### 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– TC–1947 through TC–

B55A. 2456. A36 ..................... E–825 through E–2578. B36TC ................ EA–242 and EA–273 through EA–509. Model

E55, E55A ..........

F33A ...................

V35B .................. Serial Nos. (SNs)

TE–1078 through TE–

1201. CE–634 through CE–

1536. 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.

(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 correctmetal, inner and outer diameter, and thickness, replace the incorrect washer with part number 100951X060YA washer. (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.Before further flight, after the inspection required by paragraph (e)(1) of this AD. Follow Beechcraft Mandatory Service Bulletin No. 2394, dated December 1990.

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)VerDate Nov<24>2008 17:19 Aug 27, 2009 Jkt 217001 PO 00000 Frm 00015 Fmt 4702 Sfmt 4702 E:\FR\FM\28AUP1.SGM 28AUP1jlentini on DSKJ8SOYB1PROD with PROPOSALS 

## 44314 Federal Register / Vol. 74, No. 166 / Friday, August 28, 2009 / Proposed Rules

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 isan ‘‘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 NO X 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 (40VerDate Nov<24>2008 17:19 Aug 27, 2009 Jkt 217001 PO 00000 Frm 00016 Fmt 4702 Sfmt 4702 E:\FR\FM\28AUP1.SGM 28AUP1jlentini on DSKJ8SOYB1PROD with PROPOSALS 

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

## 44315

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

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). 

### 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 NavajoNation. 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 NO X 

### emissions in the United States (nearly 45,000 tons per year (tpy) of NO X

### ).

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 SandDunes 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

2 ‘‘Clean Air Markets—Data and Maps’’ at http://camddataandmaps.epa.gov/gdm/.VerDate Nov<24>2008 17:19 Aug 27, 2009 Jkt 217001 PO 00000 Frm 00017 Fmt 4702 Sfmt 4702 E:\FR\FM\28AUP1.SGM 28AUP1jlentini on DSKJ8SOYB1PROD with PROPOSALS 

## 44316 Federal Register / Vol. 74, No. 166 / Friday, August 28, 2009 / Proposed Rules

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 ofFlagstaff, 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 NO X 

### 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 NO X 

### 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. NO X 

### and ammonia are two examples of precursors to secondary PM.

NO X 

### 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 SO 2 

### 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 NO X 

### and in Table 2 for four different levels of control options to reduce PM on Units 1–3. The NO X 

### control technology options in Table 1 are: (1) Low NO X 

### 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 C OSTS OF 

### C OMPLIANCE FOR 

### NOX 

### BASED ON 

### APS’ S 

### A NALYSIS

LNB/LNB + OFA 5SCR SCR + LNB SCR + LNB + OFA

**Total Capital Investment**

Unit 1 ... Unit 2

... Unit 3

... Unit 4

... $4,109,000 4,109,000 4,701,000 15,260,000 $110,664,000 119,010,000 113,084,000 265,406,000 $111,609,000 121,066,000 115,420,000 273,892,000 $112,058,000 121,496,000 114,851,000 279,444,000

3 Guidance for Estimating Natural Visibility 03–005, September 2003; http://www.epa.gov/ttn/ 4 PM emissions from Units 4 and 5 at FCPP are Conditions Under the Regional Haze Rule, U.S. oarpg/t1pgm.html. already controlled by baghouses. Environmental Protection Agency’’, EPA–454/B–VerDate Nov<24>2008 17:19 Aug 27, 2009 Jkt 217001 PO 00000 Frm 00018 Fmt 4702 Sfmt 4702 E:\FR\FM\28AUP1.SGM 28AUP1jlentini on DSKJ8SOYB1PROD with PROPOSALS 

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

## 44317

TABLE 

### 1—FCPP C OSTS OF 

### C OMPLIANCE FOR 

### NOX 

### BASED ON 

### APS’ S 

### A NALYSIS

### —Continued

LNB/LNB + OFA 5SCR SCR + LNB SCR + LNB + OFA

Unit 5

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

**Total Annual Costs**

Unit 1

... Unit 2 ... Unit 3 ... Unit 4 ... Unit 5 ... $922,000 922,000 1,055,000 3,447,000 3,447,000 $22,297,000 23,634,000 23,173,000 55,755,000 55,755,000 $21,764,000 23,468,000 23,010,000 56,883,000 56,883,000 $21,685,000 23,385,000 22,729,000 57,237,000 57,237,000



### TABLE 

### 2—FCPP C OSTS OF 

### C OMPLIANCE FOR 

### PM BASED ON 

### APS’ S 

### A NALYSIS

Upstream 6 ESP Upstream baghouse Wet metal ESP Wet membrane ESP

Unit 1

... Unit 2 ... Unit 3 ... $37,236,000 45,702,000 40,135,000 $50,515,000 60,992,000 59,594,000 $32,136,000 32,879,000 59,594,000 7 $23,360,000 23,901,000 26,988,000 **Total Capital Investment**

**Total Annual Costs**

Unit 1 ... Unit 2 ... Unit 3 ... $10,169,000 11,011,000 10,925,000 $13,950,000 14,481,000 16,559,000 $8,781,000 8,972,000 10,309,000 $5,652,000 6,658,000 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 NO X 

### 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 NO X 

### emissions reductions by starting with baseline emission rates of NO X 

### of: 0.78 pounds of NO X 

### 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
0.49lb/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 NO X 

### 45% and 33%, respectively and LNB + OFA on Units 3, and 4–5 would reduce NO X 

### 44% and 29%, respectively; (2)SCR on Units 1–5 would reduce NO X 

### approximately 88–91%; (3) SCR + LNB on Units 1–5 would reduce NO X 

### by 88– 93%; and (4) SCR + LNB + OFA on Units 1–5 would reduce NO X 

### by approximately 88—93%. APS estimated PM emissions reductions using baseline emission rates of PM of: 0.025 lb/MMBtu for Unit 1;
0.029lb/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 NO X 

### 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 E MISSIONS 

### R EDUCTIONS AND 

### C OST 

### E FFECTIVENESS FOR 

### NOX

LNB/LNB + OFA 8SCR SCR + LNB SCR + LNB + OFA

**Tons of NO** X **Reduced per Year (tpy)**

Unit 1

... Unit 2

... Unit 3

... Unit 4 ... Unit 5 ... 2,569 1,573 2,465 3,798 3,798 5,138 4,344 5,025 11,665 11,665 5,285 4,344 5,025 11,665 11,665 5,285 4,344 5,023 11,665 11,665
**Cost Effectiveness of Controls ($/ton)**

Unit 1 ... Unit 2 ... Unit 3 ... 359 586 428 4,343 5,484 4,582 4,118 5,403 4,579 4,103 5,384 4,523

5 Capital and annual cost values are for LNB on 7 This estimate was reported by APS in their a wet ESP would equal the cost of a baghouse for Units 1 and 2, and LNB + OFA on Units 3–5. December 2007 analysis. EPA believes this value Unit 3, but not Units 1 and 2.

