (in lb/hr) 

SO2 ........................................................ 464.17 615.12 995.26 2,026.10 2,130.76 


jlentini on DSKJ8SOYB1PROD with PROPOSALS
44326 Federal Register / Vol. 74, No. 166 / Friday, August 28, 2009 / Proposed Rules 

23Letter 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. 

24 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. 

25http://vista.cira.colostate.edu/improve/. 

26Mark 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. 

TABLE 21—APS AND EPA EMISSIONS FOR SCR ON UNITS 1–5—Continued 

[Scenario E] 

Unit 1 Unit 2 Unit 3 Unit 4 Unit 5 

SO4 ........................................................ 30.71 34.61 42.61 9.53 9.58 

NOX ........................................................ 147.31 141.09 192.62 601.92 533.29 

SOA ....................................................... 8.35 9.41 11.58 32.00 32.00 

PM fine ................................................... 30.74 47.87 52.90 100.93 48.00 

PM coarse .............................................. 12.52 19.49 21.54 77.12 36.67 

EC .......................................................... 1.18 1.84 2.03 3.88 1.84 

EPA Modeling Inputs for SCR (Scenario E2) (in lb/hr) 

SO2 ........................................................ 522.54 615.12 1,042.09 2,026.10 2,131.85 

SO4 ........................................................ 9.70 9.71 12.52 2.52 2.54 

NOX ........................................................ 484.83 383.87 472.99 1,203.84 1,082.05 

SOA ....................................................... 9.40 9.41 12.13 32.00 32.20 

PM fine ................................................... 46.29 65.99 70.18 128.93 76.20 

PM coarse .............................................. 15.50 23.52 24.26 77.12 36.69 

EC .......................................................... 1.46 2.22 2.29 3.88 1.85 

c. Ammonia Background 

In addition to the different CALPUFF 

emission rates described above, EPA 

additionally revised some postprocessor settings from those originally 

used by APS. The USFS indicated that 

the ammonia background 

concentrations modeled by APS were 

underestimated compared to observed 

concentrations.23 EPA agrees and has 

used a similar back-calculation 

methodology to the one referenced by 

the USFS for estimating ammonia 

background values. 

Ammonia is important because it is a 

precursor to particulate ammonium 

sulfate and ammonium nitrate which 

degrades visibility. It is present in the 

air from both natural and anthropogenic 

sources. The latter may include 

ammonia slip from the use of ammonia 

in SCR and SNCR technologies to 

control NOX emissions. 

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. 

Very little monitored ammonia data is 

available. The default recommended 

ammonia background value for arid 

regions is 1 ppb, as described in the 

IWAQM Phase 2 document.24

Alternative levels may be used if 

supported by data. To address concerns 

expressed by APS in their January 2008 

BART modeling protocol (p. 4–1) that 

CALPUFF over-predicts ammonium 

nitrate in winter, EPA estimated 

ammonia background for all Class I 

areas (except Mesa Verde National Park, 

see below) by back-calculating from 

measurements at monitors in the areas 

run by the IMPROVE program.25

IMPROVE monitors do not measure 

ammonia directly; rather, they measure 

particulate sulfate and nitrate. In the 

atmosphere, particulate sulfate and 

nitrate are essentially all in the form of 

ammonium sulfate and ammonium 

nitrate, respectively. Applying their 

chemical formulas, EPA estimated a 

lower bound on the amount of ammonia 

that must have been present to combine 

with gaseous sulfate and nitrate in order 

to form the measured particulate sulfate 

and nitrate. 

EPA performed this back-calculation 

using 2005–2007 data for all 14 

IMPROVE monitors at Class I areas in 

the modeling domains. For each 

monitor, EPA used the maximum 

calculated value for each calendar 

month to represent the month. Then, for 

each month, EPA averaged over all 

monitors, resulting in a single value for 

each of the 12 calendar months. For the 

months of May and July, this backcalculation resulted in a somewhat 

lower value than the IWAQM default of 

1 ppb which was also used by APS; for 

these months EPA used 1 ppb. The 

back-calculation results ranged from 0.7 

ppb in the winter to 1 ppb in summer, 

except the value of 1.3 ppb in June. 

Ammonia background concentrations 

for Mesa Verde National Park were 

derived from measured ammonia 

concentrations in the Four Corners area, 

as described in Sather et al., (2008).26

Monitored data was available within 

park, 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 the park 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 under 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 midrange of the various stations plotted. 

The results ranged from 1.0 ppb in 

winter to 1.5 ppb in summer. See Table 

22. 

TABLE 22—AMMONIA BACKGROUND CONCENTRATION IN PPB (POSTUTIL PARAMETER BCKNH3) FOR FCPP 

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 

IWAQM default ................................................................. 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 


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27U.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. 28EPA 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 impact the overall results. 

TABLE 22—AMMONIA BACKGROUND CONCENTRATION IN PPB (POSTUTIL PARAMETER BCKNH3) FOR FCPP—Continued 

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 

APS values ....................................................................... 0.2 0.2 0.5 0.5 1.0 1.0 1.0 1.0 1.0 0.5 0.5 0.2 

EPA values ....................................................................... 0.8 0.7 0.7 1.0 1.0 1.3 1.0 1.0 1.0 1.0 1.0 0.9 

EPA values for Mesa Verde ............................................ 1.0 1.0 1.3 1.3 1.3 1.3 1.5 1.5 1.5 1.5 1.3 1.0 

d. Natural Background 

The BART determination guidelines 

recommend that impacts of sources 

should be estimated in deciviews 

relative to natural background. 

