[Federal Register Volume 74, Number 166 (Friday, August 28, 2009)]
[Proposed Rules]
[Pages 44313-44334]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E9-20826]
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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.
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SUMMARY: The Environmental Protection Agency is providing an Advanced
Notice of Proposed Rulemaking (ANPR)
[[Page 44314]]
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: [email protected].
3. Mail or delivery: Anita Lee (Air-3), U.S. Environmental
Protection Agency Region IX, 75 Hawthorne Street, San Francisco, CA
94105-3901.
Instructions: All comments will be included in the public docket
without change and may be made available online at www.regulations.gov,
including any personal information provided, unless the comment
includes Confidential Business Information (CBI) or other information
whose disclosure is restricted by statute. Information that you
consider CBI or otherwise protected should be clearly identified as
such and should not be submitted through www.regulations.gov or e-mail.
www.regulations.gov is an ``anonymous access'' system, and EPA will not
know your identity or contact information unless you provide it in the
body of your comment. If you send e-mail directly to EPA, your e-mail
address will be automatically captured and included as part of the
public comment. If EPA cannot read your comment due to technical
difficulties and cannot contact you for clarification, EPA may not be
able to consider your comment.
Docket: The index to the docket for this action is available
electronically at www.regulations.gov and in hard copy at EPA Region
IX, 75 Hawthorne Street, San Francisco, California. While all documents
in the docket are listed in the index, some information may be publicly
available only at the hard copy location (e.g., copyrighted material),
and some may not be publicly available in either location (e.g., CBI).
To inspect the hard copy materials, please schedule an appointment
during normal business hours with the contact listed in the FOR FURTHER
INFORMATION CONTACT section.
FOR FURTHER INFORMATION CONTACT: Anita Lee, EPA Region IX, (415) 972-
3958, [email protected].
SUPPLEMENTARY INFORMATION: Throughout this document, ``we'', ``us'',
and ``our'' refer to EPA.
Table of Contents
I. Background
A. Statutory and Regulatory Framework for Addressing Visibility
B. Statutory and Regulatory Framework for Addressing Sources
Located on Tribal Lands
C. Statutory and Regulatory Framework for BART Determinations
D. EPA's Intended Action Subsequent to ANPRM
E. Factual Background
1. Four Corners Power Plant
2. Navajo Generating Station
3. Relationship of NOX and PM to Visibility
Impairment
II. Request for Public Comment
A. Factor 1: Cost of Compliance
1. FCPP
a. Estimated Cost of Controls
b. Cost Effectiveness of Controls
2. NGS
a. Estimated Cost of Controls
b. Cost Effectiveness of Controls
B. Factor 5: Degree of Visibility Improvement
1. FCPP
a. Visibility Modeling Scenarios
b. EPA Modifications to Emission Rate Inputs
c. Ammonia Background
d. Natural Background
e. Visibility Modeling Results
2. NGS
a. Visibility Modeling Scenarios
b. EPA Modifications to Emission Rate Inputs
c. Ammonia Background and Natural Background
d. Visibility Modeling Results
C. Factor 2: Energy and Non-Air Quality Impacts
1. FCPP
2. NGS
D. Factor 3: Existing Controls at the Facility
1. FCPP
2. NGS
E. Factor 4: Remaining Useful Life of Facility
1. FCPP
2. NGS
III. Statutory and Executive Order Reviews
I. Background
A. Statutory and Regulatory Framework for Addressing Visibility
Part C, Subsection II, of the Act, establishes a visibility
protection program that sets forth ``as a national goal the prevention
of any future, and the remedying of any existing, impairment of
visibility in mandatory class I Federal areas which impairment results
from man-made air pollution.'' 42 U.S.C. 7491A(a)(1). The terms
``impairment of visibility'' and ``visibility impairment'' are defined
in the Act to include a reduction in visual range and atmospheric
discoloration. Id. 7491A(g)(6). A fundamental requirement of the
program is for EPA, in consultation with the Secretary of the Interior,
to promulgate a list of ``mandatory Class I Federal areas'' where
visibility is an important value. Id. 7491A(a)(2). These areas include
national wilderness areas and national parks greater than six thousand
acres in size. Id. 7472(a).
On November 30, 1979, EPA identified 156 mandatory Class I Federal
areas, including for example: Grand Canyon National Park in Arizona (40
[[Page 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.''
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\1\ ``Protecting Visibility in National Parks and Wilderness
Areas'', Committee on Haze in National Parks and Wilderness Areas,
National Research Council, National Academy Press (1993).
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EPA first promulgated regulations to address regional haze on April
22, 1999. 64 FR 35765 (April 22, 1999). EPA's 1999 regional haze
regulations included a provision requiring States to review BART-
eligible sources for potentially mandating further air pollution
controls. Congress defined BART-eligible sources as ``each major
station stationary source which is in existence on August 7, 1977, but
which has not been in operation for more than fifteen years as of such
date'' which emits pollutants that are reasonably anticipated to cause
or contribute to visibility impairment. 42 U.S.C. 7479(b)(2)(A).
EPA's 1999 regulations followed the five factor approach set forth
in the statutory definition of BART. However, the regulations treated
the fifth factor, the degree of visibility improvement, on an area-wide
rather than source specific basis. 64 FR 35741. The Court remanded the
1999 regulations to EPA on that issue. American Corn Growers Assoc. v.
EPA, 291 F.3d 1 (DC Cir. 2002). EPA promulgated revisions to the
regulations in June 2003, which were remanded on narrow grounds not
relevant to this action. Center for Energy and Economic Development v.
EPA, 398 F.3d 653 (DC Cir. 2005). Finally, EPA revised regional haze
regulations in March 2005, which were upheld by the Court of Appeals
for the District of Columbia Circuit. Utility Air Regulatory Group v.
EPA, 471 F.3d 1333 (DC Cir. 2006).
B. Statutory and Regulatory Framework for Addressing Sources Located on
Tribal Lands
The 1990 Amendments included Section 301(d)(4) of the Act directing
EPA to promulgate regulations for controlling air pollution on Tribal
lands. EPA promulgated regulations to implement this Congressional
directive, known as the Tribal Authority Rule (TAR), in 1998. 63 FR
7264 (1998) codifed at 40 CFR 49.1-49.11. See generally Arizona Public
Service v. EPA, 211 F.3d 1280 (DC Cir. 2000).
Section 49.11 of the TAR authorizes EPA to promulgate a FIP when
EPA determines such regulations are ``necessary or appropriate'' to
protect air quality. 40 CFR 49.11(a). Pursuant to the authority in the
TAR, EPA promulgated a source specific FIP for FCPP 2006. The Court of
Appeals for the Tenth Circuit considered the regulatory language in 40
CFR 49.11(a) and concluded that ``[i]t provides the EPA discretion to
determine what rulemaking is necessary or appropriate to protect air
quality and requires the EPA to promulgate such rulemaking.'' Arizona
Public Service v. EPA, 562 F.3d 1116 (10th Cir. 2009).
C. Statutory and Regulatory Framework for BART Determinations
FCPP and NGS are the only BART eligible sources located on the
Navajo Nation. EPA's guidelines for evaluating BART are set forth in
Appendix Y to 40 CFR Part 51. The Guidelines include a ``five factor''
analysis for BART determinations. Id. at IV.A. Those factors, from the
definition of BART, are: (1) Costs of compliance, (2) the energy and
non-air quality environmental impacts of compliance, (3) any pollution
control equipment in use or in existence at the source, (4) the
remaining useful life of the source, and (5) the degree of improvement
in visibility which may reasonably be anticipated to result from the
use of such technology. 40 CFR 51.308(e)(1)(ii)(A).
D. EPA's Intended Action Subsequent to the ANPR
After receiving information from this ANPR, EPA intends to propose
separate FIPs for FCPP and NGS containing our determination of what
level of control technology is BART for each power plant. EPA has
determined it has authority to promulgate these FIPs under CAA Section
301(d)(4), 40 CFR Part 49.11, and 40 CFR 51.308(e). Any person may
submit information concerning EPA's authority during the 30 day comment
period for this ANPR.
As discussed more fully below, EPA is specifically seeking
information in this ANPR on two of the listed considerations in the
five factor test: (1) The data inputs to model the degree of
improvement in visibility which may reasonably be anticipated from
different levels of air pollution controls as BART and (2) the costs of
compliance of those potential BART controls. We anticipate that those
two factors will generate the most comments on our subsequent proposed
BART FIPs for FCPP and NGS. Information on the other three factors in
the five factor test may also be submitted in response to this ANPR.
E. Factual Background
1. Four Corners Power Plant
FCPP is a privately owned and operated coal-fired power plant
located on the Navajo Nation Indian Reservation near Farmington, New
Mexico. Based on lease agreements signed in 1960, FCPP was constructed
and has been operating on real property held in trust by the Federal
government for the Navajo Nation. The facility consists of five coal-
fired electric utility steam generating units with a total capacity of
2060 megawatts (MW). Units 1, 2, and 3 at FCPP are owned entirely by
Arizona Public Service (APS), which serves as the facility operator,
and are rated to 170 MW (Units 1 and 2) and 220 MW (Unit 3). Units 4
and 5 are each rated to a capacity of 750 MW, and are co-owned by six
entities: Southern California Edison (48%), APS (15%), Public Service
Company of New Mexico (13%), Salt River Project (SRP) (10%), El Paso
Electric Company (7%), and Tucson Electric Power (7%).
Based on 2006 emissions data from the EPA Clean Air Markets
Division,\2\ FCPP is the largest source of NOX emissions in
the United States (nearly 45,000 tons per year (tpy) of
NOX).
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\2\ ``Clean Air Markets--Data and Maps'' at http://camddataandmaps.epa.gov/gdm/.
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FCPP, located near the Four Corners region of Arizona, New Mexico,
Utah, and Colorado, is within 300 kilometers (km) of sixteen mandatory
Class I areas: Arches National Park (NP), Bandolier National Monument
(NM), Black Canyon of the Gunnison Wilderness Area (WA), Canyonlands
NP, Capitol Reef NP, Grand Canyon NP, Great Sand Dunes NP, La Garita
WA, Maroon Bells-Snowmass WA, Mesa Verde NP, Pecos WA, Petrified Forest
NP, San Pedro Parks WA, West Elk WA, Weminuche WA, and Wheeler Park WA.
APS
[[Page 44316]]
provided information relevant to a BART analysis to EPA on January 29,
2008. The information consisted of a BART engineering and cost analysis
conducted by Black and Veatch (B&V) dated December 4, 2007 (Revision
3), a BART visibility modeling protocol prepared by ENSR Corporation
(now called AECOM and will be referred to as AECOM throughout this
document) dated January 2008, a BART visibility modeling report
prepared by AECOM dated January 2008, and APS BART Analysis
conclusions, dated January 29, 2008. APS provided supplemental
information on cost and visibility modeling in correspondence dated May
28, 2008, June 10, 2008, November 2008, and March 16, 2009.
2. Navajo Generating Station
NGS is a coal-fired power plant located on the Navajo Nation Indian
Reservation, just east of Page, Arizona, approximately 135 miles north
of Flagstaff, Arizona. The facility is co-owned by six different
entities: U.S. Bureau of Reclamation (24.3%), SRP, which also acts as
the facility operator (21.7%), Los Angeles Department of Water and
Power (21.2%), APS (14%), Nevada Power Company (11.3%), and Tucson
Electric Power (7.5%).