6 Upstream refers to a location before the existing was reported by APS in error because it is unlikely venturi scrubbers.VerDate Nov<24>2008 17:19 Aug 27, 2009 Jkt 217001 PO 00000 Frm 00019 Fmt 4702 Sfmt 4702 E:\FR\FM\28AUP1.SGM 28AUP1jlentini on DSKJ8SOYB1PROD with PROPOSALS 

## 44318 Federal Register / Vol. 74, No. 166 / Friday, August 28, 2009 / Proposed Rules

TABLE 

### 3—FCPP E MISSIONS 

### R EDUCTIONS AND 

### C OST 

### E FFECTIVENESS FOR 

### NOX

### —Continued

LNB/LNB + OFA 8SCR SCR + LNB SCR + LNB + OFA

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



### TABLE 

### 4—FCPP E MISSIONS 

### R EDUCTIONS AND 

### C OST 

### E FFECTIVENESS FOR 

### PM

Upstream ESP Upstream baghouse Wet metal ESP Wet membrane ESP

Unit 1

... Unit 2

... Unit 3

... 95 127 161 95 127 161 95 127 161 95 127 161 **Tons of PM Reduced per Year (tpy)**

**Cost Effectiveness of Controls ($/ton)**

Unit 1 ... Unit 2 ... Unit 3 ... 106,571 86,485 67,785 146,195 113,739 102,741 92,024 70,470 63,963 59,233 52,294 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 NO X 

### 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 NO X 

### 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 C OSTS OF 

### C OMPLIANCE FOR 

### NOX 

### BASED ON 

### EPA R EVISIONS

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

**Total Annual Costs**

Unit 1 ....................................................................................... Unit 2 ....................................................................................... Unit 3 ....................................................................................... Unit 4 ....................................................................................... Unit 5 ....................................................................................... $616,350 616,350 705,150 2,289,000 2,289,000 $16,599,600 17,851,500 16,962,600 39,810,900 39,810,900 $16,741,350 18,159,900 17,313,000 39,810,900 39,810,900 $ 16,808,700 18,2 24,400 17,2 27,650 41 ,916,600 41 ,916,600

8 Capital and annual cost values are for LNB on Units 1 and 2, and LNB + OFA on Units 3–5.VerDate Nov<24>2008 17:19 Aug 27, 2009 Jkt 217001 PO 00000 Frm 00020 Fmt 4702 Sfmt 4702 E:\FR\FM\28AUP1.SGM 28AUP1jlentini on DSKJ8SOYB1PROD with PROPOSALS 

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

## 44319

TABLE 

### 6—FCPP C OSTS OF 

### C OMPLIANCE FOR 

### PM BASED ON 

### EPA R EVISIONS

Upstream ESP Upstream baghouse Wet metal ESP Wet membrane ESP

**Total Annual Costs**

Unit 1 ....................................................................................... Unit 2 ....................................................................................... Unit 3 ....................................................................................... $5,585,400 6,855,300 6,020,250 $7,577,250 9,148,800 8,939,100 $4,820,400 4,931,850 8,939,100 $3,504,000 3,585,150 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 NO X 

### control of approximately 90% or greater from the baseline emissions. For new facilities, 90% or greater reduction in NO X 

### 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 NO X 

### 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 NO X 

### and PM based on adjusting the annual costs, the NO X 

### control efficiency for SCR and the baseline PM emissions as discussed above.



### TABLE 

### 7—FCPP C OST 

### E FFECTIVENESS FOR 

### NOX 

### BASED ON 

### EPA R EVISIONS

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

**Tons of NO** X **Reduced per Year (tpy)**

Unit 1

....................................................................................... Unit 2

....................................................................................... Unit 3

....................................................................................... Unit 4 ....................................................................................... Unit 5 ....................................................................................... 2,478 1,524 2,563 3,275 3,284 4,417 3,716 4,652 9,171 9,195 5,097 4,210 5,224 10,060 10,086 5,097 4,210 5,224 10,060 10,086

**Cost Effectiveness of Controls ($/ton)**

Unit 1 ....................................................................................... Unit 2 ....................................................................................... Unit 3 ....................................................................................... Unit 4 ....................................................................................... Unit 5 ....................................................................................... 249 404 275 699 697 3,758 4,803 3,646 4,341 4,330 3,284 4,314 3,314 3,957 3,947 3,298 4,329 3,298 4,167 4,156



### TABLE 

### 8—FCPP C OST 

### E FFECTIVENESS FOR 

### PM BASED ON 

### EPA R EVISIONS

Upstream ESP Upstream baghouse Wet metal ESP Wet membrane ESP

**Tons of PM Reduced per Year (tpy)**

Unit 1

....................................................................................... Unit 2

....................................................................................... Unit 3

....................................................................................... 92 123 375 92 123 375 92 123 375 92 123 375

**Cost Effectiveness of Controls ($/ton)**

Unit 1

....................................................................................... Unit 2

....................................................................................... Unit 3

....................................................................................... 60,691 55,556 16,074 82,334 74,143 23,867 52,378 39,968 23,867 38,074 29,054 10,808

9 White Paper: Selective Catalytic Reduction Fired Electric Power Plants, Prepared by Institute of 10 See http://www.azdeq.gov/environ/air/permits/ (SCR) Control of NO X Emissions from Fossil Fuel- Clean Air Companies Inc., May 2009. download/pastmonth.pdf.VerDate Nov<24>2008 17:19 Aug 27, 2009 Jkt 217001 PO 00000 Frm 00021 Fmt 4702 Sfmt 4702 E:\FR\FM\28AUP1.SGM 28AUP1jlentini on DSKJ8SOYB1PROD with PROPOSALS 

## 44320 Federal Register / Vol. 74, No. 166 / Friday, August 28, 2009 / Proposed Rules

The National Park Service (NPS) NPS costs of compliance and cost the EPA Control Cost Manual are calculated the cost effectiveness of SCR effectiveness are shown in Table 9. NPS considerably lower than those estimated using only the estimates and allowed assumed post-SCR NO X 

### emissions of by APS. categories of costs from EPA’s Air 0.06 lb/MMBtu. The capital and annual Pollution Control Costs Manual. The costs of SCR the NPS estimated using



### TABLE 

### 9—NPS’ S 

### E STIMATED 

### SCR C OSTS OF 

### C OMPLIANCE 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 EPA’s annual cost estimates in Tables 5 was below the U.S. average ($0.1128/ calculated the expected increase in and 6. DOE provides information on the kWh) and the continental U.S. electricity generation costs to be borne average cost of electricity by state in a maximum of $0.1993/kWh in by consumers in terms of dollars per given year. 11 

