[Federal Register Volume 75, Number 201 (Tuesday, October 19, 2010)]
[Proposed Rules]
[Pages 64221-64235]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2010-26262]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 49

[EPA-R09-OAR-2010-0683; FRL-9213-7]


Source Specific Federal Implementation Plan for Implementing Best 
Available Retrofit Technology for Four Corners Power Plant: Navajo 
Nation

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: The Environmental Protection Agency (EPA) is proposing to 
promulgate a source specific Federal Implementation Plan (FIP) 
requiring the Four Corners Power Plant (FCPP), located on the Navajo 
Nation, to achieve emissions reductions required by the Clean Air Act's 
Best Available Retrofit Technology (BART) provision. In this action, 
EPA is proposing to require FCPP to reduce emissions of oxides of 
nitrogen (NO<INF>X</INF>) and particulate matter (PM). These pollutants 
are significant contributors to visibility impairment in the numerous 
mandatory Class I Federal areas surrounding FCPP. For NO<INF>X</INF> 
emissions, EPA is proposing to require FCPP to meet an emission limit 
of 0.11 lb/MMBtu, representing an 80% reduction from current 
NO<INF>X</INF> emissions. This NO<INF>X</INF> limit is achievable by 
installing and operating Selective Catalytic Reduction (SCR) technology 
on Units 1-5. For PM, EPA is proposing to require FCPP to meet an 
emission limit of 0.012 lb/MMBtu for Units 1-3 and 0.015 lb/MMBtu for 
Units 4 and 5. These emissions limits are achievable by installing and 
operating any of several equivalent controls on Units 1-3, and through 
proper operation of the existing baghouse on Units 4 and 5. EPA is 
proposing to require FCPP to meet a 10% opacity limit on Units 1-5 to 
ensure proper operation of the PM controls. EPA is requesting comment 
on whether APS can satisfy BART on Units 1-3 by operating the existing 
venturi scrubbers to meet an emission limit of 0.03 lb/MMBtu with a 20% 
opacity limit. EPA is also proposing to require FCPP to comply with a 
20% opacity limit on its coal and material handling operations.

DATES: Comments must be submitted no later than December 20, 2010.

ADDRESSES: Submit comments, identified by docket number EPA-R09-OAR-
2010-0683, by one of the following methods:
    Federal eRulemaking Portal: http://www.regulations.gov. Follow the 
on-line instructions.
    E-mail: <a href="/cdn-cgi/l/email-protection#4c3e752d253e132a2f3c3c2e2d3e380c293c2d622b233a"><span class="__cf_email__" data-cfemail="f486cd959d86ab9297848496958680b4918495da939b82">[email protected]</span></a>.
    Mail or deliver: Anita Lee (Air-3), U.S. Environmental Protection 
Agency Region IX, 75 Hawthorne Street, San Francisco, CA 94105-3901.
    Instructions: All comments will be included in the public docket 
without change and may be made available online at http://www.regulations.gov, including any personal information provided, 
unless the comment includes Confidential Business Information (CBI) or 
other information whose disclosure is restricted by statute. 
Information that you consider CBI or otherwise protected should be 
clearly identified as such and should not be submitted through http://www.regulations.gov or e-mail. http://www.regulations.gov is an 
``anonymous access'' system, and EPA will not know your identity or 
contact information unless you provide it in the body of your comment. 
If you send 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.
    Hearings: EPA intends to hold public hearings in two locations in 
New Mexico to accept oral and written comments on the proposed 
rulemaking. EPA anticipates these hearings will occur in Shiprock and 
Farmington. EPA will provide notice and additional details at least 30 
days prior to the hearings in the Federal Register, on our Web site, 
and in the docket.
    Docket: The index to the docket for this action is available 
electronically at http://www.regulations.gov and in hard copy at EPA 
Region IX, 75 Hawthorne Street, San Francisco, California. While all 
documents in the docket are listed in the index, some information may 
be publicly available only at the hard copy location (e.g., copyrighted 
material), and some may not be publicly available in either location 
(e.g., CBI). To inspect the hard copy materials, please schedule an 
appointment during normal business hours with the contact listed in the 
FOR FURTHER INFORMATION CONTACT section.

FOR FURTHER INFORMATION CONTACT: Anita Lee, EPA Region IX, (415) 972-
3958, <a href="/cdn-cgi/l/email-protection#4a38732b2338152c293a3a282b383e0a2f3a2b642d253c"><span class="__cf_email__" data-cfemail="36440f575f446950554646545744427653465718515940">[email protected]</span></a>.

SUPPLEMENTARY INFORMATION: Throughout this document, ``we'', ``us'', 
and ``our'' refer to EPA.

Table of Contents

I. Background
    A. Statutory and Regulatory Framework for Addressing Visibility
    B. Statutory and Regulatory Framework for Addressing Sources 
Located in Indian Country
    C. Statutory and Regulatory Framework for BART Determinations
    D. Factual Background
    1. Four Corners Power Plant
    2. Relationship of NO<INF>X</INF> and PM to Visibility 
Impairment
II. EPA's Proposed Action Based on Five Factors Test
    A. A BART Determination for FCPP Is Necessary or Appropriate
    B. Summary of Proposed BART Emission Limits
    C. Available and Feasible Control Technologies and Five Factor 
Analysis for NO<INF>X</INF> Emissions
    i. Factor 1: Cost of Compliance
    ii. Factor 2: Energy and Non-Air Quality Impacts
    iii. Factor 3: Existing Controls at the Facility
    iv. Factor 4: Remaining Useful Life of Facility
    v. Factor 5: Degree of Visibility Improvement
    D. Available and Feasible Control Technologies and Five Factor 
Analysis for PM Emissions
    i. Factor 1: Cost of Compliance
    ii. Factor 2: Energy and Non-Air Quality Impacts
    iii. Factor 3: Existing Controls at the Facility
    iv. Factor 4: Remaining Useful Life of Facility
    v. Factor 5: Degree of Visibility Improvement
III. EPA's Proposed Action on Material Handling Limits
IV. Administrative Requirements
    A. Executive Order 12866: Regulatory Planning and Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

[[Page 64222]]

    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations

I. Background

A. Statutory and Regulatory Framework for Addressing Visibility

    Part C, Subpart II, of the Act, establishes a visibility protection 
program that sets forth ``as a national goal the prevention of any 
future, and the remedying of any existing, impairment of visibility in 
mandatory class I Federal areas which impairment results from manmade 
air pollution.'' 42 U.S.C. 7491A(a)(1). The terms ``impairment of 
visibility'' and ``visibility impairment'' are defined in the Act to 
include a reduction in visual range and atmospheric discoloration. Id. 
7491A(g)(6). A fundamental requirement of the visibility protection 
program is for EPA, in consultation with the Secretary of the Interior, 
to promulgate a list of ``mandatory Class I Federal areas'' where 
visibility is an important value. Id. 7491A(a)(2). These areas include 
national wilderness areas and national parks greater than six thousand 
acres in size. Id. 7472(a).
    On November 30, 1979, EPA identified 156 mandatory Class I Federal 
areas where visibility is an important value, including for example: 
Grand Canyon National Park in Arizona (40 CFR 81.403); Mesa Verde 
National Park and La Garita Wilderness Area in Colorado (Id. 81.406); 
Bandelier Wilderness Area in New Mexico (Id. 81.421); and Arches, Bryce 
Canyon, Canyonlands and Capitol Reef National Parks in Utah (Id. 
81.430). These mandatory Class I Federal areas are within an 
approximately 300 km (or 186 mile) radius of FCPP.
    On December 2, 1980, EPA promulgated the first phase of the 
required visibility regulations, codified at 40 CFR 51.300-307. 45 FR 
80084. The 1980 regulations deferred regulating regional haze from 
multiple sources finding that the scientific data were inadequate at 
that time. Id. at 80086.
    Congress added Section 169B to the Act in the 1990 CAA Amendments, 
requiring EPA to take further action to reduce visibility impairment in 
broad geographic regions. 42 U.S.C. 7492. In 1993, the National Academy 
of Sciences released a comprehensive study required by the 1990 
Amendments concluding that ``current scientific knowledge is adequate 
and control technologies are available for taking regulatory action to 
improve and protect visibility.'' Protecting Visibility in National 
Parks and Wilderness Areas, Committee on Haze in National Parks and 
Wilderness Areas, National Research Council, National Academy Press 
(1993).
    EPA promulgated regulations to address regional haze on April 22, 
1999. 64 FR 35765. Consistent with the statutory requirement in 42 
U.S.C. 7491(b)(2)(a), EPA's 1999 regional haze regulations include a 
provision requiring States to require certain major stationary sources 
``in existence on August 7, 1977, but which ha[ve] not been in 
operation for more than fifteen years as of such date'' which emit 
pollutants that are reasonably anticipated to cause or contribute to 
any visibility impairment to procure, install and operate BART. In 
determining BART, States are required to take into account five factors 
identified in the CAA and EPA's regulations. 42 U.S.C. 7491(g)(2) and 
40 CFR 51.308.