Based on 2006 emissions data from the EPA Clean Air Markets
Division, NGS is the fourth largest source of NOX emissions
in the United States (nearly 35,000 tpy). NGS, in northern Arizona, is
located within 300 km of eleven Class I areas: Arches NP, Bryce Canyon
NP, Canyonlands NP, Capitol Reef NP, Grand Canyon NP, Mazatzal WA, Mesa
Verde NP, Petrified Forest NP, Pine Mountain WA, Sycamore Canyon WA,
and Zion NP.
SRP submitted to EPA a BART modeling protocol prepared by AECOM
dated September 2007, and a BART Analysis, conducted by AECOM, dated
November 2007. SRP provided supplemental information regarding cost on
July 29, 2008, a revised BART Analysis, dated December 2008, and
additional information regarding modeling and emission control rates on
June 3, 2009.
3. Relationship of NOX and PM to Visibility Impairment
Particulate matter (PM) less than 10 microns (millionths of a
meter) in size interacts with light. The smallest particles in the 0.1
to 1 micron range interact most strongly as they are about the same
size as the wavelengths of visible light. The effect of the interaction
is to scatter light from its original path. Conversely, for a given
line of sight, such as between a mountain scene and an observer, light
from many different original paths is scattered into that line. The
scattered light appears as whitish haze in the line of sight, obscuring
the view.
PM emitted directly into the atmosphere, also called primary PM,
for example from materials handling, tends to be coarse, i.e. around 10
microns, since it is created from the breakup of larger particles of
soil and rock. PM that is formed in the atmosphere from the
condensation of gaseous chemical pollutants, also called secondary PM,
tends to be fine, i.e. smaller than 1 micron, since they are formed
from the buildup of individual molecules. Thus, secondary PM tends to
contribute more to visibility impairment than primary PM because it is
in the size range where it most effectively interacts with visible
light. NOX and ammonia are two examples of precursors to
secondary PM.
NOX is a gaseous pollutant that can be oxidized to form
nitric acid. In the atmosphere, nitric acid in the presence of ammonia
can form particulate ammonium nitrate. The formation of ammonium
nitrate is also dependent on temperature and relative humidity.
Particulate ammonium nitrate can grow into the size range that
effectively interacts with light by coagulating together and by taking
on additional pollutants and water. The same principle applies to
SO2 and the formation of particulate ammonium sulfate.
In air quality models, secondary PM is tracked separately from
primary PM because the amount of secondary PM formed depends on weather
conditions and because it can be six times more effective at impairing
visibility. This is reflected in the equation used to calculate
visibility impact from concentrations measured by the Interagency
Monitoring of Protected Visual Environments (IMPROVE) monitoring
network covering Class I areas.\3\
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\3\ Guidance for Estimating Natural Visibility Conditions Under
the Regional Haze Rule, U.S. Environmental Protection Agency'', EPA-
454/B-03-005, September 2003; http://www.epa.gov/ttn/oarpg/t1pgm.html.
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II. Request for Public Comment
A. Factor 1: Cost of Compliance
1. FCPP
a. Estimated Cost of Controls
APS, through its contractor B&V, evaluated the BART cost of
compliance analysis using the EPA Coal Utility Environmental Cost
(CUECost) program, information supplied by equipment vendors, estimates
from previous projects, and projected costs from FCPP. The cost
estimates provided by APS (updated in the March 16, 2009 submission to
EPA) are included in Table 1 for four different levels of control
technology to reduce NOX and in Table 2 for four different
levels of control options to reduce PM on Units 1-3. The NOX
control technology options in Table 1 are: (1) Low NOX
Burners (LNB) on Units 1 and 2 and LNB plus overfire air (OFA) on Units
3-5; (2) selective catalytic reduction (SCR) on all units (units 1-5);
(3) SCR plus LNB on all units (Units 1-5); and (4) SCR plus LNB + OFA
on all units (units 1-5). The PM control options for Units 1-3 \4\ are:
(1) Electrostatic precipitators (ESP) upstream of current air quality
control equipment, i.e., venturi scrubbers; (2) pulse jet fabric filter
(baghouse) upstream of current air quality control equipment; (3) wet
metal ESP downstream of venturi scrubber, and (4) wet membrane ESP
downstream of venturi scrubber.
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\4\ PM emissions from Units 4 and 5 at FCPP are already
controlled by baghouses.
Table 1--FCPP Costs of Compliance for NOX Based on APS's Analysis
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LNB/LNB + OFA \5\ SCR SCR + LNB SCR + LNB + OFA
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Total Capital Investment
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Unit 1.............................. $4,109,000 $110,664,000 $111,609,000 $112,058,000
Unit 2.............................. 4,109,000 119,010,000 121,066,000 121,496,000
Unit 3.............................. 4,701,000 113,084,000 115,420,000 114,851,000
Unit 4.............................. 15,260,000 265,406,000 273,892,000 279,444,000
[[Page 44317]]
Unit 5.............................. 15,260,000 265,406,000 273,892,000 279,444,000
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Total Annual Costs
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Unit 1.............................. $922,000 $22,297,000 $21,764,000 $21,685,000
Unit 2.............................. 922,000 23,634,000 23,468,000 23,385,000
Unit 3.............................. 1,055,000 23,173,000 23,010,000 22,729,000
Unit 4.............................. 3,447,000 55,755,000 56,883,000 57,237,000
Unit 5.............................. 3,447,000 55,755,000 56,883,000 57,237,000
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\5\ Capital and annual cost values are for LNB on Units 1 and 2,
and LNB + OFA on Units 3-5.
Table 2--FCPP Costs of Compliance for PM Based on APS's Analysis
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Upstream \6\ ESP Upstream baghouse Wet metal ESP Wet membrane ESP
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Total Capital Investment
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Unit 1.............................. $37,236,000 $50,515,000 $32,136,000 $23,360,000
Unit 2.............................. 45,702,000 60,992,000 32,879,000 23,901,000
Unit 3.............................. 40,135,000 59,594,000 59,594,000 \7\ 26,988,000
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Total Annual Costs
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Unit 1.............................. $10,169,000 $13,950,000 $8,781,000 $5,652,000
Unit 2.............................. 11,011,000 14,481,000 8,972,000 6,658,000
Unit 3.............................. 10,925,000 16,559,000 10,309,000 7,557,000
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b. Cost Effectiveness of Controls
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\6\ Upstream refers to a location before the existing venturi
scrubbers.
\7\ This estimate was reported by APS in their December 2007
analysis. EPA believes this value was reported by APS in error
because it is unlikely a wet ESP would equal the cost of a baghouse
for Unit 3, but not Units 1 and 2.
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To determine the cost effectiveness of controls, typically
expressed in cost per ton of pollutant reduced ($/ton), estimating the
amount of NOX and PM that will be reduced from the various
control options is necessary. The estimated reduction of the pollutant
is determined by establishing the baseline emissions and the degree of
emissions reduction from the control technology. 40 CFR Part 51, App.
Y, Step 4, c.
APS estimated NOX emissions reductions by starting with
baseline emission rates of NOX of: 0.78 pounds of
NOX per million BTU heat input (lb/MMBtu) for Unit 1; 0.64
lb/MMBtu for Unit 2; 0.59 lb/MMBtu for Unit 3; and 0.49 lb/MMBtu from
Units 4 and 5 each. For the four control technology options, APS
estimated FCPP could achieve the following emissions reductions: (1)
LNB on Units 1 and 2 would reduce NOX 45% and 33%,
respectively and LNB + OFA on Units 3, and 4-5 would reduce
NOX 44% and 29%, respectively; (2) SCR on Units 1-5 would
reduce NOX approximately 88-91%; (3) SCR + LNB on Units 1-5
would reduce NOX by 88-93%; and (4) SCR + LNB + OFA on Units
1-5 would reduce NOX by approximately 88--93%.
APS estimated PM emissions reductions using baseline emission rates
of PM of: 0.025 lb/MMBtu for Unit 1; 0.029 lb/MMBtu for Unit 2; and
0.029 lb/MMBtu for Unit 3. APS estimated that the four different PM
control options would all achieve 52% control on Unit 1 and 59% control
on Units 2 and 3.
Table 3 lists the reduction in NOX emissions and cost
effectiveness estimated by APS for the four control technology options
listed in Table 1. Table 4 provides the corresponding estimates for PM.
Table 3--FCPP Emissions Reductions and Cost Effectiveness for NOX
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LNB/LNB + OFA \8\ SCR SCR + LNB SCR + LNB + OFA
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Tons of NOX Reduced per Year (tpy)
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Unit 1.............................. 2,569 5,138 5,285 5,285
Unit 2.............................. 1,573 4,344 4,344 4,344
Unit 3.............................. 2,465 5,025 5,025 5,023
Unit 4.............................. 3,798 11,665 11,665 11,665
Unit 5.............................. 3,798 11,665 11,665 11,665
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Cost Effectiveness of Controls ($/ton)
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Unit 1.............................. 359 4,343 4,118 4,103
Unit 2.............................. 586 5,484 5,403 5,384
Unit 3.............................. 428 4,582 4,579 4,523
[[Page 44318]]
Unit 4.............................. 908 4,872 4,780 4,907
Unit 5.............................. 908 4,872 4,780 4,907
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\8\ Capital and annual cost values are for LNB on Units 1 and 2,
and LNB + OFA on Units 3-5.
Table 4--FCPP Emissions Reductions and Cost Effectiveness for PM
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Upstream ESP Upstream baghouse Wet metal ESP Wet membrane ESP
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Tons of PM Reduced per Year (tpy)
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Unit 1.............................. 95 95 95 95
Unit 2.............................. 127 127 127 127
Unit 3.............................. 161 161 161 161
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Cost Effectiveness of Controls ($/ton)
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Unit 1.............................. 106,571 146,195 92,024 59,233
Unit 2.............................. 86,485 113,739 70,470 52,294
Unit 3.............................. 67,785 102,741 63,963 46,888
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EPA's regulations recommend using the EPA's Office of Air Quality
Planning and Standards' Air Pollution Cost Control Manual (Sixth
Edition, January 2002) for estimating costs of compliance. 40 CFR Part
51, App. Y, Step 4.a.4. The Air Pollution Cost Control Manual provides
guidance and methodologies for developing accurate and consistent
estimates of cost for air pollution control devices. The costs that may
be estimated include capital costs, operation and maintenance expenses,
and other annual costs. Chapter 2 (Cost Estimation: Concepts and
Methodology) states that total capital costs may include equipment
costs, freight, sales tax, and installation costs. For existing
facilities, retrofit costs should also be considered, and may include
auxiliary equipment, handling and erection, piping, insulation,
painting, site preparation, off-site facilities, engineering, and lost
production revenue. Finally, annual costs are estimated from costs of
raw materials, maintenance labor and materials, utilities, waste
treatment and disposal, replacement materials, overhead, property
taxes, insurance, and administrative charges.
For the estimated costs that FCPP submitted, in Tables 1 & 2 above,
APS provided line-item estimates for the direct and indirect capital
costs, as well as direct and indirect annual costs. APS's estimate,
however, included several costs that are not included in the EPA Air
Pollution Cost Control Manual, including costs of unintended
consequences, such as new Continuous Emission Monitors (CEMs) and costs
of Relative Accuracy Test Audits (RATA) for the CEMs. Additionally,
FCPP included costs of performance tests and ``owner's costs'' in the
indirect capital investment, such as financing, project management, and
construction support costs, as well as legal assistance, permits and
offsets, and public relations costs.