### In 2009, the average cost Connecticut. kilowatt hour ($/kWh), assuming 85% of electricity in Arizona for residential capacity. The calculation is based on consumers was $0.0994/kWh, which



### TABLE 

### 10—I NCREASE IN 

### E LECTRICITY 

### C OSTS 

### F ROM 

### NOX 

### C ONTROLS AT 

### FCPP

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

Unit 1

....................................................................................... Unit 2

....................................................................................... Unit 3

....................................................................................... Unit 4

....................................................................................... Unit 5

....................................................................................... $0.001 0.001 0.001 0.001 0.001 $0.015 0.016 0.011 0.009 0.009 $0.015 0.016 0.012 0.009 0.009 $0.015 0.016 0.012 0.009 0.009



### TABLE 

### 11—I NCREASE IN 

### E LECTRICITY 

### C OSTS 

### F ROM 

### PM C ONTROLS AT 

### FCPP

Upstream ESP kWh Upstream baghouse

kWh Wet metal ESP kWh Wet membrane ESP kWh

Unit 1

....................................................................................... Unit 2

....................................................................................... Unit 3

....................................................................................... $0.005 0.006 0.004 $0.007 0.008 0.006 $0.004 0.004 0.006 $0.003 0.003 0.003



### EPA requests comments on the data 2. NGS NO X 

### control options included in Table used to estimate the cost of compliance 12 are (1) LNB plus Separated Overfire a. Cost of Compliance for the different levels of control for Air (SOFA) on all three units, (2) SCR The cost estimates provided by SRP NO X 

### and PM for FCPP. on Units 1 and 3, LNB + SOFA on Unit (updated in the 2008 submissions to 2, and (3) SCR + LNB + SOFA on all EPA) are included in Table 12 for three units. different control options for NO X 

### . The



### TABLE 

### 12—NGS C OSTS OF 

### C OMPLIANCE FOR 

### NOX 

### BASED ON 

### SRP A NALYSIS

SCR + LNB + SOFA LNB + SOFA (Units 1 & 3); SCR + LNB + SOFA

(All units) LNB + SOFA (All units) (Unit 2)

**Total Capital Investment**

Unit 1 ....................................................................................................................... $1 4,000,000 $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

11 http://www.eia.doe.gov/cneaf/electricity/epm/ table5

_ 6

_b.htmlVerDate Nov<24>2008 17:19 Aug 27, 2009 Jkt 217001 PO 00000 Frm 00022 Fmt 4702 Sfmt 4702 E:\FR\FM\28AUP1.SGM 28AUP1jlentini on DSKJ8SOYB1PROD with PROPOSALS 

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

## 44321

TABLE 

### 12—NGS C OSTS OF 

### C OMPLIANCE FOR 

### NOX 

### BASED ON 

### SRP A NALYSIS

### —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 retrofit are anticipated to be higher than control options, SRP estimated Unit 2 compared to Units 1 and 3 is a for Units 1 and 3. 12 

### emissions reductions from: LNB + result of the physical layout of the coal SOFA of 47–51% to achieve 0.24 lb/ b. Cost Effectiveness conveyor and its supports in relation to MMBtu; and from SCR of 82–84% to In determining the cost effectiveness Unit 2. Because of limited access for achieve 0.08 lb/MMBtu. of controls, SRP estimated NO X 

### construction cranes and equipment, and Table 13 lists the reduction in NO X 

### emissions reductions using baseline to make room for the SCR and fans by emissions and cost effectiveness emission rates of: 0.49 lb/MMBtu for demolishing the remainder of the old Unit 1; 0.45 lb/MMBtu for Unit 2; 0.46 estimated by SRP for the three control Unit 2 chimney, costs for the Unit 2 lb/MMBtu for Unit 3. For the various scenarios listed in Table 12.



### TABLE 

### 13—SRP E MISSIONS 

### R EDUCTIONS AND 

### C OST 

### E FFECTIVENESS FOR 

### NOX

LNB + SOFA

(All units) SCR + LNB + SOFA (Units 1 & 3); LNB + SOFA

(Unit 2) SCR + LNB + SOFA (All units)

**NO** X **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 ....................................................................................................................... 16 8 1,833 1,833 Unit 2 ....................................................................................................................... 18 7 187 2,419 Unit 3 ....................................................................................................................... 184 1,900 1,900



### Appendix Y of the BART Guidelines appears SRP used the same 24-hour emission rates for NO X 

### averaged over states that average cost effectiveness average actual emission rate from the 2004–2006 of: 0.35 lb/MMBtu for Unit should be based on the annualized cost highest emitting day used for its 1; 0.37 lb/MMBtu for Unit 2; 0.31 lb/ and the difference between baseline modeling inputs, rather than an annual MMBtu for Unit 3. The revised emission annual emissions and annual emissions average rate. Therefore, EPA has revised reductions and cost effectiveness with the control technology. In SRP’s estimated NO X 

### emissions estimates are provided in Table 14. calculating the cost effectiveness, it reductions by starting with baseline



### TABLE 

### 14—EPA E MISSIONS 

### R EDUCTIONS AND 

### C OST 

### E FFECTIVENESS FOR 

### NOX

LNB + SOFA

(All units) SCR + LNB + SOFA (Units 1 & 3); LNB + SOFA

(Unit 2) SCR + LNB + SOFA (All units)

**NO** X **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

12 See July 29, 2008 Letter from Kevin Wanttaja July 25, 2008 Final Report for SCR and SNCR Cost (SRP) to Deborah Jordan (EPA) and its attachment: Study, prepared by Sargent and Lundy.VerDate Nov<24>2008 17:19 Aug 27, 2009 Jkt 217001 PO 00000 Frm 00023 Fmt 4702 Sfmt 4702 E:\FR\FM\28AUP1.SGM 28AUP1jlentini on DSKJ8SOYB1PROD with PROPOSALS 

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

TABLE 

### 14—EPA E MISSIONS 

### R EDUCTIONS AND 

### C OST 

### E FFECTIVENESS FOR 

### NOX

### —Continued

SCR + LNB + SOFA LNB + SOFA (Units 1 & 3); SCR + LNB + SOFA

(All units) LNB + SOFA (All units) (Unit 2)

Unit 3 ....................................................................................................................... 71 0 3,549 3,549



### The NPS calculated the cost effectiveness are shown in Table 15. retrofits on Unit 2 compared to Units 1 effectiveness of SCR + LNB + SOFA NPS assumed post-SCR NO X 

### emissions and 3. Note that the capital and annual using only the estimates and allowed of 0.05 lb/MMBtu. NPS accounts for the costs of SCR estimated using the EPA categories of costs from EPA’s Air higher retrofit costs associated with Unit Control Cost Manual are considerably Pollution Control Costs Manual. The 2 by applying a larger retrofit factor lower than those estimated by SRP. NPS costs of compliance and cost associated with physically difficult



### TABLE 

### 15—NPS C OSTS OF 

### C ONTROLS AND 

### C OST 

### E FFECTIVENESS 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 consumers in $/kWh, assuming 85% in electricity generation costs to capacity in Table 16.