B. Statutory and Regulatory Framework for Addressing Sources Located in 
Indian Country

    When the Clean Air Act was amended in 1990, Congress included a new 
provision, Section 301(d), granting EPA authority to treat Tribes in 
the same manner as States where appropriate. See 40 U.S.C. 7601(d). 
Congress also recognized, however, that such treatment may not be 
appropriate for all purposes of the Act and that in some circumstances, 
it may be inappropriate to treat tribes identically to states. 
Therefore, Section 301(d)(2) of the Act directed EPA to promulgate 
regulations ``specifying those provisions of [the CAA] for which it is 
appropriate to treat Indian tribes as States.'' Id. 7601(d)(2). In 
addition, Congress provided that ``[i]n any case in which [EPA] 
determines that the treatment of Indian tribes as identical to States 
is inappropriate or administratively infeasible, the Administrator may 
provide, by regulation, other means by which the Administrator will 
directly administer such provisions so as to achieve the appropriate 
purpose.'' Id. 7601(d)(4).
    In 1998, EPA promulgated regulations at 40 CFR part 49 (which have 
been referred to as the Tribal Authority Rule or TAR) relating to 
implementation of CAA programs in Indian Country. See 40 CFR part 49; 
see also 59 FR 43956 (Aug. 25, 1994) (proposed rule); 63 FR 7254 (Feb. 
12, 1998) (final rule); Arizona Public Service Company v. EPA, 211 F.3d 
1280 (DC Cir. 2000), cert. den., 532 U.S. 970 (2001) (upholding the 
TAR). The TAR allows EPA to treat eligible Indian Tribes in the same 
manner as States ``with respect to all provisions of the [CAA] and 
implementing regulations, except for those provisions [listed] in 49.4 
and the [EPA] regulations that implement those provisions.'' 40 CFR 
49.3. EPA recognized that Tribes were in the early stages of developing 
air planning programs known as Tribal Implementation Plans (TIPs) and 
that Tribes would need additional time to develop air quality programs. 
62 FR 7264-65. Thus, EPA determined that it was not appropriate to 
treat Tribes in the same manner as States for purposes of those 
provisions of the CAA imposing air program submittal deadlines. See 59 
FR at 43964-65; 63 FR at 7264-65. Similarly, EPA determined that it 
would be inappropriate to treat Tribes the same as States for purposes 
of the related CAA provisions establishing sanctions and federal 
oversight mechanisms where States fail to meet applicable air program 
submittal deadlines. Id. Thus, one of the CAA provisions that EPA 
determined was not appropriate to apply to Tribes is Section 110(c)(1). 
See 40 CFR 49.4(d). In particular, EPA found that it was inappropriate 
to impose on Tribes the provisions in Section 110(c)(1) for EPA to 
promulgate a FIP within 2 years after a State fails to make a required 
plan submission.
    Although EPA determined that the requirements of CAA section 
110(c)(1) were not applicable to Tribes, EPA also determined that under 
other provisions of the CAA it has the discretionary authority to 
promulgate ``such federal implementation plan provisions as are 
necessary or appropriate to protect air quality'' when a Tribe has not 
submitted a TIP. 40 CFR 49.11. EPA determined in promulgating the TAR 
that it could exercise discretionary authority to promulgate FIPs based 
on Section 301(a) of the CAA, which authorizes EPA to prescribe such 
regulations as are necessary to carry out the Act, and Section 
301(d)(4), which authorizes EPA to directly administer CAA provisions 
for which EPA has determined it is inappropriate or infeasible to treat 
Tribes as identical to States. 40 CFR 49.11. See also 63 FR at 7265. 
Specifically, 40 CFR 49.11(a) provides that EPA shall promulgate 
without unreasonable delay such Federal implementation plan provisions 
as are necessary or appropriate to protect air quality, consistent with 
the provisions of sections 301(a) and 301(d)(4), if a tribe does not 
submit a tribal implementation plan or does not receive EPA approval of 
a submitted tribal implementation plan.
    EPA has previously promulgated FIPs under the TAR to regulate air 
pollutants emitted from the two coal fired electric generating 
facilities on the Navajo

[[Page 64223]]

Nation, FCPP and Navajo Generating Station (NGS). In 1991, EPA also 
revised an existing FIP that applied to Arizona to include a 
requirement for NGS to substantially reduce its SO<INF>2</INF> 
emissions by installing scrubbers based on finding that the 
SO<INF>2</INF> emissions were contributing to visibility impairment at 
the Grand Canyon National Park. 56 FR 50172 (Oct. 3, 1991); see also 
Central Arizona Water Conservation District v. United States 
Environmental Protection Agency, 990 F.2d 1531 (9th Cir. 1993).
    In 1999, after several years of negotiations, EPA proposed 
concurrent but separate FIPs for FCPP and NGS. Those FIPs proposed to 
fill the regulatory gap that existed because permits and SIP rules by 
New Mexico (for FCPP) and Arizona (for NGS) were not applicable or 
enforceable on the Navajo Nation, and the Tribe had not sought approval 
of a TIP covering the plants. 64 FR 48731 (Sept. 8, 1999).
    Before EPA finalized the 1999 FIPs, the operator of FCPP began 
negotiations to reduce SO<INF>2</INF> emissions from FCPP by making 
upgrades to improve the efficiency of its SO<INF>2</INF> scrubbers. The 
negotiations resulted in an agreement for FCPP to increase the 
SO<INF>2</INF> control from a 72% reduction of the potential 
SO<INF>2</INF> emissions to an 88% reduction. As a result of this 
increased scrubber efficiency, FCPP's SO<INF>2</INF> emissions 
decreased by a total of 57% from the historical levels. The parties to 
the negotiations requested EPA to make those SO<INF>2</INF> reductions 
enforceable through a source specific FIP. Therefore, EPA proposed new 
FIPs for FCPP and NGS in September 2006. 71 FR 53631 (Sept. 12, 2006). 
In these concurrent but separate FIPs, EPA proposed to make emissions 
limits contained in State permits or rules that had previously been 
followed by FCPP and NGS federally enforceable. In addition, for FCPP, 
EPA proposed to establish a significantly lower SO<INF>2</INF> 
emissions limit based on the increased scrubber efficiency, resulting 
in a reduction of approximately 22,000 tons of SO<INF>2</INF> per year. 
EPA indicated in the final FIP for FCPP that the new SO<INF>2</INF> 
emissions limits were close to or the equivalent of the emissions 
reductions that would have been required in a BART determination. 72 FR 
25698 (May 7, 2007). The FIP also required FCPP to comply with a 20% 
opacity limit on both the combustion and fugitive dust emissions coal 
handling operations. EPA finalized the FIP for FCPP in May 2007. Id.
    APS, the operator of FCPP, and the Sierra Club each filed Petitions 
seeking judicial review of EPA's promulgation of the 2007 FIP for FCPP, 
on separate grounds. APS argued that EPA did not have authority to 
promulgate a source-specific FIP for FCPP without its consent. APS also 
argued that EPA did not have authority to promulgate a 20% opacity 
standard on the combustion equipment unless we provided an exemption 
for malfunctions. Finally, APS argued that EPA had not established an 
adequate basis for requiring a 20% opacity limit on the fugitive dust 
from the coal handling operations. In contrast, Sierra Club argued that 
EPA could not promulgate a ``gap filling'' FIP that did not include 
modeling and an analysis to show continued attainment of the NAAQS.
    The Court of Appeals for the Tenth Circuit rejected both Petitions. 
With respect to the Sierra Club's arguments, the Court considered the 
regulatory language in 40 CFR 49.11(a) and concluded that ``[t]his 
language does not impose upon the EPA the duty the Environmentalists 
propose. It provides the EPA discretion to determine what rulemaking is 
necessary or appropriate to protect air quality and requires the EPA to 
promulgate such rulemaking.'' Arizona Public Service v. EPA, 562 F.3d 
1116, 1125 (10th Cir. 2009). The Court also rejected arguments by APS 
that EPA could not impose a continuous opacity limitation during 
operations, provided EPA set forth a reasonable basis for its decision. 
Id. at 1129 (``That APS does not agree with the EPA's rejection of the 
substance of its proposed 0.2% allowance is irrelevant; as long as 
EPA's decision making process may reasonably be discerned, we will not 
set aside the federal plan on account of a less-than-ideal 
explanation.'' [citation omitted]). The Court agreed with EPA's request 
for a voluntary remand of the opacity limit for the fugitive dust for 
the material handling operations and remanded that narrow aspect of the 
2007 FIP. Id. at 1131.
    The FIP that EPA is proposing today is promulgated under the same 
authority in 40 CFR 49.11(a). EPA is proposing to find that it is 
necessary or appropriate to establish BART requirements for 
NO<INF>X</INF> and PM emissions from FCPP, and is proposing specific 
NO<INF>X</INF> and PM limits as BART. EPA is proposing to establish a 
10% opacity limit from Units 1-5 to ensure continuous compliance with 
the PM emissions limit. EPA is also proposing a 20% opacity limit to 
apply to FCPP's material handling operations in response to the remand 
from the 2007 FIP.