In reviewing APS's estimate, EPA found that the ratio of annual
costs to the total capital costs for all control technologies projected
by APS are considerably higher than those projected by other facilities
that were amortized over the same 20 year time frame. For example, the
total capital investment of SCR for Units 4 and 5 at FCPP is comparable
to the most costly SCR retrofit (Unit 2) at NGS. However, total annual
costs for FCPP are approximately 20% of the total capital costs for
NOX control, and approximately 17-28% of total capital costs
for PM control. In contrast, the total annual cost estimates by NGS for
LNB and SCR are approximately 12-14% of the total capital costs. Other
facilities in Arizona, New Mexico, and Oregon presented annual costs
that ranged from 12-15% of total capital investments.
In Tables 5 and 6, EPA re-calculated the total annual cost of the
NOX and PM control technologies based on an annual to
capital cost ratio of 15% to be consistent with annual costs estimated
by other facilities. EPA did not adjust APS's estimates for capital
costs.
Table 5--FCPP Costs of Compliance for NOX Based on EPA Revisions
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LNB/LNB + OFA SCR SCR + LNB SCR + LNB + OFA
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Total Annual Costs
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Unit 1.............................. $616,350 $16,599,600 $16,741,350 $16,808,700
Unit 2.............................. 616,350 17,851,500 18,159,900 18,224,400
Unit 3.............................. 705,150 16,962,600 17,313,000 17,227,650
Unit 4.............................. 2,289,000 39,810,900 39,810,900 41,916,600
Unit 5.............................. 2,289,000 39,810,900 39,810,900 41,916,600
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[[Page 44319]]
Table 6--FCPP Costs of Compliance for PM Based on EPA Revisions
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Upstream ESP Upstream baghouse Wet metal ESP Wet membrane ESP
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Total Annual Costs
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Unit 1.............................. $5,585,400 $7,577,250 $4,820,400 $3,504,000
Unit 2.............................. 6,855,300 9,148,800 4,931,850 3,585,150
Unit 3.............................. 6,020,250 8,939,100 8,939,100 4,048,200
----------------------------------------------------------------------------------------------------------------
In addition to the total annual cost, other factors, such as
estimated control efficiency and how the emissions reductions are
calculated influence the cost effectiveness of controls. See 40 CFR
Part 51, App. Y, Step 4.a.4. APS estimated that SCR could achieve
NOX control of approximately 90% or greater from the
baseline emissions. For new facilities, 90% or greater reduction in
NOX from SCR can be reasonably expected. See May 2009 White
Paper on SCR from Institute of Clean Air Companies.\9\ For SCR
retrofits on an existing coal-fired power plant, Arizona Department of
Environmental Quality (ADEQ) determined that 75% control from SCR
(following upstream reductions by LNB) was appropriate for the Coronado
Generating Station in Arizona.\10\ Based on this data, EPA has
determined that an 80% control efficiency for SCR alone, rather than
the 90+% control assumed by APS, is appropriate. Accordingly, EPA
calculated post-SCR control NOX emissions from FCPP to be
higher than the values of 0.06 and 0.08 lb/MMBtu used by APS, ranging
from 0.10 lb/MMBtu from Units 4 or 5 to a maximum of 0.16 lb/MMBtu from
Unit 1.
---------------------------------------------------------------------------
\9\ White Paper: Selective Catalytic Reduction (SCR) Control of
NOX Emissions from Fossil Fuel-Fired Electric Power
Plants, Prepared by Institute of Clean Air Companies Inc., May 2009.
\10\ See http://www.azdeq.gov/environ/air/permits/download/pastmonth.pdf.
---------------------------------------------------------------------------
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 re-calculated emissions reductions and
cost effectiveness for NOX and PM based on adjusting the
annual costs, the NOX control efficiency for SCR and the
baseline PM emissions as discussed above.
Table 7--FCPP Cost Effectiveness for NOX Based on EPA Revisions
----------------------------------------------------------------------------------------------------------------
LNB/LNB + OFA SCR SCR + LNB SCR + LNB + OFA
----------------------------------------------------------------------------------------------------------------
Tons of NOX Reduced per Year (tpy)
----------------------------------------------------------------------------------------------------------------
Unit 1.............................. 2,478 4,417 5,097 5,097
Unit 2.............................. 1,524 3,716 4,210 4,210
Unit 3.............................. 2,563 4,652 5,224 5,224
Unit 4.............................. 3,275 9,171 10,060 10,060
Unit 5.............................. 3,284 9,195 10,086 10,086
----------------------------------------------------------------------------------------------------------------
Cost Effectiveness of Controls ($/ton)
----------------------------------------------------------------------------------------------------------------
Unit 1.............................. 249 3,758 3,284 3,298
Unit 2.............................. 404 4,803 4,314 4,329
Unit 3.............................. 275 3,646 3,314 3,298
Unit 4.............................. 699 4,341 3,957 4,167
Unit 5.............................. 697 4,330 3,947 4,156
----------------------------------------------------------------------------------------------------------------
Table 8--FCPP Cost Effectiveness for PM Based on EPA Revisions
----------------------------------------------------------------------------------------------------------------
Upstream ESP Upstream baghouse Wet metal ESP Wet membrane ESP
----------------------------------------------------------------------------------------------------------------
Tons of PM Reduced per Year (tpy)
----------------------------------------------------------------------------------------------------------------
Unit 1.............................. 92 92 92 92
Unit 2.............................. 123 123 123 123
Unit 3.............................. 375 375 375 375
----------------------------------------------------------------------------------------------------------------
Cost Effectiveness of Controls ($/ton)
----------------------------------------------------------------------------------------------------------------
Unit 1.............................. 60,691 82,334 52,378 38,074
Unit 2.............................. 55,556 74,143 39,968 29,054
Unit 3.............................. 16,074 23,867 23,867 10,808
----------------------------------------------------------------------------------------------------------------
[[Page 44320]]
The National Park Service (NPS) calculated the cost effectiveness
of SCR using only the estimates and allowed categories of costs from
EPA's Air Pollution Control Costs Manual. The NPS costs of compliance
and cost effectiveness are shown in Table 9. NPS assumed post-SCR
NOX emissions of 0.06 lb/MMBtu. The capital and annual costs
of SCR the NPS estimated using the EPA Control Cost Manual are
considerably lower than those estimated by APS.
Table 9--NPS's Estimated SCR Costs of Compliance for FCPP
----------------------------------------------------------------------------------------------------------------
Cost
Total capital Total annual cost effectiveness
cost (ton)
----------------------------------------------------------------------------------------------------------------
Unit 1................................................. $18,508,764 $2,983,004 $1,558
Unit 2................................................. 18,508,764 3,052,010 1,469
Unit 3................................................. 22,187,577 3,497,117 1,684
Unit 4................................................. 52,788,968 9,838,997 1,185
Unit 5................................................. 52,788,968 9,213,942 1,357
----------------------------------------------------------------------------------------------------------------
In Tables 10 and 11, EPA has calculated the expected increase in
electricity generation costs to be borne by consumers in terms of
dollars per kilowatt hour ($/kWh), assuming 85% capacity. The
calculation is based on EPA's annual cost estimates in Tables 5 and 6.
DOE provides information on the average cost of electricity by state in
a given year.\11\ In 2009, the average cost of electricity in Arizona
for residential consumers was $0.0994/kWh, which was below the U.S.
average ($0.1128/kWh) and the continental U.S. maximum of $0.1993/kWh
in Connecticut.
---------------------------------------------------------------------------
\11\ http://www.eia.doe.gov/cneaf/electricity/epm/table5_6_b.html
Table 10--Increase in Electricity Costs From NOX Controls at FCPP
----------------------------------------------------------------------------------------------------------------
SCR + LNB + OFA
LNB/LNB + OFA kWh SCR kWh SCR + LNB kWh kWh
----------------------------------------------------------------------------------------------------------------
Unit 1.............................. $0.001 $0.015 $0.015 $0.015
Unit 2.............................. 0.001 0.016 0.016 0.016
Unit 3.............................. 0.001 0.011 0.012 0.012
Unit 4.............................. 0.001 0.009 0.009 0.009
Unit 5.............................. 0.001 0.009 0.009 0.009
----------------------------------------------------------------------------------------------------------------
Table 11--Increase in Electricity Costs From PM Controls at FCPP
----------------------------------------------------------------------------------------------------------------
Upstream baghouse Wet membrane ESP
Upstream ESP kWh kWh Wet metal ESP kWh kWh
----------------------------------------------------------------------------------------------------------------
Unit 1.............................. $0.005 $0.007 $0.004 $0.003
Unit 2.............................. 0.006 0.008 0.004 0.003
Unit 3.............................. 0.004 0.006 0.006 0.003
----------------------------------------------------------------------------------------------------------------
EPA requests comments on the data used to estimate the cost of
compliance for the different levels of control for NOX and
PM for FCPP.
2. NGS
a. Cost of Compliance
The cost estimates provided by SRP (updated in the 2008 submissions
to EPA) are included in Table 12 for different control options for
NOX. The NOX control options included in Table 12
are (1) LNB plus Separated Overfire Air (SOFA) on all three units, (2)
SCR on Units 1 and 3, LNB + SOFA on Unit 2, and (3) SCR + LNB + SOFA on
all three units.
Table 12--NGS Costs of Compliance for NOX Based on SRP Analysis
----------------------------------------------------------------------------------------------------------------
SCR + LNB + SOFA
LNB + SOFA (All (Units 1 & 3); SCR + LNB + SOFA
units) LNB + SOFA (Unit (All units)
2)
----------------------------------------------------------------------------------------------------------------
Total Capital Investment
----------------------------------------------------------------------------------------------------------------
Unit 1................................................. $14,000,000 $212,000,000 $212,000,000
Unit 2................................................. 14,000,000 14,000,000 281,000,000
Unit 3................................................. 14,000,000 212,000,000 212,000,000
----------------------------------------------------------------------------------------------------------------
[[Page 44321]]
Total Annual Cost
----------------------------------------------------------------------------------------------------------------
Unit 1................................................. 1,622,000 28,951,500 28,951,500
Unit 2................................................. 1,622,000 36,945,000 36,945,000
Unit 3................................................. 1,622,000 28,951,500 28,951,500
----------------------------------------------------------------------------------------------------------------
The higher retrofit cost of SCR on Unit 2 compared to Units 1 and 3
is a result of the physical layout of the coal conveyor and its
supports in relation to Unit 2. Because of limited access for
construction cranes and equipment, and to make room for the SCR and
fans by demolishing the remainder of the old Unit 2 chimney, costs for
the Unit 2 retrofit are anticipated to be higher than for Units 1 and
3.\12\
---------------------------------------------------------------------------
\12\ See July 29, 2008 Letter from Kevin Wanttaja (SRP) to
Deborah Jordan (EPA) and its attachment: July 25, 2008 Final Report
for SCR and SNCR Cost Study, prepared by Sargent and Lundy.
---------------------------------------------------------------------------
b. Cost Effectiveness
In determining the cost effectiveness of controls, SRP estimated
NOX emissions reductions using baseline emission rates of:
0.49 lb/MMBtu for Unit 1; 0.45 lb/MMBtu for Unit 2; 0.46 lb/MMBtu for
Unit 3. For the various control options, SRP estimated emissions
reductions from: LNB + SOFA of 47-51% to achieve 0.24 lb/MMBtu; and
from SCR of 82-84% to achieve 0.08 lb/MMBtu.
Table 13 lists the reduction in NOX emissions and cost
effectiveness estimated by SRP for the three control scenarios listed
in Table 12.