### TABLE 

### 16—I NCREASE IN 

### E LECTRICITY 

### C OSTS 

### F ROM 

### NOX 

### C ONTROLS AT 

### NGS

SCR + LNB + SOFA LNB + SOFA (Units 1&3); SCR + LNB + SOFA

(All Units) LNB + SOFA (All Units)

kWh (Unit 2) kWh 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 NO X 

### 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. EPAestimates 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 NO X 

### 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 PM 10 

### . 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

13 CALPUFF 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 

### 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:

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]’’).VerDate Nov<24>2008 17:19 Aug 27, 2009 Jkt 217001 PO 00000 Frm 00024 Fmt 4702 Sfmt 4702 E:\FR\FM\28AUP1.SGM 28AUP1jlentini on DSKJ8SOYB1PROD with PROPOSALS 

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

## 44323

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 NO X on Units 1–5

(modeled by APS) C2. LNB for NO X on Units 1 and 2 and LNB

+OFA on Units 3–5 (modeled by EPA) D. SCR for NO X on Units 3–5 (modeled by

EPA) E1. SCR + LNB + OFA for NO X on Units 1–

5 (modeled by APS) E2. SCR for NO X 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, NO X 

### , SO 2 

### , 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 NO X 

### emission rates inputs were generally appropriate, except that several of the highest emitting days for NO X 

### 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 NO X 

### 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 NO X 

### emission rate for those units. Data from CAMD for Unit 2 and 4 generally agreed with emission inputs used by APS. For SO 2 

### emissions, because the SO 2 

### 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 SO 2 

### emissions for Units 4 and 5, rather than using SO 2 

### data from the 2001–2003 meteorological period.

CALPUFF modeling requires additional inputs, including SO 4 

### , representing condensable inorganic PM and fine and coarse filterable PM. For SO 4 

### , APS estimated that the condensable inorganic PM was entirely represented by sulfuric acid (H 2 

### SO 4

### ) 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 H 2 

### SO 4 

### calculation methodology provided by the Electric Power Research Institute (‘‘EPRI’’). 14 

### The EPRI method relies on characterization of various sources and sinks of H2 

### SO 4 

### in the boiler and downstream components, such as the air preheater, and particulate matter (PM) and SO 2 

### control devices. For the baseline and non-SCR emissions scenarios (Scenarios A–C), the main difference between APS’s and EPA’s calculations for H 2 

### SO 4 

### arises from the assumed loss of H 2 

### SO 4 

### 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 PM 10 

### , and 51% of filterable PM is fine PM 10 

### (i.e., PM2.5 

### ), thus 20% of filterable PM is coarse PM 10 

### , 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 PM 10 

### , and 53% of filterable PM is fine PM 10 

### (i.e., PM2.5 

### ), thus 39% of filterable PM is coarse PM 10 

### , i.e., 92%–53%. APS also estimated elemental carbon (EC) to be 3.7% of the PM2.5 

### , based on Table 6

14 Estimating Total Sulfuric Acid Emissions from Stationary Power Plants—Technical Update, Electric Power Research Institute (EPRI), Palo Alto, CA, 2008. EPRI Product ID: 1016384.

15 We 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. 

### 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 H 2 

### SO 4 

### 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 (SO 4

### ) modeling input. Method 202 for measuring condensable PM does not capture HCl and HF, therefore, EPA added these emissions to PM fine rather than SO 4 

### .

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
0.007lb 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 SO 2 

### 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.

16 Battye, W, and Boyer, K. Catalog of Global Emissi113on Inventories and Emission Inventory Tools for Black Carbon. EPA Contract No. 68–D– 98–046, 2002.

17 Hydrogen Chloride and Hydrogen Fluoride Emission Factors for the NAPAP Inventory, EPA– 600/7–85–041, U.S. Environmental Protection Agency, October 1985.

18 See Reference 1 of Table A–1 from the 1985 EPA report.VerDate Nov<24>2008 17:19 Aug 27, 2009 Jkt 217001 PO 00000 Frm 00025 Fmt 4702 Sfmt 4702 E:\FR\FM\28AUP1.SGM 28AUP1jlentini on DSKJ8SOYB1PROD with PROPOSALS 

## 44324 Federal Register / Vol. 74, No. 166 / Friday, August 28, 2009 / Proposed Rules

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 

### E MISSION 

### RATES [Scenario A]

Unit 1 Unit 2 Unit 3 Unit 4 Unit 5

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

SO 2
........................................................ SO 4
........................................................ NOX
........................................................ SOA ....................................................... PM fine ................................................... PM coarse

.............................................. EC .......................................................... 464.17 3.35 1,841.37 8.35 30.74 12.52

1.18 615.12 3.78 1,567.66 9.41 47.87 19.49

1.84 995.26 4.65 1,926.23 11.58 52.90 21.54

2.03 2,026.10 1.03 5,015.98 32.00 100.93 77.12

3.88 2,130.76 1.03 4,444.04 32.00 48.00 36.67

1.84

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

SO 2
........................................................ SO 4
........................................................ NOX
........................................................ SOA ....................................................... PM fine ................................................... PM coarse

.............................................. EC .......................................................... 522.54 2.06 2,020.14 9.40 46.29 15.50

1.46 615.12 2.06 1,599.47 9.41 65.99 23.52

2.22 1,042.09 2.65 1,970.80 12.13 70.18 24.26

2.29 2,026.10 0.51 5,015.98 32.00 128.93 77.12

3.88 2,131.85 0.51 4,508.56 32.20 76.20 36.69

1.85



### TABLE 

### 18—APS AND 

### EPA E MISSION FOR 

### PM C ONTROL ON 

### U NITS 

### 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)**

SO 2
........................................................ SO 4
........................................................ NOX
........................................................ SOA ....................................................... PM fine ................................................... PM coarse

.............................................. EC .......................................................... 464.17 0.34 1,841.37 8.35 15.34 11.72 0.59 615.12 0.38 1,567.66 9.41 20.39 15.58 0.78 995.26 0.47 1,926.23 11.58 22.54 17.22 0.87 2,026.10 1.03 5,015.98 32.00 100.93 77.12

3.88 2,130.76 1.03 4,444.04 32.00 48.00 36.67

1.84

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

SO 2
........................................................ SO 4
........................................................ NOX
........................................................ SOA ....................................................... 522.54 0.21 2,020.14 9.40 615.12 0.21 1,599.47 9.41 1,042.09 0.27 1,970.80 12.13 2,026.10 0.51 5,015.98 32.00 2,131.85 0.51 4,508.56 32.20

19 Electric Utility Mercury Information Collection http://www.epa.gov/ttn/atw/combust/utiltox/ 20 http://energy.er.usgs.gov/coalqual.htm#submit