C. Statutory and Regulatory Framework for BART Determinations

    When Congress enacted Section 169A of the CAA to protect 
visibility, it directed EPA to promulgate regulations that, inter alia, 
would require applicable implementation plans to include a 
determination of BART for certain major stationary sources. 42 U.S.C. 
7491(b)(2)(A) & (g). These major stationary sources are fossil-fuel 
fired steam electric plants of more than 250 MMBtu/hr heat input, kraft 
pulp mills, Portland cement plants and other listed industrial sources 
that came into operation between 1962 and 1977 and are ``reasonably 
anticipated to cause or contribute to any impairment of visibility in 
any [Class I area].'' Id. EPA guidelines must be followed in making 
BART determinations for fossil fuel fired electric generating plants 
larger than 750 MW. See 40 CFR Part 51, Appendix Y.
    FCPP and NGS are the only eligible BART sources located on the 
Navajo Nation. See Western Regional Air Partnership, http://www.wrapair.org/forums/ssjf/bart.html, XLS Spreadsheet, Line 184, 185, 
Column N. An eligible BART source with a predicted impact of 0.5 dv or 
more of impairment in a Class I area ``contributes'' to visibility 
impairment and is subject to BART. 70 FR 39104, 39121 (July 6, 2005). 
FCPP contributes to impairment at many surrounding Class I areas well 
in excess of this threshold.
    EPA's guidelines for evaluating BART for such sources are set forth 
in Appendix Y to 40 CFR Part 51. See also 40 CFR 51.308(e)(1)(ii)(A). 
Consistent with statutory and regulatory requirements, the Guidelines 
require consideration of ``five factors'' in making BART 
determinations. Id. at IV.A. Those factors, from the Act's statutory 
definition of BART, which are applied to all technically feasible 
control technologies, are: (1) The costs of compliance, (2) the energy 
and non-air quality environmental impacts of compliance, (3) any 
pollution control equipment in use or in existence at the source, (4) 
the remaining useful life of the source, and (5) the degree of 
improvement in visibility which may reasonably be anticipated to result 
from the use of such technology. 40 CFR 51.308(e)(1)(ii)(A).
    In this proposed action, EPA has taken into consideration each of 
the five factors after identifying feasible control technologies for 
FCPP's NO<INF>X</INF> and PM emissions.

[[Page 64224]]

D. Factual Background

1. Four Corners Power Plant
    FCPP is a privately owned and operated coal-fired power plant 
located on the Navajo Nation Indian Reservation near Farmington, New 
Mexico. Based on lease agreements signed in 1960, FCPP was constructed 
and has been operating on real property held in trust by the Federal 
government for the Navajo Nation. The facility consists of five 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 2009 emissions data from the EPA Clean Air Markets 
Division,\1\ FCPP is the largest source of NO<INF>X</INF> emissions in 
the United States (over 40,000 tons per year (tpy) of NO<INF>X</INF>). 
FCPP, located near the Four Corners region of Arizona, New Mexico, 
Utah, and Colorado, is approximately 300 kilometers (km) from sixteen 
mandatory Class I Federal areas: Arches National Park (NP), Bandelier 
National Monument (NM), Black Canyon of the Gunnison Wilderness Area 
(WA), Canyonlands NP, Capitol Reef NP, Grand Canyon NP, Great Sand 
Dunes NP, La Garita WA, Maroon Bells-Snowmass WA, Mesa Verde NP, Pecos 
WA, Petrified Forest NP, San Pedro Parks WA, West Elk WA, Weminuche WA, 
and Wheeler Park WA.
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    \1\ ``Clean Air Markets--Data and Maps: http://camddataandmaps.epa.gov/gdm/.
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    APS provided information relevant to a BART analysis to EPA on 
January 29, 2008. The information consisted of a BART engineering and 
cost analysis conducted by Black and Veatch (B&V) dated December 4, 
2007 (Revision 3), a BART visibility modeling protocol prepared by ENSR 
Corporation (now called AECOM and referred to as AECOM throughout this 
document) dated January 2008, a BART visibility modeling report 
prepared by AECOM dated January 2008, and a document titled APS BART 
Analysis conclusions, dated January 29, 2008. APS provided supplemental 
information on cost and visibility modeling in correspondence dated May 
28, 2008, June 10, 2008, November 2008, March 16, 2009, October 29, 
2009, and April 22, 2010. All of these documents are available in the 
docket for this proposal.
2. Relationship of NO<INF>X</INF> and PM to Visibility Impairment
    Particulate matter less than 10 microns (millionths of a meter) in 
size (PM<INF>10</INF>) interacts with light. The smallest particles in 
the 0.1 to 1 micron range interact most strongly as they are about the 
same size as the wavelengths of visible light. The effect of the 
interaction is to scatter light from its original path. Conversely, for 
a given line of sight, such as between a mountain scene and an 
observer, light from many different original paths is scattered into 
that line. The scattered light appears as whitish haze in the line of 
sight, obscuring the view.
    PM emitted directly into the atmosphere, also called primary PM, is 
emitted both from the boiler stacks and from material handling. Of 
primary PM emissions, those in the smaller particle size range, less 
than 2.5 microns, tend to have the most impact on visibility. PM 
emissions from the boiler stacks can have varying particle size makeup 
depending on the PM control technology. PM from material handling, 
though, tends to be coarse, i.e. around 10 microns, since it is created 
from the breakup of larger particles of soil and rock.
    PM that is formed in the atmosphere from the condensation of 
gaseous chemical pollutants, also called secondary PM, tends to be 
fine, i.e. smaller than 1 micron, since it is formed from the buildup 
of individual molecules. This secondary PM tends to contribute more to 
visibility impairment than primary PM because it is in the size range 
where it most effectively interacts with visible light. NO<INF>X</INF> 
and SO<INF>2</INF> emissions from coal fired power plants are two 
examples of gaseous chemical pollutants that react with other compounds 
in the atmosphere to form secondary PM. Specifically, NO<INF>X</INF> is 
a gaseous pollutant that can be oxidized to form nitric acid. In the 
atmosphere, nitric acid in the presence of ammonia forms particulate 
ammonium nitrate. The formation of particulate ammonium nitrate is 
dependent on temperature and relative humidity, and therefore, varies 
by season. Particulate ammonium nitrate can grow into the size range 
that effectively interacts with light by coagulating together and by 
taking on additional pollutants and water. The same principle applies 
to SO<INF>2</INF> and the formation of particulate ammonium sulfate.
    In air quality models, secondary PM is tracked separately from 
primary PM because the amount of secondary PM formed depends on weather 
conditions and because it can be six times more effective at impairing 
visibility. This is reflected in the equation used to calculate 
visibility impacts from concentrations measured by the Interagency 
Monitoring of Protected Visual Environments (IMPROVE) monitoring 
network covering Class I areas.\2\
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    \2\ Guidance for Estimating Natural Visibility Conditions Under 
the Regional Haze Rule, U.S. Environmental Protection Agency'', EPA-
454/B-03-005, September 2003; http://www.epa.gov/ttn/oarpg/t1pgm.html.
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II. EPA's Proposed Action on the Five Factor Test