Table 13--SRP Emissions Reductions and Cost Effectiveness for NOX
----------------------------------------------------------------------------------------------------------------
SCR + LNB + SOFA
LNB + SOFA (All (Units 1 & 3); SCR + LNB + SOFA
units) LNB + SOFA (Unit (All units)
2)
----------------------------------------------------------------------------------------------------------------
NOX Emissions Reductions (tpy)
----------------------------------------------------------------------------------------------------------------
Unit 1................................................. 9,631 15,794 15,794
Unit 2................................................. 8,667 8,667 15,271
Unit 3................................................. 8,824 15,241 15,241
----------------------------------------------------------------------------------------------------------------
Cost Effectiveness ($/ton)
----------------------------------------------------------------------------------------------------------------
Unit 1................................................. 168 1,833 1,833
Unit 2................................................. 187 187 2,419
Unit 3................................................. 184 1,900 1,900
----------------------------------------------------------------------------------------------------------------
Appendix Y of the BART Guidelines states that average cost
effectiveness should be based on the annualized cost and the difference
between baseline annual emissions and annual emissions with the control
technology. In calculating the cost effectiveness, it appears SRP used
the same 24-hour average actual emission rate from the highest emitting
day used for its modeling inputs, rather than an annual average rate.
Therefore, EPA has revised SRP's estimated NOX emissions
reductions by starting with baseline emission rates for NOX
averaged over 2004-2006 of: 0.35 lb/MMBtu for Unit 1; 0.37 lb/MMBtu for
Unit 2; 0.31 lb/MMBtu for Unit 3. The revised emission reductions and
cost effectiveness estimates are provided in Table 14.
Table 14--EPA Emissions Reductions and Cost Effectiveness for NOX
----------------------------------------------------------------------------------------------------------------
SCR + LNB + SOFA
LNB + SOFA (All (Units 1 & 3); SCR + LNB + SOFA
units) LNB + SOFA (Unit (All units)
2)
----------------------------------------------------------------------------------------------------------------
NOX Emissions Reductions (tpy)
----------------------------------------------------------------------------------------------------------------
Unit 1................................................. 3,658 9,643 9,643
Unit 2................................................. 4,208 4,208 9,888
Unit 3................................................. 2,284 8,158 8,158
----------------------------------------------------------------------------------------------------------------
Cost Effectiveness ($/ton)
----------------------------------------------------------------------------------------------------------------
Unit 1................................................. 443 3,002 3,002
Unit 2................................................. 385 385 3,736
[[Page 44322]]
Unit 3................................................. 710 3,549 3,549
----------------------------------------------------------------------------------------------------------------
The NPS calculated the cost effectiveness of SCR + LNB + SOFA using
only the estimates and allowed categories of costs from EPA's Air
Pollution Control Costs Manual. The NPS costs of compliance and cost
effectiveness are shown in Table 15. NPS assumed post-SCR
NOX emissions of 0.05 lb/MMBtu. NPS accounts for the higher
retrofit costs associated with Unit 2 by applying a larger retrofit
factor associated with physically difficult retrofits on Unit 2
compared to Units 1 and 3. Note that the capital and annual costs of
SCR estimated using the EPA Control Cost Manual are considerably lower
than those estimated by SRP.
Table 15--NPS Costs of Controls and Cost Effectiveness for SCR
----------------------------------------------------------------------------------------------------------------
Cost
Total capital Total annual cost effectiveness
cost (ton)
----------------------------------------------------------------------------------------------------------------
Unit 1................................................. $71,983,100 $12,065,299 $1,059
Unit 2................................................. 66,138,162 14,589,766 1,528
Unit 3................................................. 68,642,323 11,870,003 1,317
----------------------------------------------------------------------------------------------------------------
EPA calculated the expected increase in electricity generation
costs to consumers in $/kWh, assuming 85% capacity in Table 16.
Table 16--Increase in Electricity Costs From NOX Controls at NGS
----------------------------------------------------------------------------------------------------------------
SCR + LNB + SOFA
LNB + SOFA (All (Units 1&3); LNB SCR + LNB + SOFA
Units) kWh + SOFA (Unit 2) (All Units) 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 NOX control scenarios, EPA
considered another SCR control option that was not addressed by SRP.
Based on EPA's understanding of the location of the coal-feed line and
the physical layout of Unit 2, EPA is requesting comment on the
application of half an SCR to Unit 2. As configured, the flue gas from
Unit 2 is split in half with each half containing its own separate hot-
side ESP and FGD. Because the flue gas is already split, and because
the coal-feed line impedes only one side of the Unit 2 split, SCR may
be applied to half of Unit 2 so that the difficult retrofit associated
with the relocation of the coal-feed line can be avoided. EPA estimates
that the application of half-SCR on Unit 2 would require a total
capital investment of $106 million, a total annual cost of $14.5
million, result in NOX reductions of over 7000 tpy (based on
control to 0.14 lb/MMBtu) with a cost effectiveness of $2000/ton and an
increased electricity generation cost of $0.003/kWh.
In the November 2007 BART Analysis, SRP states that PM emissions
controlled by hot-side ESPs in combination with wet scrubbers
effectively limited PM emissions to less than 0.03 lb/MMBtu and did not
include a BART analysis for further retrofit controls for
PM10. In a letter dated December 12, 2008, NGS proposed a
BART emission limit for PM of 0.05 lb/MMBtu. No additional discussions
of modeling or other analyses for PM control at NGS are included in
this ANPR.
EPA requests comment on the data provided above to estimate the
costs of compliance for BART controls at NGS.
B. Factor 5: Degree of Visibility Improvement
1. FCPP
a. Visibility Modeling Scenarios
APS's contractor, AECOM, conducted visibility modeling using
CALPUFF \13\ based on a number of selected inputs. APS used its
modeling results to estimate anticipated visibility improvement from
the four different control technology options at the mandatory Class I
Federal areas within a 300 km radius.
EPA disagrees with and is requesting comment on a number of the
inputs APS used for modeling. EPA has selected alternative inputs that
we have determined are more representative. We have also modeled the
resulting visibility improvement at the Class I areas based on our
revised inputs. EPA is specifically requesting comment on EPA's and
APS's selection of inputs. EPA's modeled results, also using CALPUFF,
are presented below in Tables 17-21. The modeling scenarios are:
---------------------------------------------------------------------------
\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 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]'').
[[Page 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 NOX on Units 1-5 (modeled by APS)
C2. LNB for NOX on Units 1 and 2 and LNB + OFA on Units
3-5 (modeled by EPA)
D. SCR for NOX on Units 3-5 (modeled by EPA)
E1. SCR + LNB + OFA for NOX on Units 1-5 (modeled by APS)
E2. SCR for NOX on Units 1-5 (modeled by EPA)
APS and EPA modeled baseline and control scenarios using
meteorological data from 2001-2003. The baseline scenario uses heat
input and pollutant emission rates based on the 24-hour average actual
emission rate from the highest emitting day of the meteorological
period. The modeling scenarios listed above in C1/C2 and E1/E2 are
based on the application of the same, or similar, control technologies
but are listed as distinct modeling scenarios because EPA used
different emission inputs than APS.
b. EPA Modifications to Emission Rate Inputs
The Appendix Y BART Guidelines state that baseline heat input and
pollutant emission rates should be based on the 24-hour average actual
emission rate from the highest emitting day of the meteorological
period modeled. Although the modeling period for the BART analysis
submitted by APS is 2001-2003, APS used heat input, NOX,
SO2, and PM emission rates from 2002-2006. Based on our
review of the 2001-2003 emissions data that APS reported to the EPA
Clean Air Markets Division (CAMD), we have determined that the heat
input and baseline NOX emission rates inputs were generally
appropriate, except that several of the highest emitting days for
NOX and heat input occurred in 2001. Therefore, EPA revised
the highest heat input rate for Units 1, 3, and 5 based on the 2001-
2003 meteorological period. For NOX emissions, the highest
emitting days for Units 1,2, 3, and 5 occurred in 2001 (over the 2001-
2003 period), therefore, we also revised the baseline NOX
emission rate for those units. Data from CAMD for Unit 2 and 4
generally agreed with emission inputs used by APS. For SO2
emissions, because the SO2 control efficiency for Units 4
and 5 recently increased to 88%, EPA considers it more appropriate to
rely on a more recent period (2006-2007) for SO2 emissions
for Units 4 and 5, rather than using SO2 data from the 2001-
2003 meteorological period.
CALPUFF modeling requires additional inputs, including
SO4, representing condensable inorganic PM and fine and
coarse filterable PM. For SO4, APS estimated that the
condensable inorganic PM was entirely represented by sulfuric acid
(H2SO4) formed during the combustion process
(Scenarios A--C), or from the combustion process together with
reactions on the SCR catalyst (Scenarios D and E). APS and EPA both
relied on the H2SO4 calculation methodology
provided by the Electric Power Research Institute (``EPRI''). \14\ The
EPRI method relies on characterization of various sources and sinks of
H2SO4 in the boiler and downstream components,
such as the air preheater, and particulate matter (PM) and
SO2 control devices. For the baseline and non-SCR emissions
scenarios (Scenarios A-C), the main difference between APS's and EPA's
calculations for H2SO4 arises from the assumed
loss of H2SO4 in the air preheater. APS used a
penetration factor \15\ of 0.9 whereas EPA used a penetration factor of
0.49, which is consistent with the 2008 EPRI guidelines.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
Because CAMD data is not available for PM, we relied on filterable
PM emissions used in APS's revised modeling analysis (Supplemental
submitted November 2008), based on the maximum of six stack test
results from the 2002-2006 period for each unit. APS additionally
provided the stack test results in a spreadsheet for each unit over
2002-2006. Although APS reported using the worst-case stack test values
in their Supplemental Modeling Report, the lb/MMBtu PM values in Table
5-2 do not match the highest stack test results in the APS's
spreadsheet. Therefore, EPA revised the filterable PM values for Units
1-3. We then applied values from AP-42 that estimate for a dry bottom
boiler with scrubber (Units 1-3), 71% of filterable PM is
PM10, and 51% of filterable PM is fine PM10
(i.e., PM2.5), thus 20% of filterable PM is coarse
PM10, i.e., 71%-51%. For a dry bottom boiler with a baghouse
(Units 4 and 5), AP-42 estimates that 92% of filterable PM is
PM10, and 53% of filterable PM is fine PM10
(i.e., PM2.5), thus 39% of filterable PM is coarse
PM10, i.e., 92%-53%. APS also estimated elemental carbon
(EC) to be 3.7% of the PM2.5, based on Table 6 of a 2002
draft report prepared for EPA.\16\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
In addition to the estimates for PM fine described above, EPA
additionally revised the modeling inputs for PM fine to include
emissions of hydrogen chloride (HCl) and hydrogen fluoride (HF). AP-42
(1.1 Bituminous and Subbituminous Coal Combustion) provides a single
emission factor each for HCl and HF from all coal and boiler types. APS
assumed H2SO4 to be the only contributor to
condensable inorganic PM, and the NPS raised concerns about the
exclusion of HCl and HF and recommended these two compounds be factored
into the CPM-IOR (SO4) modeling input. Method 202 for
measuring condensable PM does not capture HCl and HF, therefore, EPA
added these emissions to PM fine rather than SO4.
HCl and HF emission factors in AP-42 (Table 1.1-15) are based on a
lb/ton coal basis (1.2 lbs HCl per ton of coal and 0.15 lb HF per ton
of coal, which converts to 0.016 lb HCl/mmbtu and 0.007 lb HF/mmbtu
using 10496 Btu/lb coal). Footnote (a) to Table 1.1-15 in AP-42 states
that these factors apply to both controlled and uncontrolled sources.