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.’’ 27

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. 

TABLE 23—NATURAL BACKGROUND CONCENTRATIONS FOR FCPP AND NGS 

CALPOST parameter Pollutant Concentration 

(μg/m3) 

BKSO4 ................................................... ammonium sulfate .................................................................................................. 0.12 

BKNO3 ................................................... ammonium nitrate ................................................................................................... 0.10 

BKPMC ................................................... coarse particulates .................................................................................................. 3.00 

BKOC ..................................................... organic carbon ........................................................................................................ 0.47 

BKSOIL .................................................. soil ........................................................................................................................... 0.50 

BKEC ...................................................... elemental carbon .................................................................................................... 0.02 

e. Visibility Modeling Results 

To assess results from the CALPUFF 

model and post-processing steps, EPA 

used a least-squares regression analysis 

of all visibility modeling output from 

the 2001–2003 modeling period to 

determine the percent improvement in 

visibility (measured in deciviews) 

compared to the baseline resulting from 

the application of control technologies. 

Table 24 shows EPA’s modeled 

predicted visibility improvements at the 

16 Class I areas within a 300 km radius 

of FCPP. 

APS presented visibility improvement 

by comparing the 98th percentile (8th 

highest) of the daily maximum deciview 

(dv) values from CALPUFF per Class I 

area, averaged over 2001–2003. As 

outlined in the 1999 Regional Haze rule 

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

deciview change in haziness is a small 

but noticeable change in haziness under 

most circumstances when viewing 

scenes in a Class I area. Table 25 

presents the visibility impacts of the 

98th percentile of daily maxima for each 

Class I area for each year, averaged over 

2001–2003, determined for FCPP by 

APS. Table 26 presents the visibility 

impacts of the 98th percentile of daily 

maxima from 2001–2003 for each Class 

I area determined by EPA.28

TABLE 24—PERCENT IMPROVEMENT IN DECIVIEW IMPACTS FROM EPA MODELING AT EACH CLASS I AREA FROM PM AND

NOX CONTROLS AT FCPP 

Scenario B 

(Wet ESP) 

(%) 

Scenario C2 

(LNB) 

(%) 

Scenario D 

(SCR 3–5) 

(%) 

Scenario E2 

(SCR 1–5) 

(%) 

Arches .............................................................................................................................. 0.4 17 31 49 

Bandolier .......................................................................................................................... 0.5 20 37 52 

Black Canyon ................................................................................................................... 0.3 22 39 55 

Canyonlands .................................................................................................................... 0.4 15 28 45 

Capitol Reef ..................................................................................................................... 0.3 17 30 46 

Grand Canyon ................................................................................................................. 0.4 19 33 50 

Great Sand Dunes ........................................................................................................... 0.4 24 44 42 

La Garita .......................................................................................................................... 0.4 24 43 42 

Maroon Bells .................................................................................................................... 0.4 25 43 59 

Mesa Verde ..................................................................................................................... 0.6 14 27 42 

Pecos ............................................................................................................................... 0.5 21 39 53 

Petrified Forest ................................................................................................................ 0.4 20 35 51 

San Pedro ........................................................................................................................ 0.6 18 32 47 

West Elk ........................................................................................................................... 0.3 24 42 58 

Weminuche ...................................................................................................................... 0.5 22 50 55 

Wheeler Peak .................................................................................................................. 0.5 22 40 55 


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44328 Federal Register / Vol. 74, No. 166 / Friday, August 28, 2009 / Proposed Rules 

TABLE 25—IMPACTS OF FCPP ON VISIBILITY (98TH PERCENTILE OF DAILY MAXIMUM DV) AT SIXTEEN CLASS I AREAS AS

MODELED BY APS 

Baseline 

Visibility impact (dv) after applying: 

Wet ESP 

(B) LNB (C1) SCR (E1) 

Arches ............................................................................................................................ 1 .98 1.96 1.74 1.23 

Bandolier ........................................................................................................................ 1 .71 1.70 1.57 1.12 

Black Canyon ................................................................................................................. 1 .44 1.43 1.21 0.75 

Canyonlands .................................................................................................................. 2 .25 2.23 2.06 1.67 

Capitol Reef ................................................................................................................... 1 .74 1.73 1.53 1.15 

Grand Canyon ............................................................................................................... 1 .07 1.07 0.95 0.66 

Great Sand Dunes ......................................................................................................... 1 .02 1.02 1.02 0.62 

La Garita ........................................................................................................................ 1 .36 1.36 1.08 0.58 

Maroon Bells .................................................................................................................. 1 0.81 0.66 0.35 

Mesa Verde ................................................................................................................... 3 .17 3.14 3.01 2.73 

Pecos ............................................................................................................................. 1 .55 1.54 1.31 0.88 

Petrified Forest .............................................................................................................. 1.21 1.20 1.05 0.68 

San Pedro ...................................................................................................................... 2 .21 2.18 2.04 1.51 

West Elk ......................................................................................................................... 1 .22 1.21 1.03 0.56 

Weminuche .................................................................................................................... 1 .90 1.68 1.66 0.94 