A. A BART Determination for FCPP Is Necessary or Appropriate

    The numerous Class I areas that surround FCPP are sometimes known 
as the Golden Circle of National Parks. See http://www.nps.gov/history/history/online_books/nava/adhi/adhi4e.htm. Millions of tourists visit 
these areas, many visiting from other countries to view the unique 
vistas of the Class I areas in the Four Corners region.
    As Congress recognized, visibility is an important value and must 
be protected in these areas. Yet, air quality and visibility are 
impaired in the 16 Class I areas surrounding FCPP. The National Park 
Service noted in 2008 that ``[v]isibility is impaired to some degree at 
all units where it is being measured and remains considerably higher 
than the target national conditions in many places, particularly on the 
haziest days.'' Air Quality in National Parks, 2008 Annual Performance 
& Progress Report, National Resource Report NPS/NRPC/ARD/NRR-2009/151, 
September 2009, p. 30. Mesa Verde, Grand Canyon, Bryce Canyon and 
Canyonlands are among the areas the Park Service is monitoring. Id. 
Table 3, p. 19. Although not directly related to visibility, 
NO<INF>X</INF> is also a precursor to ozone formation and the National 
Park Service also determined that ozone concentrations in Mesa Verde 
appears to be trending upward over the 1994-2007 period and the Park's 
annual 4th-highest 8-hour ozone concentrations ``are approaching the 
[NAAQS] standard.'' Id. at 16. FCPP, which emitted over 42,000 tons of 
NO<INF>X</INF> in 2009,\3\ was built roughly four decades ago and has 
not installed any new NO<INF>X</INF> controls since the 1990's, 
including modern combustion technology such as post-2000 low-
NO<INF>X</INF> burners (LNB) or separated overfire air.
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    \3\ Clean Air Markets Division--Data--Maps.
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    Based on the importance of visibility as a value in this Golden 
Circle of

[[Page 64225]]

National Parks, and the substantial NO<INF>X</INF> and PM emissions 
generated by operating FCPP, EPA is proposing to find that BART 
emission limits are necessary or appropriate.

B. Summary of Proposed BART Emissions Limits

    On August 28, 2009, EPA published an Advanced Notice of Proposed 
Rulemaking (ANPRM) concerning two of the five factors in the BART 
analysis: Cost of compliance and anticipated visibility improvement. 74 
FR 44314. EPA received numerous comments on the ANPRM, including 
comments from the Navajo Nation, APS, National Park Service and 
environmental groups. EPA has considered relevant comments we received 
on the ANPRM in determining which NO<INF>X</INF> and PM emission 
limitations we are proposing today as BART for FCPP.
    Based on the available control technologies and the five factors 
discussed in more detail below, EPA is proposing to require FCPP to 
meet a NO<INF>X</INF> emission limit on Units 1-5 of 0.11 lb/MMBtu. EPA 
is proposing a PM emission limit on Units 1-3 of 0.012 lb/MMBtu and on 
Units 4 and 5 of 0.015 lb/MMBtu as BART. EPA is taking comment on an 
alternative PM emissions limit for Units 1-3 described in more detail 
in Section II.D.
    EPA is not proposing to require each unit to achieve the specified 
NO<INF>X</INF> emission limit. EPA is proposing to require FCPP to meet 
a plant-wide heat input weighted 30-day rolling average emission limit 
of 0.11 lb/MMBtu for NO<INF>X</INF> for Units 1-5. For PM, we are 
proposing a BART emission limit of 0.012 lb/MMBtu from Units 1-3 on a 
6-hour average basis and 0.015 lb/MMBtu averaged over a 6-hour period 
for Units 4 and 5, which should be achievable with proper operation of 
the existing baghouses. EPA is also proposing that Units 1-5 meet a 10% 
opacity limit which will reasonably assure continuous compliance with 
the PM emission limits. EPA is taking comment on an alternative PM 
emission limit for Units 1-3.
    The available control technologies and EPA's evaluation of each of 
the five factors supporting our proposed BART emissions limits for 
NO<INF>X</INF> and PM are discussed in more detail below and in EPA's 
accompanying Technical Support Document (TSD).

C. Available and Feasible Control Technologies and Five Factor Analysis 
for NO<INF>X</INF> Emissions

    APS identified sixteen options as available retrofit technologies 
to control NO<INF>X</INF>. Generally, NO<INF>X</INF> control techniques 
use: (1) Combustion control to reduce the production of NO<INF>X</INF> 
from fuel-bound nitrogen and high temperature combustion; (2) post-
combustion add-on control to reduce the amount of NO<INF>X</INF> 
emitted in flue gas by converting NO<INF>X</INF> to diatomic nitrogen 
(N<INF>2</INF>); or (3) a combination of combustion and post-combustion 
controls. EPA approached the five factor analysis using a top-down 
method. A top-down analysis entails ranking the control options in 
descending order starting with the most stringent option. The top 
control option is evaluated and if eliminated based on one of the five 
factors, the next most stringent option is considered, and so on. The 
top option for NO<INF>X</INF> control is a combination of a post-
combustion add-on control, i.e., selective catalytic reduction (SCR), 
and combustion controls, i.e., low-NO<INF>X</INF> burners plus overfire 
air (LNB + OFA). SCR without LNB + OFA represents the next most 
stringent option, and LNB + OFA without SCR represents a low-mid level 
of control. As described in detail below, EPA believes LNB + OFA are 
not likely to be effective control technologies at FCPP due to the 
inherent limitations of the existing boilers on all units. Therefore, 
EPA started our top-down analysis of the five factors with SCR without 
combustion controls. More details on the control options are provided 
in Section 2 of the TSD.
    As described in our ANPRM, APS has claimed that combustion controls 
(i.e., low-NO<INF>X</INF> burners (LNB) on Units 1 and 2 and low 
NO<INF>X</INF> burners plus overfire air (LNB + OFA) on Units 3-5) 
would provide NO<INF>X</INF> reductions sufficient to meet the 
presumptive limits for NO<INF>X</INF> identified in the BART Guidelines 
(40 CFR Part 51 Appendix Y). Table 1 shows the presumptive 
NO<INF>X</INF> limits for boilers burning either sub-bituminous or 
bituminous coal and the emission limits APS considers achievable for 
Units 1-5. APS submitted NO<INF>X</INF> emission limits it considers 
achievable to EPA in January 2008, March 2009, and October 2009. The 
coal burned at FCPP has historically been classified as sub-bituminous. 
APS, however, in its BART analysis has claimed that the coal is 
bituminous.

 Table 1--Presumptive NOX Limits4 and NOX Emissions (in lb/MMBtu) From LNB (Units 1 and 2) LNB + OFA (Units 3-5)
                                            Claimed Achievable by APS
----------------------------------------------------------------------------------------------------------------
                                                                               Emissions after   Emissions after
                                           Bituminous coal   Sub-Bituminous    LNB or LNB+OFA    LNB or LNB+OFA
                                                                  coal         (Jan 2008 \5\)    (Oct 2009 \6\)
----------------------------------------------------------------------------------------------------------------
Unit 1..................................               N/A               N/A              0.48              0.40
Unit 2..................................               N/A               N/A              0.48              0.40
Unit 3..................................              0.39              0.23              0.39              0.32
Unit 4..................................              0.40              0.45              0.40              0.35
Unit 5..................................              0.40              0.45              0.40              0.35
----------------------------------------------------------------------------------------------------------------

    EPA, however, disagrees with APS's contention that EPA should rely 
only on presumptive limits for BART for NO<INF>X</INF> and with APS's 
claim that LNB and LNB + OFA will be effective at achieving 
NO<INF>X</INF> emissions lower than the presumptive BART emissions 
limits.
---------------------------------------------------------------------------

    \4\ Presumptive limits for Unit 3 based on dry-bottom wall-fired 
boiler and Units 4 and 5 on cell burner boilers. Presumptive limits 
do not apply to Units 1 and 2 because they are smaller than 200 MW.
    \5\ From 2008-01--APS--4--Corners--BART--Analysis--
Conclusions.pdf.
    \6\ From APS's Comment Letter to EPA dated October 28, 2009.