The HCl and HF emission factors refer to a 1985 report on HCl and HF
prepared for the NAPAP inventory.\17\ This 1985 report shows that the
uncontrolled and controlled emission factors for HCl and HF were
considered to be the same only because wet scrubbers and FGD systems,
which are the only controls used on boilers that have a significant
effect on HCl and HF removal, were (at the time) used to control only a
small percentage of coal burned in utility boilers (see footnote (a)
from Tables 3-6 and 3-7 from the 1985 report). Given that 2 units at
FCPP use wet FGD and 3 units use venturi scrubbers for SO2
control, EPA did not apply the AP-42 emission factor ``as is'' to FCPP.
Furthermore, given that the chlorine content of the coal used by FCPP
is much lower than coal from other parts of the U.S., we scaled the HCl
emission factor (based on 46 sites from several parts of the country
\18\) for subbituminous coal to account for the low Cl content of FCPP
coal compared to average Cl content of U.S. coal.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
[[Page 44324]]
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.
---------------------------------------------------------------------------
\19\ Electric Utility Mercury Information Collection Request
(OMB Control Number 2060-0396): http://www.epa.gov/ttn/atw/combust/utiltox/utoxpg.html#DA2.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\20\ http://energy.er.usgs.gov/coalqual.htm#submit.
\21\ Based on samples D176206 and D202211.
---------------------------------------------------------------------------
Using the scaled emission factors of 0.13 lb HCl/ton coal and 0.18
lb HF/ton coal, EPA accounted for additional loss of HCl and HF from
the use of flue gas desulfurization (FGD) or venturi scrubbers. Page 19
of the 1985 EPA report describes that wet scrubbers are expected to
provide approximately 80% control of HCl and HF from coal-fired utility
boilers, and removal of HCl from flue gases with FGD systems is very
high (with sodium bicarbonate systems providing 95% control), but
little data are available to quantify the HF removal efficiency of FGD
systems. We assumed the FGD and venturi scrubbers provided 80% control
of HCl and HF. Thus, our HCl and HF emission factors for FCPP are 0.015
lb HCl/MMBtu and 0.0020 lb HF/MMBtu. These HCl and HF emissions were
applied as inputs to PM fine for all modeling scenarios.
Table 17--APS and EPA Baseline Emission Rates
[Scenario A]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Unit 1 Unit 2 Unit 3 Unit 4 Unit 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
APS Modeling Inputs for Baseline Case (all units in lb/hr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2...................................................... 464.17 615.12 995.26 2,026.10 2,130.76
SO4...................................................... 3.35 3.78 4.65 1.03 1.03
NOX...................................................... 1,841.37 1,567.66 1,926.23 5,015.98 4,444.04
SOA...................................................... 8.35 9.41 11.58 32.00 32.00
PM fine.................................................. 30.74 47.87 52.90 100.93 48.00
PM coarse................................................ 12.52 19.49 21.54 77.12 36.67
EC....................................................... 1.18 1.84 2.03 3.88 1.84
--------------------------------------------------------------------------------------------------------------------------------------------------------
EPA Modeling Inputs for Baseline Case (all units in lb/hr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2...................................................... 522.54 615.12 1,042.09 2,026.10 2,131.85
SO4...................................................... 2.06 2.06 2.65 0.51 0.51
NOX...................................................... 2,020.14 1,599.47 1,970.80 5,015.98 4,508.56
SOA...................................................... 9.40 9.41 12.13 32.00 32.20
PM fine.................................................. 46.29 65.99 70.18 128.93 76.20
PM coarse................................................ 15.50 23.52 24.26 77.12 36.69
EC....................................................... 1.46 2.22 2.29 3.88 1.85
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table 18--APS and EPA Emission for PM Control on Units 1-3
[Scenario B]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Unit 1 Unit 2 Unit 3 Unit 4 Unit 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
APS Modeling Inputs for Baseline Case (all units in lb/hr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2...................................................... 464.17 615.12 995.26 2,026.10 2,130.76
SO4...................................................... 0.34 0.38 0.47 1.03 1.03
NOX...................................................... 1,841.37 1,567.66 1,926.23 5,015.98 4,444.04
SOA...................................................... 8.35 9.41 11.58 32.00 32.00
PM fine.................................................. 15.34 20.39 22.54 100.93 48.00
PM coarse................................................ 11.72 15.58 17.22 77.12 36.67
EC....................................................... 0.59 0.78 0.87 3.88 1.84
--------------------------------------------------------------------------------------------------------------------------------------------------------
EPA Modeling Inputs for Baseline Case (all units in lb/hr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2...................................................... 522.54 615.12 1,042.09 2,026.10 2,131.85
SO4...................................................... 0.21 0.21 0.27 0.51 0.51
NOX...................................................... 2,020.14 1,599.47 1,970.80 5,015.98 4,508.56
SOA...................................................... 9.40 9.41 12.13 32.00 32.20
[[Page 44325]]
PM fine.................................................. 25.49 28.63 34.21 128.93 76.20
PM coarse................................................ 13.19 15.58 18.03 77.12 36.69
EC....................................................... 0.66 0.78 0.91 3.88 1.85
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table 19--APS and EPA Emission for PM Control on Units 1-3
[Scenario C]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Unit 1 Unit 2 Unit 3 Unit 4 Unit 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
APS Modeling Inputs for LNB + OFA (Scenario C1) (in lb/hr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2...................................................... 464.17 615.12 995.26 2,026.10 2,130.76
SO4...................................................... 3.35 3.78 4.65 1.03 1.03
NOX...................................................... 1,010.91 1,051.90 1,078.69 3,561.35 3,155.27
SOA...................................................... 8.35 9.41 11.58 32.00 32.00
PM fine.................................................. 30.74 47.87 52.90 100.93 48.00
PM coarse................................................ 12.52 19.49 21.54 77.12 36.67
EC....................................................... 1.18 1.84 2.03 3.88 1.84
--------------------------------------------------------------------------------------------------------------------------------------------------------
EPA Modeling Inputs for LNB/OFA (Scenario C2) (in lb/hr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2...................................................... 522.54 615.12 1,042.09 2,026.10 2,131.85
SO4...................................................... 2.06 2.06 2.65 0.51 0.51
NOX...................................................... 1,109.06 1,073.25 1,103.65 3,561.35 3,201.08
SOA...................................................... 9.40 9.41 12.13 32.00 32.20
PM fine.................................................. 46.29 65.99 70.18 128.93 76.20
PM coarse................................................ 15.50 23.52 24.26 77.12 36.69
EC....................................................... 1.46 2.22 2.29 3.88 1.85
--------------------------------------------------------------------------------------------------------------------------------------------------------
EPA also disagrees with APS's evaluation of sulfuric acid
emissions. Sulfuric acid emissions are estimated to increase as a
result of operating an SCR due to additional oxidation of
SO2 to SO3 on the SCR catalyst. APS used a 1%
conversion rate from the SCR catalyst. Yet a Prevention of Significant
Deterioration (PSD) permit issued June 2, 2009, to Coronado Generating
Station by the ADEQ \22\ required the use of an ultra-low conversion
catalyst (0.5% conversion) as Best Available Control Technology (BACT).
EPA has determined that APS could also use an ultra-low conversion
catalyst. Therefore, in our calculation of H2SO4
emissions from the addition of the SCR, we accounted for a 0.5%
conversion of SO2 to SO3.
---------------------------------------------------------------------------
\22\ See http://www.azdeq.gov/environ/air/permits/download/pastmonth.pdf.
---------------------------------------------------------------------------
For emissions of ammonia (NH3) resulting from SCR, EPA
followed the calculation methodology APS used in its supplemental
modeling analysis for FCPP (dated November 2008).
Table 20--EPA Emissions for SCR on Units 3-5
[Scenario D]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Unit 1 Unit 2 Unit 3 Unit 4 Unit 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
EPA Modeling Inputs for SCR on Units 3-5, No Control Units 1 and 2 (in lb/hr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2...................................................... 522.54 615.12 1,042.09 2,026.10 2,131.85
SO4...................................................... 2.06 2.06 12.52 2.52 2.54
NOX...................................................... 2,020.14 1,599.47 472.99 1,203.84 1,082.05
SOA...................................................... 9.40 9.41 12.13 32.00 32.20
PM fine.................................................. 46.29 65.99 70.18 128.93 76.20
PM coarse................................................ 15.50 23.52 24.26 77.12 36.69
EC....................................................... 1.46 2.22 2.29 3.88 1.85
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table 21--APS and EPA Emissions for SCR on Units 1-5
[Scenario E]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Unit 1 Unit 2 Unit 3 Unit 4 Unit 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
APS Modeling Inputs for SCR + LNB + OFA (Scenario E1) (in lb/hr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2...................................................... 464.17 615.12 995.26 2,026.10 2,130.76
[[Page 44326]]
SO4...................................................... 30.71 34.61 42.61 9.53 9.58
NOX...................................................... 147.31 141.09 192.62 601.92 533.29
SOA...................................................... 8.35 9.41 11.58 32.00 32.00
PM fine.................................................. 30.74 47.87 52.90 100.93 48.00
PM coarse................................................ 12.52 19.49 21.54 77.12 36.67
EC....................................................... 1.18 1.84 2.03 3.88 1.84
--------------------------------------------------------------------------------------------------------------------------------------------------------
EPA Modeling Inputs for SCR (Scenario E2) (in lb/hr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2...................................................... 522.54 615.12 1,042.09 2,026.10 2,131.85
SO4...................................................... 9.70 9.71 12.52 2.52 2.54
NOX...................................................... 484.83 383.87 472.99 1,203.84 1,082.05
SOA...................................................... 9.40 9.41 12.13 32.00 32.20
PM fine.................................................. 46.29 65.99 70.18 128.93 76.20
PM coarse................................................ 15.50 23.52 24.26 77.12 36.69
EC....................................................... 1.46 2.22 2.29 3.88 1.85
--------------------------------------------------------------------------------------------------------------------------------------------------------
c. Ammonia Background
In addition to the different CALPUFF emission rates described
above, EPA additionally revised some post-processor 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.
---------------------------------------------------------------------------
\23\ Letter from Rick Cables (Forest Service R2 Regional
Forester) and Corbin Newman (Forest Service R3 Regional Forester) to
Deborah Jordan (EPA Region 9 Air Division Director) dated March 17,
2009.
---------------------------------------------------------------------------
Ammonia is important because it is a precursor to particulate
ammonium sulfate and ammonium nitrate which degrades visibility. It is
present in the air from both natural and anthropogenic sources. The
latter may include ammonia slip from the use of ammonia in SCR and SNCR
technologies to control NOX emissions.
In our modeling input for ammonia, EPA assumed that the remaining
ammonia in the flue gas following SCR reacts to form ammonium sulfate
or ammonium bisulfate before exiting the stack. This particulate
ammonium is represented in the modeling as sulfate (SO4)
emissions. Thus, EPA addressed ammonia solely as a background
concentration.
Very little monitored ammonia data is available. The default
recommended ammonia background value for arid regions is 1 ppb, as
described in the IWAQM Phase 2 document.\24\ Alternative levels may be
used if supported by data. To address concerns expressed by APS in
their January 2008 BART modeling protocol (p. 4-1) that CALPUFF over-
predicts ammonium nitrate in winter, EPA estimated ammonia background
for all Class I areas (except Mesa Verde National Park, see below) by
back-calculating from measurements at monitors in the areas run by the
IMPROVE program.\25\ IMPROVE monitors do not measure ammonia directly;
rather, they measure particulate sulfate and nitrate. In the
atmosphere, particulate sulfate and nitrate are essentially all in the
form of ammonium sulfate and ammonium nitrate, respectively. Applying
their chemical formulas, EPA estimated a lower bound on the amount of
ammonia that must have been present to combine with gaseous sulfate and
nitrate in order to form the measured particulate sulfate and nitrate.