Wheeler Peak ................................................................................................................ 1 .20 1.19 0.97 0.64 

Sum of Class I areas .............................................................................................. 26 .03 25.45 22.89 16.07 

TABLE 26—IMPACTS OF FCPP ON VISIBILITY (98TH PERCENTILE DV) ON SIXTEEN CLASS I AREAS AS MODELED BY EPA 

Baseline 

Visibility Impact (dv) after applying: 

Wet ESP LNB (C2) SCR(D) SCR (E2) 

Arches ...................................................................................................... 4.03 4.02 3.24 2.55 1.83 

Bandolier .................................................................................................. 2.91 2.90 2.25 1.81 1.38 

Black Canyon ........................................................................................... 2.36 2.36 1.89 1.44 1.01

Canyonlands ............................................................................................ 4.89 4.87 4.21 3.76 2.66

Capitol Reef ............................................................................................. 3.21 3.20 2.44 1.87 1.48 

Grand Canyon ......................................................................................... 1.63 1.63 1.31 0.96 0.81 

Great Sand Dunes ................................................................................... 1.21 1.20 0.91 0.67 0.54 

La Garita .................................................................................................. 1.71 1.71 1.28 1.05 0.73 

Maroon Bells ............................................................................................ 1.04 1.04 0.77 0.57 0.43 

Mesa Verde ............................................................................................. 6.48 6.45 5.47 4.90 3.89

Pecos ....................................................................................................... 2.11 2.10 1.65 1.34 1.06 

Petrified Forest ........................................................................................ 1.51 1.51 1.14 0.97 0.81 

San Pedro ................................................................................................ 3.81 3.80 3.13 2.53 2.01 

West Elk ................................................................................................... 1.86 1.86 1.41 1.06 0.75 

Weminuche .............................................................................................. 2.79 2.77 2.16 1.58 1.17

Wheeler Peak .......................................................................................... 1.50 1.50 1.17 0.93 0.74 

Sum of Class I areas ........................................................................ 43.05 42.90 34.43 27.99 21.29 

EPA used higher values for ammonia 

background concentration than APS, 

which resulted in higher modeled 

visibility impacts of FCPP and larger 

percent visibility improvement of 

controls compared to APS modeling. 

Although the different inputs used by 

EPA changed the absolute deciview 

values, it did not change the relative 

ranking of the controls in terms of 

deciview benefit. The different natural 

background concentrations EPA used 

compared to APS did not significantly 

change the visibility modeling results. 

In their March 16, 2009 letter to EPA, 

the USFS discusses the need for a more 

comprehensive characterization of a 

facility’s impacts, particularly, for 

facilities like FCPP and NGS that affect 

visibility at multiple Class I areas. To 

account for cumulative impacts, the 

USFS suggested accounting for the total 

dv impact by summing across all days 

for all Class I areas. EPA agrees that 

alternative visibility metrics may assist 

in evaluating the visibility improvement 

associated with various control options 

at FCPP and NGS, including taking an 

average of the 98th percentile of all 

Class I areas or summing over all days 

for all Class I areas. Table 27 presents 

an alternative visibility metric that takes 

into account the size of the area over 

which controls provide visibility 

benefits. The 98th percentile for each 

Class I area is multiplied by its land area 

in km2 and then summed. EPA is 

requesting comment on this, and other 

alternative visibility metrics. These 

metrics can then be used as an adjunct 

to cost effectiveness expressed in $/ton 

to assist EPA in evaluating the 

effectiveness of controls at FCPP and 

NGS on visibility improvement, as 

expressed in terms of dollar per 

deciview ($/dv) or $/dv-km2. 


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TABLE 27—ALTERNATIVE VISIBILITY METRIC

A (Baseline) 

Visibility Impact (dv-km2) after applying: 

B (Wet ESP) C2 (LNB) D (SCR 3–5) E2 (SCR 1–5) 

Arches .................................................................................. 1,014 1,012 816 615 461 

Bandolier .............................................................................. 249 246 193 156 119 

Black Canyon ....................................................................... 121 121 89 76 53 

Canyon-lands ....................................................................... 4,991 4,964 4,419 3,961 2,794 

Capitol Reef ......................................................................... 2,433 2,427 1,849 1,405 1,113 

Grand Canyon ...................................................................... 6,443 6,416 4,870 3,714 3,174 

Great Sand Dunes ............................................................... 119 119 88 69 56 

La Garita .............................................................................. 699 697 518 394 295 

Maroon Bells ........................................................................ 571 569 415 315 238 

Mesa Verde .......................................................................... 1,112 1,109 939 818 666 

Pecos ................................................................................... 1,574 1,570 1,225 974 780 

Petrified Forest ..................................................................... 469 467 374 322 259 

San Pedro ............................................................................ 505 503 430 347 265 

West Elk ............................................................................... 2,996 2,988 2,221 1,614 1,207 

Weminuche .......................................................................... 1,525 1,522 1,170 860 636 

Wheeler Peak ...................................................................... 121 121 92 74 59 

Sum over all areas ....................................................... 24,943 24,852 19,708 15,716 12,175 

2. NGS 

a. Visibility Modeling Scenarios 

SRP conducted visibility modeling for 

NGS using CALPUFF based on 

estimated emission rates of various 

pollutants as inputs for the model. EPA 

conducted its own CALPUFF modeling 

using inputs that we determined were 

more representative. 