---------------------------------------------------------------------------

[[Page 64226]]

    EPA's presumptive BART limits were not intended to supplant a case-
by-case BART determination. For NO<INF>X</INF>, for most types of 
boilers, EPA's presumptive BART limits were intended to indicate what 
should generally be achievable with combustion modifications such as 
modern LNB with OFA for a given type of boiler firing either bituminous 
or sub-bituminous coal. In establishing the presumptions, EPA concluded 
that these controls were highly cost-effective at large power plants 
generally and that installation of such controls would result in 
meaningful visibility improvement at any 750 MW power plant. Thus, 
these controls are required at a minimum at these facilities unless 
there are source-specific circumstances that would justify a different 
conclusion. EPA did not consider the question of what more stringent 
control technologies might be appropriately determined to be BART, 
however, especially in the case where the visibility benefits may be 
substantial. A full case-by-case BART analysis is required for each 
facility. In this instance, given the fact that FCPP is the largest 
source of NO<INF>X</INF> emissions in the United States and that it is 
surrounded by 16 mandatory Class I areas, EPA considers it appropriate 
to carefully consider NO<INF>X</INF> emission limits based on a full 
analysis of the five BART factors. In this rulemaking, EPA is 
undertaking a complete BART analysis for the FCPP for the first time, 
an analysis that is specific to FCPP and that takes into consideration 
the five factors set forth in the CAA.
    Because EPA is relying on the five-factor analysis and not the 
presumptive NO<INF>X</INF> levels in the BART guidelines, it is not 
necessary for EPA to make a determination on the classification of coal 
used by APS as bituminous or sub-bituminous. EPA is taking the coal 
characteristics into account in establishing the NO<INF>X</INF> BART 
emission limit, but the classification as bituminous or sub-bituminous 
is only relevant for choosing presumptive limits, which we are not 
doing in this proposal. Although the emissions level claimed by APS for 
LNB + OFA retrofit of Units 4 and 5 are below the presumptive limits 
for both sub-bituminous coal and bituminous coal, we note that the 
presumptive levels of 0.40 and 0.45 lb/MMBtu provide little reduction 
of baseline NO<INF>X</INF> emissions (0.49 lb/MMBtu) from these units.
    In our ANPRM, EPA questioned the ability of LNB and LNB + OFA to 
result in the magnitude of NO<INF>X</INF> reductions being claimed as 
achievable by APS. APS has submitted two different reports concerning 
the potential for NO<INF>X</INF> reductions at FCPP. The first report 
written by Andover Technology Partners \7\ (Andover Report) was 
submitted by APS by letter dated August 7, 2009, prior to the 
publication of the ANPRM.\8\ The Andover Report outlined the 
considerable challenges associated with LNB and OFA retrofits on each 
unit, including boiler design and size, and FCPP coal characteristics. 
Although four different technology suppliers claimed they could achieve 
NO<INF>X</INF> reductions with burner retrofits, the Andover Report 
concluded that LNB retrofits were not likely to be beneficial for the 
boilers at FCPP because the risk of adverse operational side effects 
outweighed the potentially modest improvement in emissions performance.
---------------------------------------------------------------------------

    \7\ ``Assessment of Potential for Further NO<INF>X</INF> 
Reduction by Combustion-Based Control at the Four Corners Steam 
Electric Station'', April 5, 2004.
    \8\ EPA received the Andover Report only a few days prior to 
signature of the ANPRM. Therefore the report was not considered in 
the ANPRM or made available in the ANPRM docket. APS claimed the 
report Confidential Business Information (CBI) and on July 9, 2010, 
EPA's Regional Counsel determined this report was not CBI.
---------------------------------------------------------------------------

    The fireboxes for Units 1, 2 and 3 are considered to be too small 
to effectively use modern approaches to low NO<INF>X</INF> combustion, 
which require separated OFA. Unit 2 was retrofitted with a 1990-
designed LNB and, according to APS, had considerable operational 
problems subsequent to this retrofit. Units 1 and 2 are identical 
boilers. Thus due to operational difficulties following the Unit 2 
retrofit, APS did not attempt a retrofit on Unit 1, which continues to 
emit NO<INF>X</INF> at a concentration as high as 0.8 lb/MMBtu.
    Units 4 and 5 were originally designed and operated with cell 
burners. This type of combustion burner inherently creates more 
NO<INF>X</INF> than conventional wall-fired burners. Although the type 
of burners in the cell boilers were replaced in the 1980s, the design 
of a cell boiler limits the NO<INF>X</INF> reduction that can be 
achieved with modern low NO<INF>X</INF> combustion techniques. EPA set 
different presumptive levels of 0.40 lb/MMBtu or 0.45 lb/MMBtu for the 
expected achievable NO<INF>X</INF> reductions for cell burner boilers 
with combustion modifications due to this design limitation. Thus, the 
efficacy of LNB + OFA on Units 4 and 5 will also be limited by their 
inherent design. Even if retrofit of Units 4 and 5 results in some 
improvement in NO<INF>X</INF> performance (approaching 0.40 lb/MMBtu), 
the Andover Report did not recommend burner retrofits because potential 
operational problems on the two largest units at FCPP were not worth 
the small incremental reduction in NO<INF>X</INF> emissions.
    A subsequent report prepared by APS and submitted to EPA as 
Attachment J of its October 28, 2009 comment letter on the ANPRM, 
indicated that Units 1 and 2 could achieve 0.40 lb/MMBtu with LNB 
retrofit, Unit 3 could achieve 0.32 lb/MMBtu and Units 4 and 5 could 
achieve 0.35 lb/MMBtu with a combination of LNB + OFA retrofit. See 
Table 1 above. APS cited examples of several boilers with LNB or LNB + 
OFA retrofits that achieve emission rates of 0.4 lb/MMBtu or below.
    EPA Clean Air Markets Division (CAMD) evaluated the boiler examples 
from Attachment J to assess the emissions reductions that have been 
achieved with modern combustion modification retrofits. CAMD concluded 
that other boilers have achieved NO<INF>X</INF> emissions of 
approximately 0.4 lb/MMBtu, but could not determine if Units 3-5 at 
FCPP were indeed comparable to those boilers. APS did not provide 
enough information in Attachment J to assess the level of similarity. 
Based on information provided in the Andover Report and the EPA CAMD 
review of Attachment J provided by APS, EPA determined that combustion 
controls are not likely to be effective control technologies at FCPP 
due to the inherent limitations of the existing boilers on all units. 
Therefore, EPA rejected the top control option, SCR in combination with 
LNB + OFA, and focused our five factor analysis on the next most 
stringent technology, SCR without LNB + OFA, which can reduce 
NO<INF>X</INF> emissions by 80%.
i. Factor 1: Cost of Compliance
    The cost effectiveness of controls is expressed in cost per ton of 
pollutant reduced ($/ton). 40 CFR Part 51, App. Y, IV.D.4.c. Cost 
effectiveness is calculated by first estimating the total capital and 
annual costs of the BART controls. The second step requires calculating 
the amounts of the pollutants which will be reduced by the control 
technology selected as BART. This second step compares the uncontrolled 
baseline emissions (i.e. emissions from current operations) to the 
proposed BART emissions limits. Id.
    APS submitted cost estimates for all feasible control options in 
January 2008 and submitted revised cost estimates for SCR on March 16, 
2009 to reflect higher costs of construction services and materials. In 
our August 28, 2009 ANPRM, we presented APS's cost estimates for 
emissions controls for NO<INF>X</INF>, which included the revised SCR 
costs submitted in March 2009, and cost estimates from the National 
Park Service

[[Page 64227]]

(NPS). In the ANPRM, EPA revised the annual operating cost estimates 
submitted by APS based on the ratio of annual to capital costs from 
other facilities in the western United States. NPS conducted an 
independent analysis strictly adhering to the EPA Control Cost Manual 
and calculated significantly lower cost effectiveness. In subsequent 
comments on the ANPRM, NPS submitted revised cost estimates for each 
unit. All of these cost estimates are described in detail in the TSD.
    Subsequent to the ANPRM, APS submitted revised cost estimates for 
the NO<INF>X</INF> control technologies. APS provided these revised 
cost estimates to EPA via electronic mail on April 22, 2010, in a 
report dated February 10, 2010. Costs estimated for Unit 1-3 were dated 
May 2008, whereas revised cost estimates were provided for Units 4 and 
5 were dated February 2010. All cost estimates in the 2010 submission 
were lower than those submitted previously. The report updated cost 
estimates for Units 4 and 5 in 2010 dollars and provided cost estimates 
for Units 1-3 in 2008 dollars that are lower than the costs APS 
submitted in March 2009 upon which the ANPRM relied. Because APS only 
recently withdrew a claim of confidentiality for the 2010 cost 
estimates, however, this proposal is based on the costs submitted in 
March 2009. The TSD also contains a further discussion of these costs.
    For this NPR, EPA evaluated the capital and annual cost estimates 
APS submitted in March 2009 against the EPA Control Cost Manual. 
Although EPA has generally accepted the costs estimates APS submitted, 
we have eliminated any line item costs that are not explicitly included 
in the EPA Control Cost Manual and we have revised the costs where EPA 
determined alternate costs were more appropriate, e.g., cost of 
catalysts, or interest rates. Additional detailed information and the 
results of our revisions to the cost estimates are included in Table 13 
of the TSD. EPA's cost effectiveness estimates and those estimated by 
NPS and APS are shown in Table 2.