. Request (OMB Control Number 2060–0396): utoxpg.html#DA2

. 21 Based on samples D176206 and D202211.VerDate Nov<24>2008 17:19 Aug 27, 2009 Jkt 217001 PO 00000 Frm 00026 Fmt 4702 Sfmt 4702 E:\FR\FM\28AUP1.SGM 28AUP1jlentini on DSKJ8SOYB1PROD with PROPOSALS 

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

## 44325

TABLE 

### 18—APS AND 

### EPA E MISSION FOR 

### PM C ONTROL ON 

### U NITS 

### 1–3—Continued [Scenario B]

Unit 1 Unit 2 Unit 3 Unit 4 Unit 5

PM fine ................................................... PM coarse

.............................................. EC .......................................................... 25.49 13.19 0.66 28.63 15.58 0.78 34.21 18.03 0.91 128.93 77.12

3.88 76.20 36.69

1.85



### TABLE 

### 19—APS AND 

### EPA E MISSION FOR 

### PM C ONTROL ON 

### U NITS 

### 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)**

SO 2
........................................................ SO 4
........................................................ NOX
........................................................ SOA ....................................................... PM fine ................................................... PM coarse

.............................................. EC .......................................................... 464.17 3.35 1,010.91 8.35 30.74 12.52

1.18 615.12 3.78 1,051.90 9.41 47.87 19.49

1.84 995.26 4.65 1,078.69 11.58 52.90 21.54

2.03 2,026.10 1.03 3,561.35 32.00 100.93 77.12

3.88 2,130.76 1.03 3,155.27 32.00 48.00 36.67

1.84

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

SO 2
........................................................ SO 4
........................................................ NOX
........................................................ SOA ....................................................... PM fine ................................................... PM coarse

.............................................. EC .......................................................... 522.54 2.06 1,109.06 9.40 46.29 15.50

1.46 615.12 2.06 1,073.25 9.41 65.99 23.52

2.22 1,042.09 2.65 1,103.65 12.13 70.18 24.26

2.29 2,026.10 0.51 3,561.35 32.00 128.93 77.12

3.88 2,131.85 0.51 3,201.08 32.20 76.20 36.69

1.85



### EPA also disagrees with APS’s 2, 2009, to Coronado Generating Station accounted for a 0.5% conversion of SO 2 

### evaluation of sulfuric acid emissions. by the ADEQ 22 

### required the use of an to SO 3 

### . Sulfuric acid emissions are estimated to ultra-low conversion catalyst (0.5% For emissions of ammonia (NH 3 

### ) increase as a result of operating an SCR conversion) as Best Available Control resulting from SCR, EPA followed the due to additional oxidation of SO 2 

### to Technology (BACT). EPA has calculation methodology APS used in SO 3 

### on the SCR catalyst. APS used a 1% determined that APS could also use an its supplemental modeling analysis for conversion rate from the SCR catalyst. ultra-low conversion catalyst. Therefore, FCPP (dated November 2008). Yet a Prevention of Significant in our calculation of H2 

### SO 4 

### emissions Deterioration (PSD) permit issued June from the addition of the SCR, we



### TABLE 

### 20—EPA E MISSIONS FOR 

### SCR ON 

### U NITS 

### 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)**

SO 2
........................................................ SO 4
........................................................ NOX
........................................................ SOA ....................................................... PM fine ................................................... PM coarse

.............................................. EC .......................................................... 522.54 2.06 2,020.14 9.40 46.29 15.50

1.46 615.12 2.06 1,599.47 9.41 65.99 23.52

2.22 1,042.09 12.52 472.99

12.13 70.18 24.26

2.29 2,026.10 2.52 1,203.84 32.00 128.93 77.12

3.88 2,131.85 2.54 1,082.05 32.20 76.20 36.69

1.85



### TABLE 

### 21—APS AND 

### EPA E MISSIONS FOR 

### SCR ON 

### U NITS 

### 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)**

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

22 See http://www.azdeq.gov/environ/air/permits/ download/pastmonth.pdf.VerDate Nov<24>2008 17:19 Aug 27, 2009 Jkt 217001 PO 00000 Frm 00027 Fmt 4702 Sfmt 4702 E:\FR\FM\28AUP1.SGM 28AUP1jlentini on DSKJ8SOYB1PROD with PROPOSALS 

## 44326 Federal Register / Vol. 74, No. 166 / Friday, August 28, 2009 / Proposed Rules

TABLE 

### 21—APS AND 

### EPA E MISSIONS FOR 

### SCR ON 

### U NITS 

### 1–5—Continued [Scenario E]

Unit 1 Unit 2 Unit 3 Unit 4 Unit 5

SO4
........................................................ NOX
........................................................ SOA ....................................................... PM fine ................................................... PM coarse

.............................................. EC .......................................................... 30.71 147.31

8.35 30.74 12.52

1.18 34.61 141.09

9.41 47.87 19.49

1.84 42.61 192.62

11.58 52.90 21.54

2.03 9.53 601.92

32.00 100.93 77.12

3.88 9.58 533.29

32.00 48.00 36.67

1.84

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

SO 2
........................................................ SO 4
........................................................ NOX
........................................................ SOA ....................................................... PM fine ................................................... PM coarse

.............................................. EC .......................................................... 522.54 9.70 484.83

9.40 46.29 15.50

1.46 615.12 9.71 383.87

9.41 65.99 23.52

2.22 1,042.09 12.52 472.99

12.13 70.18 24.26

2.29 2,026.10 2.52 1,203.84 32.00 128.93 77.12

3.88 2,131.85 2.54 1,082.05 32.20 76.20 36.69

1.85



### c. Ammonia Background

In addition to the different CALPUFF emission rates described above, EPAadditionally 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 NO X 

### 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 (SO 4

### ) 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 themonths 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—A MMONIA 

### BACKGROUND 

### C ONCENTRATION 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

23 Letter from Rick Cables (Forest Service R2 24 Interagency Workgroup On Air Quality 25 http://vista.cira.colostate.edu/improve/. Regional Forester) and Corbin Newman (Forest Modeling (IWAQM) Phase 2 Summary Report And 26 Mark E. Sather et al. , 2008. ‘‘Baseline ambient Service R3 Regional Forester) to Deborah Jordan Recommendations For Modeling Long Range gaseous ammonia concentrations in the Four (EPA Region 9 Air Division Director) dated March Transport Impacts (EPA–454/R–98–019), EPA Corners area and eastern Oklahoma, USA’’. Journal
17, 2009. OAQPS, December 1998, http://www.epa.gov/ of Environmental Monitoring, 2008, 10, 1319–1325, scram001/7thconf/calpuff/phase2.pdf

. DOI: 10.1039/b807984f.VerDate Nov<24>2008 17:19 Aug 27, 2009 Jkt 217001 PO 00000 Frm 00028 Fmt 4702 Sfmt 4702 E:\FR\FM\28AUP1.SGM 28AUP1jlentini on DSKJ8SOYB1PROD with PROPOSALS 

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

## 44327

TABLE 

### 22—A MMONIA 

### BACKGROUND 

### C ONCENTRATION 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 various pollutants to calculate the pollutant is a single value for the year, natural background visibility impact. this method allows for monthly The BART determination guidelines EPA used background concentrations variation in its visibility impact, which recommend that impacts of sources should be estimated in deciviews from Table 2–1 of ‘‘Guidance for changes with relative humidity. The relative to natural background. Estimating Natural Visibility Conditions resulting deciviews differ by roughly CALPOST, a CALPUFF post-processor, Under the Regional Haze Rule.’’ 27 

### 1% from those resulting from the uses background concentrations of Although the concentration for each method originally used by APS.