EPA then modeled anticipated 

visibility improvements for four 

different options for installed control 

technologies. NGS’s and EPA’s 

modeling inputs are set forth in Tables 

28–32 below. The modeling scenarios 

are: 

A. Baseline Visibility Impact (modeled by 

NGS and EPA), 

B. LNB + SOFA on Units 1–3 (modeled by 

NGS and EPA), 

C. SCR + LNB + SOFA on Units 1 and 3, 

LNB + SOFA on Unit 2 (modeled by NGS and 

EPA), 

D. SCR + LNB + SOFA on Units 1 and 3, 

Half-SCR + LNB + SOFA on Unit 2 (modeled 

by EPA), 

E. SCR on Units 1–3 (modeled by NGS and 

EPA). 

Scenarios C and E modeled by SRP 

and EPA were not listed as discrete 

modeling scenarios as they were for 

FCPP because the emission inputs for 

NGS from SRP and EPA, though 

different for PM fine and SO4, are more 

similar to each other in terms of NOX

control than for FCPP. For Scenario E, 

SRP assumed NOX emissions to be 0.08 

lb/MMBtu, whereas EPA assumed 0.06 

lb/MMBtu. 

b. EPA Modifications to Emission Rate 

Inputs 

Similar to FCPP, for the baseline and 

non-SCR emissions scenarios (Scenarios 

A and B), the main difference between 

SRP and EPA calculations for H2SO4

were from the assumed loss of H2SO4 in 

the air preheater. SRP used a 

penetration factor of 0.9 whereas EPA 

used a penetration factor of 0.49, which 

is consistent with the 2008 EPRI 

guidelines. Similarly for H2SO4

emissions resulting from the SCR 

scenarios, EPA used a 0.5% SO2 to SO3

conversion rate based on the application 

of an ultra-low oxidation catalyst. 

For all modeling scenarios, EPA 

included HCl and HF emissions as PM 

fine modeling inputs and scaled them in 

a similar manner described for FCPP. 

For HCl, EPA used a scaled emission 

factor of 0.0025 lb/MMBtu, and for HF, 

EPA used a scaled emission factor of 

0.00086 lb/MMBtu. 

TABLE 28—SRP AND EPA BASELINE EMISSION RATES (SCENARIO A) 

Unit 1 Unit 2 Unit 3 

SRP Baseline Modeling Inputs (in lb/hr) 

SO2 .............................................................................................................................................. 487.75 526.92 576.17 

SO4 .............................................................................................................................................. 4.18 4.48 4.36 

NOX .............................................................................................................................................. 4,271.42 4,207.50 4,181.67 

SOA ............................................................................................................................................. 35.18 37.69 36.63 

PM fine ......................................................................................................................................... 63.86 55.27 79.28 

PM coarse .................................................................................................................................... 86.89 75.20 107.87 

EC ................................................................................................................................................ 2.45 2.12 3.05 

EPA Baseline Modeling Inputs (in lb/hr) 

SO2 .............................................................................................................................................. 487.75 526.92 576.17 

SO4 .............................................................................................................................................. 3.62 3.87 3.76 

NOX .............................................................................................................................................. 4,271.42 4,207.50 4,181.67 

SOA ............................................................................................................................................. 35.18 37.69 36.63 

PM fine ......................................................................................................................................... 93.41 86.93 110.05 

PM coarse .................................................................................................................................... 86.89 75.20 107.87 


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TABLE 28—SRP AND EPA BASELINE EMISSION RATES (SCENARIO A)—Continued 

Unit 1 Unit 2 Unit 3 

EC ................................................................................................................................................ 2.45 2.12 3.05 

TABLE 29—SRP AND EPA EMISSIONS FOR LNB + SOFA (SCENARIO B) 

Unit 1 Unit 2 Unit 3 

SRP Baseline Modeling Inputs (in lb/hr) 

SO2 .............................................................................................................................................. 487.75 526.92 576.17 

SO4 .............................................................................................................................................. 4.18 4.48 4.36 

NOX .............................................................................................................................................. 2,110.74 2,261.63 2,197.78 

SOA ............................................................................................................................................. 35.18 37.69 36.63 

PM fine ......................................................................................................................................... 63.86 55.27 79.28 

PM coarse .................................................................................................................................... 86.89 75.20 107.87 

EC ................................................................................................................................................ 2.45 2.12 3.05 

EPA Baseline Modeling Inputs (in lb/hr) 

SO2 .............................................................................................................................................. 487.75 526.92 576.17 

SO4 .............................................................................................................................................. 3.62 3.87 3.76 

NOX .............................................................................................................................................. 2,110.74 2,261.63 2,197.78 

SOA ............................................................................................................................................. 35.18 37.69 36.63 

PM fine ......................................................................................................................................... 93.41 86.93 110.05 

PM coarse .................................................................................................................................... 86.89 75.20 107.87 

EC ................................................................................................................................................ 2.45 2.12 3.05 

TABLE 30—SRP AND EPA EMISSIONS FOR SCR + LNB + SOFA ON UNITS 1 AND 3, LNB + SOFA ON UNIT 2 

(SCENARIO C) 

Unit 1 Unit 2 Unit 3 

SRP Baseline Modeling Inputs (in lb/hr) 

SO2 .............................................................................................................................................. 487.75 526.92 576.17 