                       Table 2--EPA, NPS, and APS Cost Effectiveness for SCR on Units 1-5
----------------------------------------------------------------------------------------------------------------
                                                              EPA Cost           NPS Cost           APS Cost
                                                         effectiveness  ($/ effectiveness  ($/ effectiveness ($/
                                                                ton)               ton)               ton)
----------------------------------------------------------------------------------------------------------------
Unit 1.................................................             $2,515             $1,326             $4,887
Unit 2.................................................              3,163              1,882              6,170
Unit 3.................................................              2,678              1,390              5,142
Unit 4.................................................              2,622              1,453              5,197
Unit 5.................................................              2,908              1,598              5,764
----------------------------------------------------------------------------------------------------------------

    EPA's cost effectiveness calculations in this NPR are lower than we 
presented in the ANPRM. The estimates continue to be lower than those 
estimated by APS but higher than those estimated by NPS. The range of 
cost effectiveness that EPA has calculated and upon which this proposal 
is based, from $2,515-$3,163/ton of NO<INF>X</INF> removed, is lower 
than or within the range of other BART evaluations. Some BART analyses 
for other electric generating facilities evaluated SCR with a range of 
costs: Pacificorps Jim Bridger Units 2-4: $2,256-$4,274/ton of 
NO<INF>X</INF> removed; Pacificorps Naughton Units 1-3: $2,751-$2,830/
ton of NO<INF>X</INF> removed; PGE Boardman: $3,096/ton of 
NO<INF>X</INF> removed; M.R. Young Units 1 and 2: $3,950-$4,250/ton of 
NO<INF>X</INF> removed; and Centralia Power Plant Units 1 and 2: 
$9,091/ton of NO<INF>X</INF> removed. San Juan Generating Station in 
Farmington, New Mexico, is a nearby coal fired power plant that was 
built shortly after FCPP and uses coal with almost identical 
characteristics. On June 21, 2010, the New Mexico Environmental 
Department proposed requiring SCR as BART for the four units at San 
Juan Generating Station based on cost-effectiveness calculations 
ranging from $5,946/ton NO<INF>X</INF> reduced to $7,398/ton 
NO<INF>X</INF> reduced.
    EPA considers its revised cost-effectiveness estimates of $2,515-
$3,163/ton of NO<INF>X</INF> removed to be more accurate and 
representative of the actual cost of compliance. However, even if EPA 
had decided to accept APS's worst-case cost estimates of $4,887-$6,170/
ton of NO<INF>X</INF> removed, EPA considers that estimate to be cost 
effective for the purpose of proposing an 80% reduction in 
NO<INF>X</INF>, achievable by installing and operating SCR as BART at 
FCPP.
ii. Factor 2: Energy and Non-Air Quality Impacts
    The Navajo Nation has expressed concerns that requiring additional 
controls at FCPP could result in lost Navajo employment and royalties 
if FCPP were to shut down or curtail operations. EPA has received no 
definitive information indicating that FCPP intends to shut down or 
curtail operations, but to assess the possibility that today's proposed 
BART limits could have such an effect, EPA conducted an economic 
analysis that looked at the impact of requiring SCR on FCPP.
    Based on an economic analysis of the increase in electricity 
generation costs as a result of SCR compared to the estimated cost to 
purchase electricity on the wholesale market, FCPP is expected to 
remain competitive relative to the wholesale market, suggesting that 
the incremental cost increase for SCR alone should not force FCPP to 
shut down. This analysis estimates that the average cost of electricity 
generation over the 20 year amortization period as a result of SCR 
implementation will increase by 22%, or $0.00740/kWh.
    Retail electricity consumers, however, pay more than just the 
generation costs of power. Retail rates include the cost to transmit 
and distribute electricity as well as generate electricity. 
Additionally, for APS customers, for example, the generation cost 
increase on FCPP due to SCR would flow into a broader retail rate 
impact calculation based on the entire portfolio of APS generation 
assets and purchases power contracts, which include coal (of which FCPP 
is only a portion of APS' total coal portfolio), natural gas, nuclear, 
and some renewables. For these reasons, EPA expects the potential rate 
increase to APS rate payers resulting from SCR on FCPP to be 
significantly lower than 22%. This topic is discussed in more detail in 
the TSD.
    In addition to concerns about possible facility shut down, EPA 
received comments regarding potential impacts of increased 
transportation emissions associated with urea deliveries to FCPP for 
SCR and concerns of the affect of SCR on salability of fly ash. EPA 
conducted an analysis to evaluate any increase in health risks 
resulting from increased diesel truck traffic to and from FCPP and 
determined that the increase in cancer and non-cancer health risks

[[Page 64228]]

associated with transportation emissions in the most impacted census 
block in San Juan County, New Mexico, are well below background levels 
and will not result in a significant health risk.
    The Salt River Pima Maricopa Indian Community expressed concern 
about the impact of SCR on their Phoenix Cement Company fly ash 
business unit at FCPP. Ammonia adsorption (resulting from ammonia 
injection from SCR or selective noncatalytic reduction--SNCR) to fly 
ash is generally less desirable due to odor but does not impact the 
integrity of the use of fly ash in concrete. However, other 
NO<INF>X</INF> control technologies, including LNB, also have 
undesirable impacts on fly ash. LNBs increase the amount of unburned 
carbon in the fly ash, also known as Loss of Ignition (LOI), which does 
affect the integrity of the concrete. Commercial-scale technologies 
exist to remove ammonia and LOI from fly ash. Therefore, EPA has 
determined that the impact of SCR on the fly ash at FCPP is smaller 
than the impact of LNB on the fly ash, and in both cases, the adverse 
effects can be mitigated.
    EPA concludes that the energy and non-air quality impacts of SCR do 
not warrant elimination of SCR as the top control option for 
NO<INF>X.</INF>
iii. Factor 3: Existing Controls at the Facility
    There are some existing controls at FCPP for NO<INF>X</INF>. APS 
has installed a variety of LNB on Units 2-5 although these controls are 
all about 20 years old and there have been significant advances in the 
technology for most EGU boilers. Unit 1 does not have any 
NO<INF>X</INF> controls. The controls that APS is operating at FCPP for 
NO<INF>X</INF> do not result in the magnitude of NO<INF>X</INF> 
emissions reduction that are consistent with BART and do not represent 
current control technologies.
iv. Factor 4: Remaining Useful Life of Facility
    The remaining useful life of the facility can be relevant if the 
facility may shut down before the end of the amortization period used 
to annualize the costs of control for a technology. In its analysis, 
APS used an amortization period of 20 years, the standard amortization 
period recommended by EPA, and indicated that it anticipated that the 
remaining useful life of Units 1-5 is at least 20 years. As it appears 
that the FCPP facility will continue to operate for at least 20 years, 
EPA agrees with the use of an amortization period of 20 years to 
estimate costs.
v. Factor 5: Degree of Visibility Improvement
    The fifth factor to consider under EPA's BART Guidelines is the 
degree of visibility improvement from the BART control options. See 59 
FR at 39170. The BART guidelines recommend using the CALPUFF air 
quality dispersion model to estimate the visibility improvements of 
alternative control technologies at each Class I area, typically those 
within a 300 km radius of the source, and to compare these to each 
other and to the impact of the baseline (i.e., current) source 
configuration. APS included sixteen Class I Areas in its modeling 
analysis; fifteen are within 300 km of FCPP and one Class I area, Grand 
Canyon National Park, is just beyond 300 km from FCPP. These areas are 
listed in Table 22 of the TSD.
    The BART guidelines recommend comparing visibility improvements 
between control options using the 98th percentile of 24-hour delta 
deciviews, which is roughly equivalent to the facility's 8th highest 
visibility impact day. The ``delta'' refers to the difference between 
total deciview impact from the facility plus natural background, and 
deciviews of natural background alone, so ``delta deciviews'' is the 
estimate of the facility's impact. Visibility is traditionally 
described in terms of visual range in kilometers or miles. However, the 
visual range scale does not correspond to how people perceive 
visibility because how a given increase in visual range is perceived 
depends on the starting visibility against which it is compared. Thus, 
an increase in visual range may be perceived to be a big improvement 
when starting visibility is poor, but a relatively small improvement 
when starting visibility is good.
    The ``deciview'' scale is designed to address this problem. It is 
linear with respect to perceived visibility changes over its entire 
range, and is analogous to the decibel scale for sound. This means that 
a given change in deciviews will be perceived as the same amount of 
visibility change regardless of the starting visibility. Lower deciview 
values represent better visibility and greater visual range, while 
increasing deciview values represent increasingly poor visibility. In 
the BART guidelines, EPA noted that a 1.0 deciview impact from a source 
is sufficient to ``cause'' visibility impairment and that a source with 
a 0.5 deciview impact must ``contribute'' to visibility impairment. 
Generally, 0.5 deciviews is the amount of change that is just 
perceptible to a human observer.
    Under the BART guidelines, the improved visibility in deciviews 
from installing controls is determined by using the CALPUFF air quality 
model. CALPUFF, generally, simulates the transport and dispersion of 
FCPP emissions, and the conversion of SO<INF>2</INF> emitted from FCPP 
to particulate sulfate and NO<INF>X</INF> to particulate nitrate, at a 
rate dependent on meteorological conditions and background ozone 
concentration. These concentrations are then converted to delta 
deciviews by the CALPOST post-processor. The CALPUFF model and CALPOST 
post-processing are explained in more detail in the TSD.
    The ``delta deciviews'' estimated by the modeling represents the 
facility's impact on visibility at the Class I areas. Each modeled day 
and location in the Class I area will have an associated delta 
deciviews. For each day, the model finds the maximum visibility impact 
of all locations (i.e., receptors) in the Class I area. From among 
these daily values, the BART guidelines recommend use of the 98th 
percentile, which is roughly equivalent to the 8th highest day for a 
given year, for comparing the base case and the effects of various 
controls. The 98th percentile is recommended rather than the maximum 
value to avoid undue influence from unusual meteorological conditions. 
Meteorological conditions are modeled using the CALMET model.
    APS conducted modeling for FCPP according to a modeling protocol 
submitted to EPA. See BART Visibility Modeling Protocol for the Arizona 
Public Service Four Corners Power Plant, ENSR Corporation, January 
2008. APS's modeling used the CALMET and CALPUFF versions recommended 
by EPA but in blending in meteorological station wind observations, APS 
used a lower radius of influence for stations. This change resulted in 
smoother wind fields. After initial input from the Federal Land 
Managers, EPA requested APS to change certain other CALMET option 
settings. These changes resulted in a more refined approach that is 
more consistent with approaches used in PSD permit application 
modeling. Further details about the CALPUFF and CALMET modeling are in 
the TSD, and the relevant CALMET settings are listed in Table 23.
    In addition to the different CALPUFF emission rates described 
above, EPA's evaluation of anticipated visibility improvement used 
revised post-processor settings from those originally used by APS. The 
USFS informed EPA that the ammonia background concentrations modeled by 
APS in January 2008 were lower than observed