### TABLE 

### 23—N ATURAL 

### BACKGROUND 

### C ONCENTRATIONS FOR 

### FCPP AND 

### NGS

CALPOST parameter Pollutant Concentration (μg/m 3)

BKSO4 ................................................... BKNO3 ................................................... BKPMC ................................................... BKOC ..................................................... BKSOIL .................................................. BKEC ...................................................... ammonium sulfate .......................................................

........................................... ammonium nitrate .......................................................

............................................ coarse particulates ....................................................

.............................................. organic carbon ........................................................

................................................ soil ........................................................................................................................... elemental carbon .....................................................

............................................... 0.12 0.10 3.00 0.47 0.50 0.02



### e. Visibility Modeling Results predicted visibility improvements at the but noticeable change in haziness under 16 Class I areas within a 300 km radius most circumstances when viewing To assess results from the CALPUFF of FCPP. scenes in a Class I area. Table 25 model and post-processing steps, EPA used a least-squares regression analysis APS presented visibility improvement presents the visibility impacts of the of all visibility modeling output from by comparing the 98th percentile (8th 98th percentile of daily maxima for each the 2001–2003 modeling period to highest) of the daily maximum deciview Class I area for each year, averaged over determine the percent improvement in (dv) values from CALPUFF per Class I 2001–2003, determined for FCPP by visibility (measured in deciviews) area, averaged over 2001–2003. As APS. Table 26 presents the visibility compared to the baseline resulting from outlined in the 1999 Regional Haze rule impacts of the 98th percentile of daily the application of control technologies. (64 FR 35725, July 1, 1999), a one maxima from 2001–2003 for each Class Table 24 shows EPA’s modeled deciview change in haziness is a small I area determined by EPA. 28



### TABLE 

### 24—P ERCENT 

### I MPROVEMENT IN 

### D ECIVIEW 

### I MPACTS 

### F ROM 

### EPA M ODELING AT 

### E ACH 

### C LASS 

### I A REA 

### F ROM 

### PM AND 

### NOX 

### C ONTROLS 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

27 U.S. Environmental Protection Agency, EPA– direct link http://www.epa.gov/ttn/oarpg/t1/ percentile from all three years taken together. This 454/B–03–005, September 2003, on web page memoranda/rh

_envcurhr

_ gd.pdf. does not significantly impact the overall results. http://www.epa.gov/ttn/oarpg/t1pgm.html, with 28 EPA did not average the 98th percentiles from each year as did APS, rather EPA used the 98thVerDate Nov<24>2008 17:19 Aug 27, 2009 Jkt 217001 PO 00000 Frm 00029 Fmt 4702 Sfmt 4702 E:\FR\FM\28AUP1.SGM 28AUP1jlentini on DSKJ8SOYB1PROD with PROPOSALS 

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

TABLE 

### 25—I MPACTS OF 

### FCPP ON 

### V ISIBILITY 

### (98TH 

### P ERCENTILE OF 

### DAILY 

### M AXIMUM DV

### ) AT 

### S IXTEEN 

### C LASS 

### I A REAS AS 

### M ODELED BY 

### APS

Baseline Visibility impact (dv) after applying:

Wet ESP (B) LNB (C1) SCR (E1)

Arches ............................................................................................................................ Bandolier ........................................................................................................................ Black Canyon ................................................................................................................. Canyonlands .................................................................................................................. Capitol Reef ................................................................................................................... Grand Canyon ............................................................................................................... Great Sand Dunes ......................................................................................................... La Garita ......................................................................................................................

.. Maroon Bells .................................................................................................................. Mesa Verde ................................................................................................................... Pecos ............................................................................................................................. Petrified Forest .............................................................................................................. San Pedro ...................................................................................................................... West Elk .......................................................................................................................

.. Weminuche .................................................................................................................... Wheeler Peak ................................................................................................................ 1 .98 1 .71 1 .44 2 .25 1 .74 1 .07 1 .02 1 .36 1 3 .17 1 .55 1 .21 2 .21 1 .22 1 .90 1 .20 1.96 1.70 1.43 2.23 1.73 1.07 1.02 1.36 0.81 3.14 1.54 1.20 2.18 1.21 1.68 1.19 1.74 1.57 1.21 2.06 1.53 0.95 1.02 1.08 0.66 3.01 1.31 1.05 2.04 1.03 1.66 0.97 1.23 1.12 0.75 1.67 1.15 0.66 0.62 0.58 0.35 2.73 0.88 0.68 1.51 0.56 0.94 0.64

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



### TABLE 

### 26—I MPACTS OF 

### FCPP ON 

### V ISIBILITY 

### (98TH 

### P ERCENTILE DV

### ) ON 

### S IXTEEN 

### C LASS 

### I A REAS AS 

### M ODELED BY 

### EPA

Baseline Visibility Impact (dv) after applying:

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

Arches ...................................................................................................... Bandolier .................................................................................................. Black Canyon ........................................................................................... Canyonlands ............................................................................................ Capitol Reef ............................................................................................. Grand Canyon ......................................................................................... Great Sand Dunes ................................................................................... La Garita .................................................................................................. Maroon Bells ............................................................................................ Mesa Verde ............................................................................................. Pecos ....................................................................................................... Petrified Forest ........................................................................................ San Pedro ................................................................................................ West Elk ................................................................................................... Weminuche .............................................................................................. Wheeler Peak .......................................................................................... 4.03 2.91 2.36 4.89 3.21 1.63 1.21 1.71 1.04 6.48 2.11 1.51 3.81 1.86 2.79 1.50 4.02 2.90 2.36 4.87 3.20 1.63 1.20 1.71 1.04 6.45 2.10 1.51 3.80 1.86 2.77 1.50 3.24 2.25 1.89 4.21 2.44 1.31 0.91 1.28 0.77 5.47 1.65 1.14 3.13 1.41 2.16 1.17 2.55 1.81 1.44 3.76 1.87 0.96 0.67 1.05 0.57 4.90 1.34 0.97 2.53 1.06 1.58 0.93 1.83 1.38 1.01 2.66 1. 48 0.81 0.54 0.73 0.43 3.89 1.06 0.8 1 2. 01 0.75 1.17 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 km 2 