---------------------------------------------------------------------------
\24\ Interagency Workgroup On Air Quality Modeling (IWAQM) Phase
2 Summary Report And Recommendations For Modeling Long Range
Transport Impacts (EPA-454/R-98-019), EPA OAQPS, December 1998,
http://www.epa.gov/scram001/7thconf/calpuff/phase2.pdf.
\25\ http://vista.cira.colostate.edu/improve/.
---------------------------------------------------------------------------
EPA performed this back-calculation using 2005-2007 data for all 14
IMPROVE monitors at Class I areas in the modeling domains. For each
monitor, EPA used the maximum calculated value for each calendar month
to represent the month. Then, for each month, EPA averaged over all
monitors, resulting in a single value for each of the 12 calendar
months. For the months of May and July, this back-calculation 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 mid-range of the various stations plotted. The
results ranged from 1.0 ppb in winter to 1.5 ppb in summer. See Table
22.
---------------------------------------------------------------------------
\26\ Mark E. Sather et al., 2008. ``Baseline ambient gaseous
ammonia concentrations in the Four Corners area and eastern
Oklahoma, USA''. Journal of Environmental Monitoring, 2008, 10,
1319-1325, DOI: 10.1039/b807984f.
Table 22--Ammonia Background Concentration in ppb (POSTUTIL Parameter BCKNH3) for FCPP
----------------------------------------------------------------------------------------------------------------
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
----------------------------------------------------------------------------------------------------------------
IWAQM default............... 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0
[[Page 44327]]
APS values.................. 0.2 0.2 0.5 0.5 1.0 1.0 1.0 1.0 1.0 0.5 0.5 0.2
EPA values.................. 0.8 0.7 0.7 1.0 1.0 1.3 1.0 1.0 1.0 1.0 1.0 0.9
EPA values for Mesa Verde... 1.0 1.0 1.3 1.3 1.3 1.3 1.5 1.5 1.5 1.5 1.3 1.0
----------------------------------------------------------------------------------------------------------------
d. Natural Background
The BART determination guidelines recommend that impacts of sources
should be estimated in deciviews relative to natural background.
CALPOST, a CALPUFF post-processor, uses background concentrations of
various pollutants to calculate the natural background visibility
impact. EPA used background concentrations from Table 2-1 of ``Guidance
for Estimating Natural Visibility Conditions Under the Regional Haze
Rule.'' \27\ Although the concentration for each pollutant is a single
value for the year, this method allows for monthly variation in its
visibility impact, which changes with relative humidity. The resulting
deciviews differ by roughly 1% from those resulting from the method
originally used by APS.
---------------------------------------------------------------------------
\27\ U.S. Environmental Protection Agency, EPA-454/B-03-005,
September 2003, on web page http://www.epa.gov/ttn/oarpg/t1pgm.html,
with direct link http://www.epa.gov/ttn/oarpg/t1/memoranda/rh_envcurhr_gd.pdf.
Table 23--Natural Background Concentrations for FCPP and NGS
------------------------------------------------------------------------
Concentration
CALPOST parameter Pollutant ([mu]g/m\3\)
------------------------------------------------------------------------
BKSO4........................ ammonium sulfate..... 0.12
BKNO3........................ ammonium nitrate..... 0.10
BKPMC........................ coarse particulates.. 3.00
BKOC......................... organic carbon....... 0.47
BKSOIL....................... soil................. 0.50
BKEC......................... elemental carbon..... 0.02
------------------------------------------------------------------------
e. Visibility Modeling Results
To assess results from the CALPUFF model and post-processing steps,
EPA used a least-squares regression analysis of all visibility modeling
output from the 2001-2003 modeling period to determine the percent
improvement in visibility (measured in deciviews) compared to the
baseline resulting from the application of control technologies. Table
24 shows EPA's modeled predicted visibility improvements at the 16
Class I areas within a 300 km radius of FCPP.
APS presented visibility improvement by comparing the 98th
percentile (8th highest) of the daily maximum deciview (dv) values from
CALPUFF per Class I area, averaged over 2001-2003. As outlined in the
1999 Regional Haze rule (64 FR 35725, July 1, 1999), a one deciview
change in haziness is a small but noticeable change in haziness under
most circumstances when viewing scenes in a Class I area. Table 25
presents the visibility impacts of the 98th percentile of daily maxima
for each Class I area for each year, averaged over 2001-2003,
determined for FCPP by APS. Table 26 presents the visibility impacts of
the 98th percentile of daily maxima from 2001-2003 for each Class I
area determined by EPA.\28\
---------------------------------------------------------------------------
\28\ EPA did not average the 98th percentiles from each year as
did APS, rather EPA used the 98th percentile from all three years
taken together. This does not significantly impact the overall
results.
Table 24--Percent Improvement in Deciview Impacts From EPA Modeling at Each Class I Area From PM and NOX
Controls at FCPP
----------------------------------------------------------------------------------------------------------------
Scenario B Scenario D Scenario E2
(Wet ESP) Scenario C2 (SCR 3-5) (SCR 1-5)
(%) (LNB) (%) (%) (%)
----------------------------------------------------------------------------------------------------------------
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
----------------------------------------------------------------------------------------------------------------
[[Page 44328]]
Table 25--Impacts of FCPP on Visibility (98th Percentile of Daily Maximum dv) at Sixteen Class I Areas as
Modeled by APS
----------------------------------------------------------------------------------------------------------------
Visibility impact (dv) after
applying:
Baseline --------------------------------------
Wet ESP (B) LNB (C1) SCR (E1)
----------------------------------------------------------------------------------------------------------------
Arches..................................................... 1.98 1.96 1.74 1.23
Bandolier.................................................. 1.71 1.70 1.57 1.12
Black Canyon............................................... 1.44 1.43 1.21 0.75
Canyonlands................................................ 2.25 2.23 2.06 1.67
Capitol Reef............................................... 1.74 1.73 1.53 1.15
Grand Canyon............................................... 1.07 1.07 0.95 0.66
Great Sand Dunes........................................... 1.02 1.02 1.02 0.62
La Garita.................................................. 1.36 1.36 1.08 0.58
Maroon Bells............................................... 1 0.81 0.66 0.35
Mesa Verde................................................. 3.17 3.14 3.01 2.73
Pecos...................................................... 1.55 1.54 1.31 0.88
Petrified Forest........................................... 1.21 1.20 1.05 0.68
San Pedro.................................................. 2.21 2.18 2.04 1.51
West Elk................................................... 1.22 1.21 1.03 0.56
Weminuche.................................................. 1.90 1.68 1.66 0.94
Wheeler Peak............................................... 1.20 1.19 0.97 0.64
----------------------------------------------------
Sum of Class I areas................................... 26.03 25.45 22.89 16.07
----------------------------------------------------------------------------------------------------------------
Table 26--Impacts of FCPP on Visibility (98th Percentile dv) on Sixteen Class I Areas as Modeled by EPA
----------------------------------------------------------------------------------------------------------------
Visibility Impact (dv) after applying:
Baseline ---------------------------------------------------
Wet ESP LNB (C2) SCR(D) SCR (E2)
----------------------------------------------------------------------------------------------------------------
Arches......................................... 4.03 4.02 3.24 2.55 1.83
Bandolier...................................... 2.91 2.90 2.25 1.81 1.38
Black Canyon................................... 2.36 2.36 1.89 1.44 1.01
Canyonlands.................................... 4.89 4.87 4.21 3.76 2.66
Capitol Reef................................... 3.21 3.20 2.44 1.87 1.48
Grand Canyon................................... 1.63 1.63 1.31 0.96 0.81
Great Sand Dunes............................... 1.21 1.20 0.91 0.67 0.54
La Garita...................................... 1.71 1.71 1.28 1.05 0.73
Maroon Bells................................... 1.04 1.04 0.77 0.57 0.43
Mesa Verde..................................... 6.48 6.45 5.47 4.90 3.89
Pecos.......................................... 2.11 2.10 1.65 1.34 1.06
Petrified Forest............................... 1.51 1.51 1.14 0.97 0.81
San Pedro...................................... 3.81 3.80 3.13 2.53 2.01
West Elk....................................... 1.86 1.86 1.41 1.06 0.75
Weminuche...................................... 2.79 2.77 2.16 1.58 1.17
Wheeler Peak................................... 1.50 1.50 1.17 0.93 0.74
----------------------------------------------------------------
Sum of Class I areas....................... 43.05 42.90 34.43 27.99 21.29
----------------------------------------------------------------------------------------------------------------
EPA used higher values for ammonia background concentration than
APS, which resulted in higher modeled visibility impacts of FCPP and
larger percent visibility improvement of controls compared to APS
modeling. Although the different inputs used by EPA changed the
absolute deciview values, it did not change the relative ranking of the
controls in terms of deciview benefit. The different natural background
concentrations EPA used compared to APS did not significantly change
the visibility modeling results.
In their March 16, 2009 letter to EPA, the USFS discusses the need
for a more comprehensive characterization of a facility's impacts,
particularly, for facilities like FCPP and NGS that affect visibility
at multiple Class I areas. To account for cumulative impacts, the USFS
suggested accounting for the total dv impact by summing across all days
for all Class I areas. EPA agrees that alternative visibility metrics
may assist in evaluating the visibility improvement associated with
various control options at FCPP and NGS, including taking an average of
the 98th percentile of all Class I areas or summing over all days for
all Class I areas. Table 27 presents an alternative visibility metric
that takes into account the size of the area over which controls
provide visibility benefits. The 98th percentile for each Class I area
is multiplied by its land area in 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\.
[[Page 44329]]
Table 27--Alternative Visibility Metric
----------------------------------------------------------------------------------------------------------------
Visibility Impact (dv-km\2\) after applying:
A (Baseline) ---------------------------------------------------------------
B (Wet ESP) C2 (LNB) D (SCR 3-5) E2 (SCR 1-5)
----------------------------------------------------------------------------------------------------------------
Arches.......................... 1,014 1,012 816 615 461
Bandolier....................... 249 246 193 156 119
Black Canyon.................... 121 121 89 76 53
Canyon-lands.................... 4,991 4,964 4,419 3,961 2,794
Capitol Reef.................... 2,433 2,427 1,849 1,405 1,113
Grand Canyon.................... 6,443 6,416 4,870 3,714 3,174
Great Sand Dunes................ 119 119 88 69 56
La Garita....................... 699 697 518 394 295
Maroon Bells.................... 571 569 415 315 238
Mesa Verde...................... 1,112 1,109 939 818 666
Pecos........................... 1,574 1,570 1,225 974 780
Petrified Forest................ 469 467 374 322 259
San Pedro....................... 505 503 430 347 265
West Elk........................ 2,996 2,988 2,221 1,614 1,207
Weminuche....................... 1,525 1,522 1,170 860 636
Wheeler Peak.................... 121 121 92 74 59
-------------------------------------------------------------------------------
Sum over all areas.......... 24,943 24,852 19,708 15,716 12,175
----------------------------------------------------------------------------------------------------------------
2. NGS
a. Visibility Modeling Scenarios
SRP conducted visibility modeling for NGS using CALPUFF based on
estimated emission rates of various pollutants as inputs for the model.
EPA conducted its own CALPUFF modeling using inputs that we determined
were more representative.