[[Page 64229]]

concentrations.\9\ The USFS recommended a method of back-calculating 
the ammonia background based on monitored values of sulfate and 
nitrate. EPA's ANPRM provided results based on using the USFS's back-
calculation methodology.
---------------------------------------------------------------------------

    \9\ 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.
---------------------------------------------------------------------------

    The visibility modeling supporting today's proposal, however, uses 
a constant ammonia background of 1 ppb, which is the default value 
recommended for western areas. IWAQM Phase 2 document.\10\ The TSD 
contains supplemental modeling using back-calculated ammonia 
concentrations, a thorough discussion of the back-calculation 
methodology and the sensitivity results based on selecting different 
concentrations of background ammonia.
---------------------------------------------------------------------------

    \10\ Interagency Workgroup On Air Quality Modeling (IWAQM) Phase 
2 Summary Report And Recommendations For Modeling Long Range 
Transport Impacts (EPA-454/R-98-019), EPA OAQPS, December 1998, 
http://www.epa.gov/scram001/7thconf/calpuff/phase2.pdf.
---------------------------------------------------------------------------

    The background values of ammonia are important because it is a 
precursor to particulate ammonium sulfate and ammonium nitrate, both of 
which degrade visibility. Ammonia is present in the air from both 
natural and anthropogenic sources. The latter may include livestock 
operations, fertilizer application associated with farming, and ammonia 
slip from the use of ammonia in SCR and SNCR technologies to control 
NO<INF>X</INF> emissions. Sensitivity of the model results to other 
ammonia assumptions are discussed in the TSD, and do not change the 
ranking of control options for evaluating visibility improvement, or 
the overall conclusions of the visibility analysis.
    In our modeling input for ammonia, EPA assumed that the remaining 
ammonia in the flue gas following SCR reacts to form ammonium sulfate 
or ammonium bisulfate before exiting the stack. This particulate 
ammonium is represented in the modeling as sulfate (SO<INF>4</INF>) 
emissions. Thus, EPA addressed ammonia solely as a background 
concentration.
    In the supplemental sensitivity analyses using different ammonia 
values described in the TSD, ammonia concentrations for Mesa Verde 
National Park were not based on the back-calculation method, but 
instead were derived from measured ammonia concentrations in the Four 
Corners area, as described in Sather et al., (2008).\11\ Monitored data 
were available within Mesa Verde NP, but because particulate formation 
happens within a pollutant plume as it travels, rather than 
instantaneously at the Class I area, EPA also examined data at 
locations outside Mesa Verde NP itself. Monitored 3-week average 
ammonia at the Substation site, some 30 miles south of Mesa Verde, were 
as high as 3.5 ppb, though generally levels were less than 1.5 ppb. 
Maximum values in Mesa Verde were 0.6 ppb, whereas other sites' maxima 
ranged from 1 to 3 ppb, but generally values were less than 2 ppb. EPA 
used values estimated from Figure 5 of Sather et al., (2008), in the 
mid-range of the various stations plotted. The results ranged from 1.0 
ppb in winter to 1.5 ppb in summer. See TSD, Table 33.
---------------------------------------------------------------------------

    \11\ 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.
---------------------------------------------------------------------------

    The BART determination guidelines recommend that visibility impacts 
should be estimated in deciviews relative to natural background 
conditions. CALPOST, a CALPUFF post-processor, uses background 
concentrations of various pollutants to calculate the natural 
background visibility impact. EPA used background concentrations from 
Table 2-1 of ``Guidance for Estimating Natural Visibility Conditions 
Under the Regional Haze Rule.'' \12\ Although the concentration for 
each pollutant is a single value for the year, this method allows for 
monthly variation in its visibility impact, which changes with relative 
humidity. The resulting deciviews differ by roughly 1% from those 
resulting from the method originally used by APS.
---------------------------------------------------------------------------

    \12\ 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.
---------------------------------------------------------------------------

    To assess results from the CALPUFF model and post-processing steps, 
in addition to considering deciview changes directly, EPA used a least-
squares regression analysis of all visibility modeling output from the 
2001-2003 modeling period to determine the percent improvement in 
FCPP's visibility impact (in delta deciviews) resulting from the 
application of control technologies compared to the FCPP's baseline 
impacts.
    As outlined in the 1999 Regional Haze rule (64 FR 35725, July 1, 
1999), a one deciview change in visibility is a small but noticeable 
change in visibility under most circumstances when viewing scenes in a 
Class I area. Table 3 presents the visibility impacts of the 98th 
percentile of daily maxima for each Class I area for each year, 
averaged over 2001-2003.\13\ The modeled visibility improvement at all 
Class I areas exceeds 0.5 deciviews and at most Class I areas exceeds 1 
deciview.
---------------------------------------------------------------------------

    \13\ 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 affect the overall 
results.