SO4 .............................................................................................................................................. 64.01 4.48 66.65 

NOX .............................................................................................................................................. 703.58 2,261.63 732.59 

SOA ............................................................................................................................................. 35.18 37.69 36.63 

PM fine ......................................................................................................................................... 63.86 55.27 79.28 

PM coarse .................................................................................................................................... 86.89 75.20 107.87 

EC ................................................................................................................................................ 2.45 2.12 3.05 

EPA Baseline Modeling Inputs (in lb/hr) 

SO2 .............................................................................................................................................. 487.75 526.92 576.17 

SO4 .............................................................................................................................................. 19.90 3.87 20.72 

NOX .............................................................................................................................................. 615.63 2,261.63 641.02 

SOA ............................................................................................................................................. 35.18 37.69 36.63 

PM fine ......................................................................................................................................... 93.41 86.93 110.05 

PM coarse .................................................................................................................................... 86.89 75.20 107.87 

EC ................................................................................................................................................ 2.45 2.12 3.05 

TABLE 31—EPA EMISSIONS FOR SCR + LNB + SOFA ON UNITS 1 AND 3, HALF-SCR + LNB + SOFA ON UNIT 2 

(SCENARIO D) 

Unit 1 Unit 2 Unit 3 

EPA Baseline Modeling Inputs (in lb/hr) 

SO2 .............................................................................................................................................. 487.75 526.92 576.17 

SO4 .............................................................................................................................................. 19.90 12.60 20.72 

NOX .............................................................................................................................................. 615.63 1,696.22 641.02 

SOA ............................................................................................................................................. 35.18 37.69 36.63 

PM fine ......................................................................................................................................... 93.41 86.93 110.05 

PM coarse .................................................................................................................................... 86.89 75.20 107.87 

EC ................................................................................................................................................ 2.45 2.12 3.05 


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TABLE 32—SRP AND EPA EMISSIONS FOR SCR + LNB + SOFA ON UNITS 1—3 (SCENARIO E) 

Unit 1 Unit 2 Unit 3 

SRP Baseline Modeling Inputs (in lb/hr) 

SO2 .............................................................................................................................................. 487.75 526.92 576.17 

SO4 .............................................................................................................................................. 64.01 68.59 66.65 

NOX .............................................................................................................................................. 703.58 753.88 732.59 

SOA ............................................................................................................................................. 35.18 37.69 36.63 

PM fine ......................................................................................................................................... 63.86 55.27 79.28 

PM coarse .................................................................................................................................... 86.89 75.20 107.87 

EC ................................................................................................................................................ 2.45 2.12 3.05 

EPA Baseline Modeling Inputs (in lb/hr) 

SO2 .............................................................................................................................................. 487.75 526.92 576.17 

SO4 .............................................................................................................................................. 19.90 21.32 20.72 

NOX .............................................................................................................................................. 615.63 659.64 641.02 

SOA ............................................................................................................................................. 35.18 37.69 36.63 

PM fine ......................................................................................................................................... 93.41 86.93 110.05 

PM coarse .................................................................................................................................... 86.89 75.20 107.87 

EC ................................................................................................................................................ 2.45 2.12 3.05 

c. Ammonia Background and Natural 

Background 

For ammonia background values at 

the Class I areas impacted by NGS, EPA 

used the same ammonia values listed in 

Table 22 above and the same natural 

background values listed in Table 23. 

See discussion of ammonia backcalculation methodologies and changes 

to natural background conditions 

described in Section II.B.1. 

d. Visibility Modeling Results 

To assess results from the CALPUFF 

model and post-processing steps, EPA 

used a least-squares regression analysis 

of all visibility modeling output from 

the 2001–2003 modeling period to 

determine the percent improvement in 

visibility compared to the baseline 

resulting from the application of control 

technologies. Table 33 shows EPA’s 

modeled predicted visibility 

improvements at the 11 Class I areas 

within a 300 km radius of NGS. 

SRP presented visibility improvement 

by comparing the 98th percentile (8th 

highest) of daily maximum deciview 

(dv) values from CALPUFF per Class I 

area, averaged over 2001–2003. Table 34 

presents the visibility impacts of the 

98th percentile of daily maxima for each 

Class I area for each year, averaged over 

2001–2003, determined for NGS by SRP. 

Table 35 presents the visibility 

impacts of the 98th percentile of daily 

maxima over 2001–2003 for each Class 

I area determined by EPA. Table 36 

presents the alternative visibility metric 

determined by EPA for each Class I area. 

TABLE 33—PERCENT IMPROVEMENT IN DECIVIEW IMPACTS FROM EPA MODELING AT EACH CLASS I AREA FROM NOX

CONTROLS AT NGS 

Scenario B 

(LNB) 

(percent) 

Scenario C 

(SCR: 1&3) 

(percent) 

Scenario D 

(1⁄2 SCR 2) 

(percent) 

Scenario E 

(SCR: 1–3) 

(percent) 

Arches .............................................................................................................. 36 60 65 74

Bryce Canyon .................................................................................................. 26 47 53 63 

Canyonlands .................................................................................................... 32 56 62 71 

Capitol Reef ..................................................................................................... 25 48 53 63 

Grand Canyon ................................................................................................. 22 43 48 58 

Mazatzal ........................................................................................................... 38 60 65 72 