EPA then modeled anticipated visibility improvements for four
different options for installed control technologies. NGS's and EPA's
modeling inputs are set forth in Tables 28-32 below. The modeling
scenarios are:
A. Baseline Visibility Impact (modeled by NGS and EPA),
B. LNB + SOFA on Units 1-3 (modeled by NGS and EPA),
C. SCR + LNB + SOFA on Units 1 and 3, LNB + SOFA on Unit 2
(modeled by NGS and EPA),
D. SCR + LNB + SOFA on Units 1 and 3, Half-SCR + LNB + SOFA on
Unit 2 (modeled by EPA),
E. SCR on Units 1-3 (modeled by NGS and EPA).
Scenarios C and E modeled by SRP and EPA were not listed as
discrete modeling scenarios as they were for FCPP because the emission
inputs for NGS from SRP and EPA, though different for PM fine and
SO4, are more similar to each other in terms of
NOX control than for FCPP. For Scenario E, SRP assumed
NOX emissions to be 0.08 lb/MMBtu, whereas EPA assumed 0.06
lb/MMBtu.
b. EPA Modifications to Emission Rate Inputs
Similar to FCPP, for the baseline and non-SCR emissions scenarios
(Scenarios A and B), the main difference between SRP and EPA
calculations for H2SO4 were from the assumed loss
of H2SO4 in the air preheater. SRP used a
penetration factor of 0.9 whereas EPA used a penetration factor of
0.49, which is consistent with the 2008 EPRI guidelines. Similarly for
H2SO4 emissions resulting from the SCR scenarios,
EPA used a 0.5% SO2 to SO3 conversion rate based
on the application of an ultra-low oxidation catalyst.
For all modeling scenarios, EPA included HCl and HF emissions as PM
fine modeling inputs and scaled them in a similar manner described for
FCPP. For HCl, EPA used a scaled emission factor of 0.0025 lb/MMBtu,
and for HF, EPA used a scaled emission factor of 0.00086 lb/MMBtu.
Table 28--SRP and EPA Baseline Emission Rates (Scenario A)
----------------------------------------------------------------------------------------------------------------
Unit 1 Unit 2 Unit 3
----------------------------------------------------------------------------------------------------------------
SRP Baseline Modeling Inputs (in lb/hr)
----------------------------------------------------------------------------------------------------------------
SO2............................................................. 487.75 526.92 576.17
SO4............................................................. 4.18 4.48 4.36
NOX............................................................. 4,271.42 4,207.50 4,181.67
SOA............................................................. 35.18 37.69 36.63
PM fine......................................................... 63.86 55.27 79.28
PM coarse....................................................... 86.89 75.20 107.87
EC.............................................................. 2.45 2.12 3.05
----------------------------------------------------------------------------------------------------------------
EPA Baseline Modeling Inputs (in lb/hr)
----------------------------------------------------------------------------------------------------------------
SO2............................................................. 487.75 526.92 576.17
SO4............................................................. 3.62 3.87 3.76
NOX............................................................. 4,271.42 4,207.50 4,181.67
SOA............................................................. 35.18 37.69 36.63
PM fine......................................................... 93.41 86.93 110.05
PM coarse....................................................... 86.89 75.20 107.87
[[Page 44330]]
EC.............................................................. 2.45 2.12 3.05
----------------------------------------------------------------------------------------------------------------
Table 29--SRP and EPA Emissions for LNB + SOFA (Scenario B)
----------------------------------------------------------------------------------------------------------------
Unit 1 Unit 2 Unit 3
----------------------------------------------------------------------------------------------------------------
SRP Baseline Modeling Inputs (in lb/hr)
----------------------------------------------------------------------------------------------------------------
SO2............................................................. 487.75 526.92 576.17
SO4............................................................. 4.18 4.48 4.36
NOX............................................................. 2,110.74 2,261.63 2,197.78
SOA............................................................. 35.18 37.69 36.63
PM fine......................................................... 63.86 55.27 79.28
PM coarse....................................................... 86.89 75.20 107.87
EC.............................................................. 2.45 2.12 3.05
----------------------------------------------------------------------------------------------------------------
EPA Baseline Modeling Inputs (in lb/hr)
----------------------------------------------------------------------------------------------------------------
SO2............................................................. 487.75 526.92 576.17
SO4............................................................. 3.62 3.87 3.76
NOX............................................................. 2,110.74 2,261.63 2,197.78
SOA............................................................. 35.18 37.69 36.63
PM fine......................................................... 93.41 86.93 110.05
PM coarse....................................................... 86.89 75.20 107.87
EC.............................................................. 2.45 2.12 3.05
----------------------------------------------------------------------------------------------------------------
Table 30--SRP and EPA Emissions for SCR + LNB + SOFA on Units 1 and 3, LNB + SOFA on Unit 2 (Scenario C)
----------------------------------------------------------------------------------------------------------------
Unit 1 Unit 2 Unit 3
----------------------------------------------------------------------------------------------------------------
SRP Baseline Modeling Inputs (in lb/hr)
----------------------------------------------------------------------------------------------------------------
SO2............................................................. 487.75 526.92 576.17
SO4............................................................. 64.01 4.48 66.65
NOX............................................................. 703.58 2,261.63 732.59
SOA............................................................. 35.18 37.69 36.63
PM fine......................................................... 63.86 55.27 79.28
PM coarse....................................................... 86.89 75.20 107.87
EC.............................................................. 2.45 2.12 3.05
----------------------------------------------------------------------------------------------------------------
EPA Baseline Modeling Inputs (in lb/hr)
----------------------------------------------------------------------------------------------------------------
SO2............................................................. 487.75 526.92 576.17
SO4............................................................. 19.90 3.87 20.72
NOX............................................................. 615.63 2,261.63 641.02
SOA............................................................. 35.18 37.69 36.63
PM fine......................................................... 93.41 86.93 110.05
PM coarse....................................................... 86.89 75.20 107.87
EC.............................................................. 2.45 2.12 3.05
----------------------------------------------------------------------------------------------------------------
Table 31--EPA Emissions for SCR + LNB + SOFA on Units 1 and 3, Half-SCR + LNB + SOFA on Unit 2 (Scenario D)
----------------------------------------------------------------------------------------------------------------
Unit 1 Unit 2 Unit 3
----------------------------------------------------------------------------------------------------------------
EPA Baseline Modeling Inputs (in lb/hr)
----------------------------------------------------------------------------------------------------------------
SO2............................................................. 487.75 526.92 576.17
SO4............................................................. 19.90 12.60 20.72
NOX............................................................. 615.63 1,696.22 641.02
SOA............................................................. 35.18 37.69 36.63
PM fine......................................................... 93.41 86.93 110.05
PM coarse....................................................... 86.89 75.20 107.87
EC.............................................................. 2.45 2.12 3.05
----------------------------------------------------------------------------------------------------------------
[[Page 44331]]
Table 32--SRP and EPA Emissions for SCR + LNB + SOFA on Units 1--3 (Scenario E)
----------------------------------------------------------------------------------------------------------------
Unit 1 Unit 2 Unit 3
----------------------------------------------------------------------------------------------------------------
SRP Baseline Modeling Inputs (in lb/hr)
----------------------------------------------------------------------------------------------------------------
SO2............................................................. 487.75 526.92 576.17
SO4............................................................. 64.01 68.59 66.65
NOX............................................................. 703.58 753.88 732.59
SOA............................................................. 35.18 37.69 36.63
PM fine......................................................... 63.86 55.27 79.28
PM coarse....................................................... 86.89 75.20 107.87
EC.............................................................. 2.45 2.12 3.05
----------------------------------------------------------------------------------------------------------------
EPA Baseline Modeling Inputs (in lb/hr)
----------------------------------------------------------------------------------------------------------------
SO2............................................................. 487.75 526.92 576.17
SO4............................................................. 19.90 21.32 20.72
NOX............................................................. 615.63 659.64 641.02
SOA............................................................. 35.18 37.69 36.63
PM fine......................................................... 93.41 86.93 110.05
PM coarse....................................................... 86.89 75.20 107.87
EC.............................................................. 2.45 2.12 3.05
----------------------------------------------------------------------------------------------------------------
c. Ammonia Background and Natural Background
For ammonia background values at the Class I areas impacted by NGS,
EPA used the same ammonia values listed in Table 22 above and the same
natural background values listed in Table 23. See discussion of ammonia
back-calculation methodologies and changes to natural background
conditions described in Section II.B.1.
d. Visibility Modeling Results
To assess results from the CALPUFF model and post-processing steps,
EPA used a least-squares regression analysis of all visibility modeling
output from the 2001-2003 modeling period to determine the percent
improvement in visibility compared to the baseline resulting from the
application of control technologies. Table 33 shows EPA's modeled
predicted visibility improvements at the 11 Class I areas within a 300
km radius of NGS.
SRP presented visibility improvement by comparing the 98th
percentile (8th highest) of daily maximum deciview (dv) values from
CALPUFF per Class I area, averaged over 2001-2003. Table 34 presents
the visibility impacts of the 98th percentile of daily maxima for each
Class I area for each year, averaged over 2001-2003, determined for NGS
by SRP.
Table 35 presents the visibility impacts of the 98th percentile of
daily maxima over 2001-2003 for each Class I area determined by EPA.
Table 36 presents the alternative visibility metric determined by EPA
for each Class I area.
Table 33--Percent Improvement in Deciview Impacts From EPA Modeling at Each Class I Area From NOX Controls at
NGS
----------------------------------------------------------------------------------------------------------------
Scenario B Scenario C Scenario D Scenario E
(LNB) (SCR: 1&3) (\1/2\ SCR 2) (SCR: 1-3)
(percent) (percent) (percent) (percent)
----------------------------------------------------------------------------------------------------------------
Arches.......................................... 36 60 65 74
Bryce Canyon.................................... 26 47 53 63
Canyonlands..................................... 32 56 62 71
Capitol Reef.................................... 25 48 53 63
Grand Canyon.................................... 22 43 48 58
Mazatzal........................................ 38 60 65 72
Mesa Verde...................................... 40 63 68 76
Petrified Forest................................ 36 60 65 74
Pine Mountain................................... 38 59 64 71
Sycamore Canyon................................. 36 59 64 72
Zion............................................ 31 54 60 69
----------------------------------------------------------------------------------------------------------------
Table 34--Visibility Impacts (98th Percentile dv) of NGS on Eleven Class I Areas as Modeled by SRP
----------------------------------------------------------------------------------------------------------------
Visibility Impact (dv) after applying:
Baseline -----------------------------------------------
LNB (B) SCR (C) SCR (E)
----------------------------------------------------------------------------------------------------------------
Arches.......................................... 2.05 1.51 1.19 0.99
Bryce Canyon.................................... 2.00 1.58 1.36 1.23
Canyonlands..................................... 2.47 1.96 1.53 1.35
Capitol Reef.................................... 2.68 2.31 2.06 1.89
Grand Canyon.................................... 2.56 2.29 2.25 2.29
Mazatzal........................................ 0.71 0.47 0.41 0.38
Mesa Verde...................................... 1.42 1.04 0.77 0.58
[[Page 44332]]
Petrified Forest................................ 1.52 1.14 0.92 0.76
Pine Mountain................................... 0.66 0.46 0.38 0.34
Sycamore Canyon................................. 1.31 0.92 0.78 0.63
Zion............................................ 1.83 1.47 1.26 1.10
---------------------------------------------------------------
Sum of Class I areas........................ 19.29 15.15 12.88 11.54
----------------------------------------------------------------------------------------------------------------
Table 35--Visibility Impacts (98th Percentile dv) of NGS on Eleven Class I Areas as Modeled by EPA
----------------------------------------------------------------------------------------------------------------
Visibility Impact (dv) after applying:
Baseline ---------------------------------------------------------------
LNB (B) SCR (C) SCR (D) SCR (E)
----------------------------------------------------------------------------------------------------------------
Arches.......................... 3.25 2.08 1.33 1.16 0.89
Bryce Canyon.................... 3.66 2.44 1.57 1.39 1.10
Canyonlands..................... 4.37 2.98 1.90 1.65 1.25
Capitol Reef.................... 5.48 4.08 2.97 2.71 2.04
Grand Canyon.................... 5.41 4.35 3.34 3.06 2.46
Mazatzal........................ 1.16 0.73 0.48 0.45 0.37
Mesa Verde...................... 2.24 1.33 0.78 0.67 0.52
Petrified Forest................ 2.62 1.54 1.00 0.86 0.66
Pine Mountain................... 1.08 0.64 0.42 0.38 0.32
Sycamore Canyon................. 1.96 1.28 0.80 0.71 0.59
Zion............................ 3.73 2.65 1.65 1.44 1.05
-------------------------------------------------------------------------------
Sum of Class I areas........ 34.95 24.10 16.25 14.48 11.23
----------------------------------------------------------------------------------------------------------------
Table 36--Alternative Visibility Metric
----------------------------------------------------------------------------------------------------------------
Visibility Impact (dv-km2) after applying:
---------------------------------------------------------------
A (Baseline) D (\1/2\ SCR
B (LNB) C (SCR: 1&3) 2) E (SCR: 1-3)
----------------------------------------------------------------------------------------------------------------
Arches.......................... 812 514 336 293 223
Bryce Canyon.................... 495 324 212 187 147
Canyonlands..................... 4,649 3,071 2,022 1,741 1,320
Capitol Reef.................... 4,184 3,127 2,233 2,031 1,566
Grand Canyon.................... 21,399 17,219 13,157 12,033 9,698
Mazatzal........................ 978 618 410 367 297
Mesa Verde...................... 383 226 135 115 87
Petrified Forest................ 847 515 313 270 217
Pine Mountain................... 72 44 28 25 22
Sycamore Canyon................. 390 235 162 144 120
Zion............................ 1,574 1,104 739 649 494
-------------------------------------------------------------------------------
Sum over all areas.......... 24,943 19,708 19,708 15,716 19,708
----------------------------------------------------------------------------------------------------------------
C. Factor 2: Energy and Non-Air Quality Impacts
1. FCPP
The application of LNB and LNB + OFA to control NOX by
staging combustion to reduce boiler temperatures will result in reduced
NOX formation as well as reduced combustion efficiency. The
reduced combustion temperatures thus result in increased emissions of
carbon monoxide (CO), volatile organic compounds (VOCs), and increased
unburned carbon in the fly ash, known as loss of ignition (LOI).