### 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-km 2



### .VerDate Nov<24>2008 17:19 Aug 27, 2009 Jkt 217001 PO 00000 Frm 00030 Fmt 4702 Sfmt 4702 E:\FR\FM\28AUP1.SGM 28AUP1jlentini on DSKJ8SOYB1PROD with PROPOSALS 

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

## 44329

TABLE 

### 27—A LTERNATIVE 

### V ISIBILITY 

### M ETRIC

A (Baseline) Visibility Impact (dv-km 2) after applying:
B (Wet ESP) C2 (LNB) D (SCR 3–5) E2 (SCR 1–5)

Arches .................................................................................. Bandolier

.............................................................................. Black Canyon ....................................................................... Canyon-lands ....................................................................... Capitol Reef ......................................................................... Grand Canyon ...................................................................... Great Sand Dunes ............................................................... La Garita

.............................................................................. Maroon Bells

........................................................................ Mesa Verde

.......................................................................... Pecos ................................................................................... Petrified Forest

..................................................................... San Pedro

............................................................................ West Elk ............................................................................... Weminuche .......................................................................... Wheeler Peak ...................................................................... 1,014 249 121 4,991 2,433 6,443

119 699 571 1,112 1,574

469 505 2,996 1,525

121 1,012 246 121 4,964 2,427 6,416

119 697 569 1,109 1,570

467 503 2,988 1,522

121 816 193 89 4,419 1,849 4,870 88 518 415 939 1,225

374 430 2,221 1,170 92 615 156 76 3,961 1,405 3,714 69 394 315 818 974 322 347 1,614

860

74 461 119 53 2,794 1,113 3,174 56 295 238 666 780 259 265 1,207

636

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 SO 4 

### , are more similar to each other in terms of NO X 

### control than for FCPP. For Scenario E, SRP assumed NO X 

### 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 H 2 

### SO 4 

### were from the assumed loss of H 2 

### SO 4 

### 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 H 2 

### SO 4 

### emissions resulting from the SCR scenarios, EPA used a 0.5% SO 2 

### to SO 3 

### 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 

### E MISSION 

### RATES 

### (S CENARIO 

### A)

Unit 1 Unit 2 Unit 3

**SRP Baseline Modeling Inputs (in lb/hr)**

SO 2
............................................................................................................................... ............... 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)**

SO 2
............................................................................................................................... ............... 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 75.20 107.87VerDate Nov<24>2008 17:19 Aug 27, 2009 Jkt 217001 PO 00000 Frm 00031 Fmt 4702 Sfmt 4702 E:\FR\FM\28AUP1.SGM 28AUP1jlentini on DSKJ8SOYB1PROD with PROPOSALS 

## 44330 Federal Register / Vol. 74, No. 166 / Friday, August 28, 2009 / Proposed Rules

TABLE 

### 28—SRP AND 

### EPA BASELINE 

### E MISSION 

### RATES 

### (S CENARIO 

### A)—Continued

Unit 1 Unit 2 Unit 3

EC .............................................................................................................................

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



### TABLE 

### 29—SRP AND 

### EPA E MISSIONS FOR 

### LNB + SOFA (S CENARIO 

### B)

Unit 1 Unit 2 Unit 3

**SRP Baseline Modeling Inputs (in lb/hr)**

SO 2
............................................................................................................................... ............... 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)**

SO 2
............................................................................................................................... ............... 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 E MISSIONS FOR 

### SCR + LNB + SOFA ON 

### U NITS 

### 1 AND 

### 3, LNB + SOFA ON 

### U NIT 

### 2 (S CENARIO 

### C)

Unit 1 Unit 2 Unit 3

**SRP Baseline Modeling Inputs (in lb/hr)**

SO 2
............................................................................................................................... ............... 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)**

SO 2
............................................................................................................................... ............... 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 E MISSIONS FOR 

### SCR + LNB + SOFA ON 

### U NITS 

### 1 AND 

### 3, H ALF

### -SCR + LNB + SOFA ON 

### U NIT 

### 2 (S CENARIO 

### D)

Unit 1 Unit 2 Unit 3

**EPA Baseline Modeling Inputs (in lb/hr)**

SO 2
............................................................................................................................... ............... 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 3.05VerDate Nov<24>2008 17:19 Aug 27, 2009 Jkt 217001 PO 00000 Frm 00032 Fmt 4702 Sfmt 4702 E:\FR\FM\28AUP1.SGM 28AUP1jlentini on DSKJ8SOYB1PROD with PROPOSALS 

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

## 44331

TABLE 

### 32—SRP AND 

### EPA E MISSIONS FOR 

### SCR + LNB + SOFA ON 

### U NITS 

### 1—3 (S CENARIO 

### E)

Unit 1 Unit 2 Unit 3

**SRP Baseline Modeling Inputs (in lb/hr)**

SO 2
............................................................................................................................... ............... 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

SO 2
............................................................................................................................... ............... 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 **EPA Baseline Modeling Inputs (in lb/hr)**



### 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—P ERCENT 

### I MPROVEMENT IN 

### D ECIVIEW 

### I MPACTS 

### F ROM 

### EPA M ODELING AT 

### E ACH 

### C LASS 

### I A REA 

### F ROM 

### NOX 

### C ONTROLS 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—V ISIBILITY 

### I MPACTS 

### (98TH 

### P ERCENTILE DV

### ) OF 

### NGS ON 

### E LEVEN 

### C LASS 

### I A REAS AS 

### M ODELED BY 

### SRP

Baseline Visibility Impact (dv) after applying:

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

Arches

.............................................................................................................. Bryce Canyon .................................................................................................. Canyonlands .................................................................................................... Capitol Reef ..................................................................................................... Grand Canyon ................................................................................................. Mazatzal

........................................................................................................... Mesa Verde

..................................................................................................... 2.05 2.00 2.47 2.68 2.56 0.71 1.42 1.51 1.58 1.96 2.31 2.29 0.47 1.04 1 .19 1.36 1.53 2.06 2.25 0. 41 0.77 0.99 1. 23 1 .35 1.89 2.2 9 0.38 0 .58VerDate Nov<24>2008 17:19 Aug 27, 2009 Jkt 217001 PO 00000 Frm 00033 Fmt 4702 Sfmt 4702 E:\FR\FM\28AUP1.SGM 28AUP1jlentini on DSKJ8SOYB1PROD with PROPOSALS 

## 44332 Federal Register / Vol. 74, No. 166 / Friday, August 28, 2009 / Proposed Rules

TABLE 

### 34—V ISIBILITY 

### I MPACTS 

### (98TH 

### P ERCENTILE DV

### ) OF 

### NGS ON 

### E LEVEN 

### C LASS 

### I A REAS AS 

### M ODELED BY 

### SRP— Continued

Baseline Visibility Impact (dv) after applying:

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

Petrified Forest ................................................................................................ Pine Mountain

.................................................................................................. Sycamore Canyon ........................................................................................... Zion .................................................................................................................. 1.52 0.66 1.31 1.83 1.14 0.46 0.92 1.47 0.92 0.38 0.78 1.26 0.76 0 .34 0.63 1.10

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



### TABLE 

### 35—V ISIBILITY 

### I MPACTS 

### (98TH 

### P ERCENTILE DV

### ) OF 

### NGS ON 

### E LEVEN 

### C LASS 

### I A REAS AS 

### M ODELED BY 

### EPA

Baseline Visibility Impact (dv) after applying:

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

Arches

.................................................................................. Bryce Canyon

...................................................................... Canyonlands ........................................................................ Capitol Reef

......................................................................... Grand Canyon

...................................................................... Mazatzal

............................................................................... Mesa Verde

.......................................................................... Petrified Forest

..................................................................... Pine Mountain

...................................................................... Sycamore Canyon

............................................................... Zion

...................................................................................... 3.25 3.66 4.37 5.48 5.41 1.16 2.24 2.62 1.08 1.96 3.73 2.08 2.44 2.98 4.08 4.35 0.73 1.33 1.54 0.64 1.28 2.65 1.33 1.57 1.90 2.97 3.34 0.48 0.78 1.00 0.42 0.80 1.65 1.16 1.39 1.65 2.71 3.06 0.45 0.67 0.86 0.38 0.71 1.44 0.89 1.10 1.25 2.04 2.46 0.37 0.52 0.66 0.32 0.59 1.05

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



### TABLE 

### 36—A LTERNATIVE 

### V ISIBILITY 

### M ETRIC

A (Baseline) Visibility Impact (dv-km2) after applying:

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

Arches

.................................................................................. Bryce Canyon

...................................................................... Canyonlands ........................................................................ Capitol Reef ......................................................................... Grand Canyon ...................................................................... Mazatzal

............................................................................... Mesa Verde .......................................................................... Petrified Forest

..................................................................... Pine Mountain

...................................................................... Sycamore Canyon

............................................................... Zion ...................................................................................... 812 495 4,649 4,184 21,399 978 383 847

72 390 1,574 514 324 3,071 3,127 17,219 618 226 515

44 235 1,104 336 212 2,022 2,233 13,157 410 135 313

28 162 739 293 187 1,741 2,031 12,033 367 115 270

25 144 649 223 147 1,320 1,566 9,698

297

87 217

22 120 494

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 NO X 

### by staging combustion to reduce boiler temperatures will result in reduced NO X 

### 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 (H2 

### SO 4

### ) from coal fired power plants result from the conversion of sulfur in the coal into SO 2 

### and further oxidation to SO 3 

### during the combustion process in the boiler. SO 3 

### can then combine with moisture (H 2

### O) in the flue gas to form H 2 

### SO 4 

### . Fuels high in vanadium can catalyze SO 2 

### to SO 3 

### at higher rates than low vanadium fuels and result in higher H 2 

### SO 4 

### emissions. The use of SCR catalysts, in particular, SCR catalysts that use vanadium, can result in increased emissions of H2 

### SO 4 

### . Emissions increases in H 2 

### SO 4 

### at existing major stationary sources as a result of the application of SCR for NO X 

### control will trigger PSD permitting requirements, including the application of BACT, if they exceed the H2 

### SO 4 

### significance threshold of 7 tpy. Add-on control technologies exist to help reduce H 2 

### SO 4 

### emissions following SO 2 

### to SO 3 

### conversion from combustion and SCR,VerDate Nov<24>2008 17:19 Aug 27, 2009 Jkt 217001 PO 00000 Frm 00034 Fmt 4702 Sfmt 4702 E:\FR\FM\28AUP1.SGM 28AUP1jlentini on DSKJ8SOYB1PROD with PROPOSALS 

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## 44333

including injection of reagents ( e.g., hydrated lime, sodium bisulfite) to convert H 2 

### SO 4 

### 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 H 2 

### SO 4 

### at FCPP, compared to coal-fired facilities in the Midwestern and Eastern states, suggests the application of reagent injection will not effectively reduce H 2 

### SO 4 

### 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% SO 2 

### to SO 3 

### conversion) currently represents BACT.

In addition to the impact of SCR on H 2 

### SO 4 

### 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 NO X 

### 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., H 2 

### SO 4 

### emissions increases, the limited efficacy of reagent injection for H 2 

### SO 4 

### 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—E XISTING 

### A IR 

### P OLLUTION 

### C ONTROLS AT 

### FCPP

NOX control PM control SO 2 control

Unit 1 .................................. Unit 2 .................................. Unit 3 .................................. Unit 4 ..................................

Unit 5 .................................. none ................................... LNB .................................... LNB .................................... LNB ....................................

LNB .................................... Venturi Scrubber (VS) ...........................

........................ VS—Lime .........................................

............................. VS—Lime .........................................

............................. Reverse Gas Fabric Filter (Baghouse) .........................

Baghouse ...................................................................... VS. VS—Lime. VS—Lime. Tray Tower Flue Gas

Desulfurization (FGD). Tray Tower FGD.



### a. Existing NO X 

### 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 NO X 

### emissions (Scenario E1). FCPP emits more NO X 

### 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 NO X 

### emitted from each unit. Every unit at FCPP emits NO X 

### at a higher concentration than any other unit in Region IX.

The potential for successfully obtaining significant reductions of NO X 

### 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 NO X 

### 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 NO X 

### 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 NO X 

### control.

Units 4 and 5 were originally designed and operated with cell burners. This type of combustion burner inherently creates more NO X 

### than conventional wall-fired burners. Although these burners were replaced in the 1980s, the design of a cell burner boiler limits the NO X 

### reduction that can be achieved with modern low NO X 

### combustion techniques. EPA has set different presumptive levels for the expected achievable NO X 

### 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 SO 2 

### 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.VerDate Nov<24>2008 17:19 Aug 27, 2009 Jkt 217001 PO 00000 Frm 00035 Fmt 4702 Sfmt 4702 E:\FR\FM\28AUP1.SGM 28AUP1jlentini on DSKJ8SOYB1PROD with PROPOSALS 

## 44334 Federal Register / Vol. 74, No. 166 / Friday, August 28, 2009 / Proposed Rules

TABLE 

### 38—E XISTING 

### A IR 

### P OLLUTION 

### C ONTROLS AT 

### NGS

NOX control PM control SO 2 control

Units 1–3 ................................................... LNB + SOFA 29

......................................... 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

29 On November 20, 2008, EPA Region IX issued a PSD permit authorizing NGS to modify Units 1– 3 with LNB + SOFA over 2009–2011. 

### 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 isan ‘‘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.