Mesa Verde ..................................................................................................... 40 63 68 76 

Petrified Forest ................................................................................................ 36 60 65 74 

Pine Mountain .................................................................................................. 38 59 64 71 

Sycamore Canyon ........................................................................................... 36 59 64 72 

Zion .................................................................................................................. 31 54 60 69 

TABLE 34—VISIBILITY IMPACTS (98TH PERCENTILE DV) OF NGS ON ELEVEN CLASS I AREAS AS MODELED BY SRP 

Baseline 

Visibility Impact (dv) after applying: 

LNB (B) SCR (C) SCR (E) 

Arches .............................................................................................................. 2.05 1.51 1.19 0.99 

Bryce Canyon .................................................................................................. 2.00 1.58 1.36 1.23 

Canyonlands .................................................................................................... 2.47 1.96 1.53 1.35 

Capitol Reef ..................................................................................................... 2.68 2.31 2.06 1.89 

Grand Canyon ................................................................................................. 2.56 2.29 2.25 2.29 

Mazatzal ........................................................................................................... 0.71 0.47 0.41 0.38 

Mesa Verde ..................................................................................................... 1.42 1.04 0.77 0.58 


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TABLE 34—VISIBILITY IMPACTS (98TH PERCENTILE DV) OF NGS ON ELEVEN CLASS I AREAS AS MODELED BY SRP— 

Continued 

Baseline 

Visibility Impact (dv) after applying: 

LNB (B) SCR (C) SCR (E) 

Petrified Forest ................................................................................................ 1.52 1.14 0.92 0.76 

Pine Mountain .................................................................................................. 0.66 0.46 0.38 0.34 

Sycamore Canyon ........................................................................................... 1.31 0.92 0.78 0.63 

Zion .................................................................................................................. 1.83 1.47 1.26 1.10 

Sum of Class I areas ................................................................................ 19.29 15.15 12.88 11.54 

TABLE 35—VISIBILITY IMPACTS (98TH PERCENTILE DV) OF NGS ON ELEVEN CLASS I AREAS AS MODELED BY EPA 

Baseline 

Visibility Impact (dv) after applying: 

LNB (B) SCR (C) SCR (D) SCR (E) 

Arches .................................................................................. 3.25 2.08 1.33 1.16 0.89 

Bryce Canyon ...................................................................... 3.66 2.44 1.57 1.39 1.10 

Canyonlands ........................................................................ 4.37 2.98 1.90 1.65 1.25 

Capitol Reef ......................................................................... 5.48 4.08 2.97 2.71 2.04 

Grand Canyon ...................................................................... 5.41 4.35 3.34 3.06 2.46 

Mazatzal ............................................................................... 1.16 0.73 0.48 0.45 0.37 

Mesa Verde .......................................................................... 2.24 1.33 0.78 0.67 0.52 

Petrified Forest ..................................................................... 2.62 1.54 1.00 0.86 0.66 

Pine Mountain ...................................................................... 1.08 0.64 0.42 0.38 0.32 

Sycamore Canyon ............................................................... 1.96 1.28 0.80 0.71 0.59 

Zion ...................................................................................... 3.73 2.65 1.65 1.44 1.05 

Sum of Class I areas .................................................... 34.95 24.10 16.25 14.48 11.23 

TABLE 36—ALTERNATIVE VISIBILITY METRIC

A (Baseline) 

Visibility Impact (dv-km2) after applying: 

B (LNB) C (SCR: 1&3) D (1⁄2 SCR 2) E (SCR: 1–3) 

Arches .................................................................................. 812 514 336 293 223 

Bryce Canyon ...................................................................... 495 324 212 187 147 

Canyonlands ........................................................................ 4,649 3,071 2,022 1,741 1,320 

Capitol Reef ......................................................................... 4,184 3,127 2,233 2,031 1,566 

Grand Canyon ...................................................................... 21,399 17,219 13,157 12,033 9,698 

Mazatzal ............................................................................... 978 618 410 367 297 

Mesa Verde .......................................................................... 383 226 135 115 87 

Petrified Forest ..................................................................... 847 515 313 270 217 

Pine Mountain ...................................................................... 72 44 28 25 22 

Sycamore Canyon ............................................................... 390 235 162 144 120 

Zion ...................................................................................... 1,574 1,104 739 649 494 

Sum over all areas ....................................................... 24,943 19,708 19,708 15,716 19,708 

C. Factor 2: Energy and Non-Air Quality 

Impacts 

1. FCPP 

The application of LNB and LNB + 

OFA to control NOX by staging 

combustion to reduce boiler 

temperatures will result in reduced NOX

formation as well as reduced 

combustion efficiency. The reduced 

combustion temperatures thus result in 

increased emissions of carbon monoxide 

(CO), volatile organic compounds 

(VOCs), and increased unburned carbon 

in the fly ash, known as loss of ignition 

(LOI). Increases in CO, and potential 

increases in VOC, from LNB or LNB + 

OFA, may trigger the Prevention of 

Significant Deterioration (PSD) 

permitting requirements, including the 

application of Best Available Control 

Technology (BACT) if the emission 

increases exceed the 100 tpy CO and 40 

tpy VOC significance thresholds. 

Increased LOI in fly ash may reduce the 

desirability of the fly ash for sale and 

reuse. 