Increases in CO, and potential increases in VOC, from LNB or LNB + OFA,
may trigger the Prevention of Significant Deterioration (PSD)
permitting requirements, including the application of Best Available
Control Technology (BACT) if the emission increases exceed the 100 tpy
CO and 40 tpy VOC significance thresholds. Increased LOI in fly ash may
reduce the desirability of the fly ash for sale and reuse.
Emissions of sulfuric acid (H2SO4) from coal
fired power plants result from the conversion of sulfur in the coal
into SO2 and further oxidation to SO3 during the
combustion process in the boiler. SO3 can then combine with
moisture (H2O) in the flue gas to form
H2SO4. Fuels high in vanadium can catalyze
SO2 to SO3 at higher rates than low vanadium
fuels and result in higher H2SO4 emissions. The
use of SCR catalysts, in particular, SCR catalysts that use vanadium,
can result in increased emissions of H2SO4.
Emissions increases in H2SO4 at existing major
stationary sources as a result of the application of SCR for
NOX control will trigger PSD permitting requirements,
including the application of BACT, if they exceed the
H2SO4 significance threshold of 7 tpy. Add-on
control technologies exist to help reduce H2SO4
emissions following SO2 to SO3 conversion from
combustion and SCR,
[[Page 44333]]
including injection of reagents (e.g., hydrated lime, sodium bisulfite)
to convert H2SO4 to particulate matter that is
then captured by downstream PM control devices, such as baghouses.
Based on discussions with URS Corporation, the commercial vendor for
sodium bisulfite (SBS) injection technology, the expected low
concentrations of H2SO4 at FCPP, compared to
coal-fired facilities in the Midwestern and Eastern states, suggests
the application of reagent injection will not effectively reduce
H2SO4 emissions from FCPP. Based on a recent PSD
permit issued to the Coronado Generating Station in Arizona, the use of
an ultra-low conversion catalyst (achieving no more than 0.5%
SO2 to SO3 conversion) currently represents BACT.
In addition to the impact of SCR on H2SO4
emissions, the application of SCR reduces the energy efficiency of the
facility by increasing parasitic load from the use of additional fans
to overcome increased resistance created by SCR.
2. NGS
As described above, the use of LNB + SOFA for NOX
control results in potential increases in emissions of CO and VOC, and
increased LOI of fly ash. Additionally, the impacts associated with
SCR, i.e., H2SO4 emissions increases, the limited
efficacy of reagent injection for H2SO4 control,
and energy impacts, also apply to NGS. NGS additionally identified
another concern related to SCR resulting from the need for daily
deliveries by tanker truck of anhydrous ammonia for the SCR system.
D. Factor 3: Existing Controls at the Facility
1. FCPP
Existing controls at FCPP are shown in Table 37.
Table 37--Existing Air Pollution Controls at FCPP
----------------------------------------------------------------------------------------------------------------
NOX control PM control SO2 control
----------------------------------------------------------------------------------------------------------------
Unit 1......................... none.............. Venturi Scrubber (VS). VS.
Unit 2......................... LNB............... VS--Lime.............. VS--Lime.
Unit 3......................... LNB............... VS--Lime.............. VS--Lime.
Unit 4......................... LNB............... Reverse Gas Fabric Tray Tower Flue Gas Desulfurization
Filter (Baghouse). (FGD).
Unit 5......................... LNB............... Baghouse.............. Tray Tower FGD.
----------------------------------------------------------------------------------------------------------------
a. Existing NOX Controls at FCCP
For the SCR control case, EPA conducted visibility modeling for
FCPP (Table 21, Scenario E2) without the addition of LNB + OFA, whereas
APS modeled an SCR control case assuming LNB + OFA could provide
further control of NOX emissions (Scenario E1). FCPP emits
more NOX than any other coal-fired power plant in the U.S.
This is due to both the size of the facility and the high average
concentration of NOX emitted from each unit. Every unit at
FCPP emits NOX at a higher concentration than any other unit
in Region IX.
The potential for successfully obtaining significant reductions of
NOX using only combustion controls, such as LNB, at this
facility is limited. The fireboxes for Units 1, 2 and 3 are considered
to be too small to effectively utilize modern approaches to low
NOX combustion which require separated overfire air. Unit 2
was retrofitted with a 1990-designed LNB and, according to APS, had
considerable operational problems subsequent to this retrofit. Units 1
and 2 are identical boilers. Thus due to operational difficulties
following the Unit 2 retrofit, APS did not attempt a retrofit on Unit
1, which continues to emit NOX at a concentration of 0.8 lb/
MMBtu. Due to their small size, EPA has determined that a retrofit of
Units 1 and 2 with LNB and Unit 3 with LNB + OFA will not provide
significant NOX control.
Units 4 and 5 were originally designed and operated with cell
burners. This type of combustion burner inherently creates more
NOX than conventional wall-fired burners. Although these
burners were replaced in the 1980s, the design of a cell burner boiler
limits the NOX reduction that can be achieved with modern
low NOX combustion techniques. EPA has set different
presumptive levels for the expected achievable NOX
reductions for cell burner boilers with combustion modifications due to
this design limitation. Thus, the efficacy of LNB + OFA on Units 4 and
5 will also be limited by their inherent design. EPA is requesting
comment on the potential efficacy of LNB + OFA on all Units at FCPP.
b. Existing PM Controls at FCCP
Units 1, 2, and 3 utilize venturi scrubbers for both PM and
SO2 control. These scrubbers operate at pressure drops less
than 10 inches of water. Venturi scrubbers have not been installed for
PM pollution control on any coal fired EGU in Region IX since the early
1970s. This was principally due to concerns over the ability of venturi
scrubbers to continuously meet the 0.10 lb/MMBtu standard in a 1971
regulation. Fossil fuel fired boiler standards for coal fired units
were revised for units built after 1978 and the PM limit was lowered to
0.03 lb/MMbtu. Most current coal fired boilers now use baghouses which
are capable of meeting PM limits of about 0.01 to 0.012 lb/MMBtu
(Method 5 front half PM measurement).
In Region IX, all other coal fired EGUs controlled by venturi
scrubbers have been retrofit with new PM controls. Unit 1 at APS's
Cholla power plant was retrofit with a baghouse in 2007, in order to
meet a new 20% opacity standard established by the ADEQ. APS received
an extended compliance schedule for meeting that opacity standard to
allow for the installation of the new baghouse. Three units at the
Nevada Energy Reid Gardner facility also have venturi scrubbers for PM
control. These units are required by a consent decree between Nevada
Energy, and Nevada Department of Environmental Protection and EPA, to
install new baghouses in 2010. EPA is requesting comment on whether the
existing controls on Units 1-3 at FCPP meet BART for PM.
2. NGS
Existing controls at NGS are shown in Table 38.
[[Page 44334]]
Table 38--Existing Air Pollution Controls at NGS
----------------------------------------------------------------------------------------------------------------
NOX control PM control SO2 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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
EPA is requesting comment on the use of this period of time for the
remaining useful life of FCPP.
2. NGS
In its analysis, SRP used an amortization period of 20 years,
anticipating that the remaining useful life of Units 1-3 is at least 20
years.
EPA is also requesting comment on the use of this period of time
for the remaining useful life of NGS.
III. Statutory and Executive Order Reviews
Under Executive Order 12866, entitled Regulatory Planning and
Review (58 FR 51735, October 4, 1993), this is not a ``significant
regulatory action.'' Because this action does not propose or impose any
requirements, the various statutes and Executive Orders that apply to
rulemaking do not apply in this case. In addition, this notice covers
two facilities. Any future rulemaking would be separate, one for each
facility. Determinations of significance and applicability of any
Executive Order or statute would depend upon the content of each
individual rulemaking. Should EPA subsequently determine to pursue
rulemaking and propose BART for these facilities, EPA will address the
statutes and Executive Orders as applicable to those individual
proposed actions.
Nevertheless, the Agency welcomes comments and/or information that
would help the Agency to assess any of the following: tribal
implications pursuant to Executive Order 13175, entitled Consultation
and Coordination with Indian Tribal Governments (65 FR 67249, November
6, 2000); environmental health or safety effects on children pursuant
to Executive Order 13045, entitled Protection of Children from
Environmental Health Risks and Safety Risks (62 FR 19885, April 23,
1997); energy effects pursuant to Executive Order 13211, entitled
Actions Concerning Regulations that Significantly Affect Energy Supply,
Distribution, or Use (66 FR 28355, May 22, 2001); Paperwork burdens
pursuant to the Paperwork Reduction Act (PRA) (44 U.S.C. 3501); or
human health or environmental effects on minority or low-income
populations pursuant to Executive Order 12898, entitled Federal Actions
to Address Environmental Justice in Minority Populations and Low-Income
Populations (59 FR 7629, February 16, 1994). The Agency will consider
such comments during the development of any subsequent rulemaking.
List of Subjects in 40 CFR Part 52
Environmental protection, Air pollution control, Oxides of
nitrogen, Particulate matter, Regional haze.
Authority: 42 U.S.C. 7401 et seq.
Dated: August 19, 2009.
Laura Yoshii,
Acting Regional Administrator, Region IX.
[FR Doc. E9-20826 Filed 8-27-09; 8:45 am]
BILLING CODE 6560-50-P