Emissions of sulfuric acid (H2SO4) 

from coal fired power plants result from 

the conversion of sulfur in the coal into 

SO2 and further oxidation to SO3 during 

the combustion process in the boiler. 

SO3 can then combine with moisture 

(H2O) in the flue gas to form H2SO4. 

Fuels high in vanadium can catalyze 

SO2 to SO3 at higher rates than low 

vanadium fuels and result in higher 

H2SO4 emissions. The use of SCR 

catalysts, in particular, SCR catalysts 

that use vanadium, can result in 

increased emissions of H2SO4. 

Emissions increases in H2SO4 at existing 

major stationary sources as a result of 

the application of SCR for NOX control 

will trigger PSD permitting 

requirements, including the application 

of BACT, if they exceed the H2SO4

significance threshold of 7 tpy. Add-on 

control technologies exist to help reduce 

H2SO4 emissions following SO2 to SO3

conversion from combustion and SCR, 


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including injection of reagents (e.g., 

hydrated lime, sodium bisulfite) to 

convert H2SO4 to particulate matter that 

is then captured by downstream PM 

control devices, such as baghouses. 

Based on discussions with URS 

Corporation, the commercial vendor for 

sodium bisulfite (SBS) injection 

technology, the expected low 

concentrations of H2SO4 at FCPP, 

compared to coal-fired facilities in the 

Midwestern and Eastern states, suggests 

the application of reagent injection will 

not effectively reduce H2SO4 emissions 

from FCPP. Based on a recent PSD 

permit issued to the Coronado 

Generating Station in Arizona, the use 

of an ultra-low conversion catalyst 

(achieving no more than 0.5% SO2 to 

SO3 conversion) currently represents 

BACT. 

In addition to the impact of SCR on 

H2SO4 emissions, the application of SCR 

reduces the energy efficiency of the 

facility by increasing parasitic load from 

the use of additional fans to overcome 

increased resistance created by SCR. 

2. NGS 

As described above, the use of LNB + 

SOFA for NOX control results in 

potential increases in emissions of CO 

and VOC, and increased LOI of fly ash. 

Additionally, the impacts associated 

with SCR, i.e., H2SO4 emissions 

increases, the limited efficacy of reagent 

injection for H2SO4 control, and energy 

impacts, also apply to NGS. NGS 

additionally identified another concern 

related to SCR resulting from the need 

for daily deliveries by tanker truck of 

anhydrous ammonia for the SCR system. 

D. Factor 3: Existing Controls at the 

Facility 

1. FCPP 

Existing controls at FCPP are shown 

in Table 37. 

TABLE 37—EXISTING AIR POLLUTION CONTROLS AT FCPP 

NOX control PM control SO2 control 

Unit 1 .................................. none ................................... Venturi Scrubber (VS) ................................................... VS. 

Unit 2 .................................. LNB .................................... VS—Lime ...................................................................... VS—Lime. 

Unit 3 .................................. LNB .................................... VS—Lime ...................................................................... VS—Lime. 

Unit 4 .................................. LNB .................................... Reverse Gas Fabric Filter (Baghouse) ......................... Tray Tower Flue Gas 

Desulfurization (FGD). 

Unit 5 .................................. LNB .................................... Baghouse ...................................................................... Tray Tower FGD. 

a. Existing NOX Controls at FCCP 

For the SCR control case, EPA 

conducted visibility modeling for FCPP 

(Table 21, Scenario E2) without the 

addition of LNB + OFA, whereas APS 

modeled an SCR control case assuming 

LNB + OFA could provide further 

control of NOX emissions (Scenario E1). 

FCPP emits more NOX than any other 

coal-fired power plant in the U.S. This 

is due to both the size of the facility and 

the high average concentration of NOX

emitted from each unit. Every unit at 

FCPP emits NOX at a higher 

concentration than any other unit in 

Region IX. 

The potential for successfully 

obtaining significant reductions of NOX

using only combustion controls, such as 

LNB, at this facility is limited. The 

fireboxes for Units 1, 2 and 3 are 

considered to be too small to effectively 

utilize modern approaches to low NOX

combustion which require separated 

overfire air. 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 of 0.8 lb/ 

MMBtu. Due to their small size, EPA 

has determined that a retrofit of Units 1 

and 2 with LNB and Unit 3 with LNB 

+ OFA will not provide significant NOX

control. 

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 these burners were replaced 

in the 1980s, the design of a cell burner 

boiler limits the NOX reduction that can 

be achieved with modern low NOX

combustion techniques. EPA has set 

different presumptive levels 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. EPA is 

requesting comment on the potential 

efficacy of LNB + OFA on all Units at 

FCPP. 

b. Existing PM Controls at FCCP 

Units 1, 2, and 3 utilize venturi 

scrubbers for both PM and 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 IX since 

the early 1970s. This was principally 

due to concerns over the ability of 

venturi scrubbers to continuously meet 

the 0.10 lb/MMBtu standard in a 1971 

regulation. 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. Most current coal fired boilers 

now use baghouses which are capable of 

meeting PM limits of about 0.01 to 0.012 

lb/MMBtu (Method 5 front half PM 

measurement). 

In Region IX, all other coal fired EGUs 

controlled by venturi scrubbers have 

been retrofit with new PM controls. Unit 

1 at APS’s Cholla power plant was 

retrofit with a baghouse in 2007, in 

order to meet a new 20% opacity 

standard established by the ADEQ. APS 

received an extended compliance 

schedule for meeting that opacity 

standard to allow for the installation of 

the new baghouse. Three units at the 

Nevada Energy Reid Gardner facility 

also have venturi scrubbers for PM 

control. These units are required by a 

consent decree between Nevada Energy, 

and Nevada Department of 

Environmental Protection and EPA, to 

install new baghouses in 2010. EPA is 

requesting comment on whether the 

existing controls on Units 1–3 at FCPP 

meet BART for PM. 

2. NGS 

Existing controls at NGS are shown in 

Table 38. 


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29On November 20, 2008, EPA Region IX issued 

a PSD permit authorizing NGS to modify Units 1– 

3 with LNB + SOFA over 2009–2011. 

TABLE 38—EXISTING AIR POLLUTION CONTROLS AT NGS 

NOX control PM control SO2 control 

Units 1–3 ................................................... LNB + SOFA29 ......................................... Hot-side ESP ............................................ Wet FGD 

E. Factor 4: Remaining Useful Life of 

Facility 

1. FCPP 

The remaining useful life of the 

facility is often expressed in terms of the 

amortization period used to annualize 

the costs of control. In its analysis, APS 

used an amortization period of 20 years, 

anticipating that the remaining useful 

life of Units 1–5 is at least 20 years. 

EPA is requesting comment on the use 

of this period of time for the remaining 

useful life of FCPP. 

2. NGS 

In its analysis, SRP used an 

amortization period of 20 years, 

anticipating that the remaining useful 

life of Units 1–3 is at least 20 years. 

EPA is also requesting comment on 

the use of this period of time for the 

remaining useful life of NGS. 

III. Statutory and Executive Order 

Reviews 

Under Executive Order 12866, 

entitled Regulatory Planning and 

Review (58 FR 51735, October 4, 1993), 

this is not a ‘‘significant regulatory 

action.’’ Because this action does not 

propose or impose any requirements, 

the various statutes and Executive 

Orders that apply to rulemaking do not 

apply in this case. In addition, this 

notice covers two facilities. Any future 

rulemaking would be separate, one for 

each facility. Determinations of 

significance and applicability of any 

Executive Order or statute would 

depend upon the content of each 

individual rulemaking. Should EPA 

subsequently determine to pursue 

rulemaking and propose BART for these 

facilities, EPA will address the statutes 

and Executive Orders as applicable to 

those individual proposed actions. 

Nevertheless, the Agency welcomes 

comments and/or information that 

would help the Agency to assess any of 

the following: tribal implications 

pursuant to Executive Order 13175, 

entitled Consultation and Coordination 

with Indian Tribal Governments (65 FR 

67249, November 6, 2000); 

environmental health or safety effects 

on children pursuant to Executive Order 

13045, entitled Protection of Children 

from Environmental Health Risks and 

Safety Risks (62 FR 19885, April 23, 

1997); energy effects pursuant to 

Executive Order 13211, entitled Actions 

Concerning Regulations that 

Significantly Affect Energy Supply, 

Distribution, or Use (66 FR 28355, May 

22, 2001); Paperwork burdens pursuant 

to the Paperwork Reduction Act (PRA) 

(44 U.S.C. 3501); or human health or 

environmental effects on minority or 

low-income populations pursuant to 

Executive Order 12898, entitled Federal 

Actions to Address Environmental 

Justice in Minority Populations and 

Low-Income Populations (59 FR 7629, 

February 16, 1994). The Agency will 

consider such comments during the 

development of any subsequent 

rulemaking. 

List of Subjects in 40 CFR Part 52 

Environmental protection, Air 

pollution control, Oxides of nitrogen, 

Particulate matter, Regional haze. 

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

Dated: August 19, 2009. 

Laura Yoshii, 

Acting Regional Administrator, Region IX. 

[FR Doc. E9–20826 Filed 8–27–09; 8:45 am] 

BILLING CODE 6560–50–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R09–OAR–2009–0385; FRL–8948–5] 

Revisions to the California State 

Implementation Plan, San Joaquin 

Valley Unified Air Pollution Control 

District and Santa Barbara County Air 

Pollution Control District 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: EPA is proposing to approve 

revisions to the San Joaquin Valley 

Unified Air Pollution Control District 

(SJVUAPCD) and the Santa Barbara 

County Air Pollution Control 

(SBCAPCD) portions of the California 

State Implementation Plan (SIP). We are 

proposing to approve these local rules 

that are administrative and address 

changes for clarity and consistency 

under the Clean Air Act as amended in 

1990 (CAA or the Act). 

DATES: Any comments on this proposal 

must arrive by September 28, 2009. 

ADDRESSES: Submit comments, 

identified by docket number EPA–R09– 

OAR–2009–0385, by one of the 

following methods: 

1. Federal eRulemaking Portal: 

http://www.regulations.gov. Follow the 

on-line instructions. 

2. E-mail: steckel.andrew@epa.gov. 

3. Mail or deliver: Andrew Steckel 

(Air-4), 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 e-mail 

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. 

Electronic files should avoid the use of 

special characters, any form of 

encryption, and be free of any defects or 

viruses. 

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: 

Cynthia G. Allen, EPA Region IX, (415) 

947–4120, allen.cynthia@epa.gov. 


jlentini on DSKJ8SOYB1PROD with PROPOSALS