  Table 3--EPA Modeling Results--8th High Delta dv Improvement and Percent Change in Delta Deciview (dv) Impact From NOX Controls Compared to Baseline
                                             Impacts From 2001-2003 Using 1 ppb Ammonia Background Scenario
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                            Distance to      Baseline     Improvement from LNB/LNB + OFA       Improvement from SCR
                                                               FCPP           impact     ---------------------------------------------------------------
                      Class I area                       --------------------------------
                                                            Kilometers                       Delta  dv           %           Delta dv            %
                                                               (km)          Delta  dv
--------------------------------------------------------------------------------------------------------------------------------------------------------
Arches National Park....................................             245            4.11            0.87              18            2.40              55
Bandelier Wilderness Area...............................             216            2.90            0.54              21            1.62              57
Black Canyon of the Gunnison WA.........................             217            2.36            0.46              23            1.42              60
Canyonlands NP..........................................             214            5.24            0.79              16            2.81              51
Capitol Reef NP.........................................             283            3.23            0.77              18            1.87              52
Grand Canyon NP.........................................             345            1.63            0.34              20            0.88              55
Great Sand Dunes NM.....................................             279            1.16            0.31              25            0.67              62
La Garita WA............................................             202            1.72            0.44              25            1.05              62
Maroon Bells Snowmass WA................................             294            1.04            0.27              26            0.64              63

[[Page 64230]]

 
Mesa Verde NP...........................................              62            5.95            0.62              13            2.43              45
Pecos WA................................................             258            2.16            0.52              23            1.15              58
Petrified Forest NP.....................................             224            1.40            0.27              21            0.65              56
San Pedro Parks WA......................................             160            3.88            0.68              19            2.02              53
Weminuche WA............................................             137            1.87            0.49              25            1.19              62
West Elk WA.............................................             245            2.76            0.65              23            1.70              60
Wheeler Peak WA.........................................             265            1.53            0.37              24            0.84              59
                                                         -----------------------------------------------------------------------------------------------
    Total Delta dv or Average % Change in Delta dv......  ..............           42.94            8.39              21           23.34              57
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Because installation and operation of SCR at FCPP to reduce 
NO<INF>X</INF> emissions by 80% will provide perceptible and 
significant visibility improvements at all of the surrounding Class I 
areas, and because LNB will result in much less visibility improvement 
than SCR, EPA is proposing to require FCPP to reduce NO<INF>X</INF> by 
80% by meeting a plant-wide emissions limit of 0.11 lb/MMBtu, which is 
achievable with SCR. Our analysis also shows that the visibility 
improvement from the emissions reductions achieved with LNB are 
significantly lower.

D. Available and Feasible Control Technologies and Five Factor Analysis 
for PM Emissions

    For PM, APS identified seven options as available retrofit 
technologies that would rely on post-combustion capture of the 
emissions. APS determined three options were technically feasible for 
PM control on Units 1-3: Wet electrostatic precipitators (ESPs), dry 
ESPs, and pulse jet fabric filters (PJFF or baghouses). These three 
control options were determined to all have similar levels of PM 
control of 99.9%. One control option, called the GE-MAX-9 hybrid, which 
is an ESP using a fabric filter collection bag, is estimated to have a 
PM control efficiency of 99.999% and has been used in a demonstration 
project, but has not been demonstrated on larger units. Therefore, EPA 
considered the other top three options, wet and dry ESP and baghouses, 
for PM control at FCPP.
    APS has been operating venturi scrubbers on Units 1-3 at FCPP since 
the 1970s resulting in PM reductions as well as SO<INF>2</INF> 
reductions. PM is controlled on Units 4 and 5 with baghouses. Venturi 
scrubbers have been used by large coal fired electric generating units 
(EGUs), but since promulgation of the New Source Performance Standards, 
have largely been replaced by more advanced technology that can achieve 
better PM reductions and provide better compliance assurance. Units 1-3 
at FCPP are the last EGUs in Region 9 to continue to operate venturi 
scrubbers. The other EGUs in Region 9 have generally been retrofit with 
baghouses.
    In this NPR, EPA is proposing to require APS to upgrade its PM 
controls as described below to meet an emission limit of 0.012 lb/MMBtu 
and 10% opacity on Units 1-3, which is achievable either through 
installing baghouses or ESPs. Because of the high incremental cost of 
both options, however, EPA is also asking for comment on whether APS 
can satisfy BART by operating the existing venturi scrubbers to meet an 
emissions limit of 0.03 lb/MMBtu with a 20% opacity limit to 
demonstrate continuous compliance. EPA is proposing to require APS to 
operate the existing baghouse for Units 4 and 5 to meet an emissions 
limit of 0.015 lb/MMBtu and 10% opacity.
i. Factor 1: Cost of Compliance
    EPA is proposing to require APS to install ESPs (wet or dry) or 
PJFFs for Units 1-3 to comply with an emissions limit of 0.012 lb/MMBtu 
and a 10% opacity limit. For Units 4 and 5, APS would not need to 
install any controls in addition to the baghouses currently in place 
but would be required to operate the baghouses to meet an emission 
limit of 0.015 lb/MMBtu and a 10% opacity limit.
    The wet-membrane ESP is the lowest cost approach to meeting the 
proposed PM BART limit of 0.012 lb/MMBtu for Units 1-3, but a wet 
membrane ESP would result in a very high cost effectiveness value for 
incremental cost because the existing venturi scrubbers are removing 
much of the PM. In other words, any control device, such as an ESP, 
placed downstream of the venturi scrubbers will result in a high 
incremental cost because the denominator (tons removed) of the cost 
effectiveness calculation will be relatively small.
    Alternatively, APS could install baghouses on Units 1-3 at FCPP 
upstream of the venturi scrubbers. The baghouses would be the most 
likely choice for APS for PM control if APS also wants to achieve 
significant mercury (``Hg'') reduction from these units. Installing 
baghouses would make those controls the primary PM control device (i.e. 
the downstream venturi scrubbers would primarily control SO<INF>2</INF> 
emissions) and the cost effectiveness for Units 1-3 would average less 
than $110 per ton of PM removed. These costs are discussed further in 
Section 3 of the TSD.
    Baghouses have already been installed on the four other coal fired 
EGUs in Region 9 that had historically used venturi scrubbers for PM 
control, including the only other venturi scrubber owned and operated 
by APS at its Cholla Unit 1. NV Energy Reid Gardner offered to install 
baghouses at Units 1, 2, and 3 as extra injunctive relief in a 
settlement agreement. Those baghouses are installed and operating 
(despite the high incremental dollars per ton of PM removed) to allow 
the units to achieve continuous compliance with PM and opacity limits 
and to prepare for the upcoming utility MACT regulation of Hg.
    EPA considers installation of either ESPs (wet or dry) or baghouses 
as reasonable-cost technology capable of achieving the proposed BART 
emission limit of 0.012 lb/MMBu for Units 1-3. However, because of the 
high incremental costs associated with ESPs or baghouses, EPA is also 
asking for

[[Page 64231]]

comment on whether APS can satisfy BART by continuing to operate the 
venturi scrubbers on Units 1-3, demonstrating compliance with an 
emissions limit of 0.03 lb/MMBtu with a continuous opacity limit of 
20%. EPA's basis for establishing a PM emissions limit of 0.03 lb/MMBtu 
is consistency with NSPS Subpart Da, which has been the applicable 
emissions limit for any boiler placed into service after 1978. We 
believe that an emissions limit that has been in place for over 35 
years should be achievable with the venturi scrubbers. We provide 
further discussion of this issue in Subsection D.3 below and the TSD.
ii. Factor 2: Energy and Non-Air Quality Impacts
    EPA is not aware of any energy and non-air quality impacts 
associated with any of the technologies discussed above that would 
eliminate them from consideration as BART.
iii. Factor 3: Existing Controls at the Facility
    Units 1-3 are controlled by venturi scrubbers, which also are used 
for SO<INF>2</INF> control. These scrubbers operate at pressure drops 
less than 10 inches of water. Venturi scrubbers have not been installed 
for PM pollution control on any coal fired EGU in Region 9 since the 
early 1970s. Venturi scrubbers have not been in use since that time 
principally due to concerns over the ability of venturi scrubbers to 
continuously meet the 0.10 lb/MMBtu standard established by a New 
Source Performance Standard in 1971. See 40 CFR Part 60 Subpart D. 
Fossil fuel fired boiler standards for coal fired units were revised 
for units built after 1978 and the PM limit was lowered to 0.03 lb/
MMBtu. See 40 CFR Part 60 Subpart Da. Most current coal fired boilers 
now use baghouses which are capable of meeting PM limits of about 0.01 
to 0.012 lb/MMBtu.
    As mentioned earlier in the cost discussion, baghouses have already 
been installed on the four other coal fired EGUs in Region 9 that had 
historically used venturi scrubbers for PM control, including APS's 
Cholla Unit 1. These baghouses were installed, despite the very high 
incremental dollars per ton of PM removed, to allow the companies to 
continue to operate the units in continuous compliance with their PM 
and opacity limits.
    EPA notes that Units 1-3 at FCPP were operated with a re-heat of 
the scrubber exhaust. This allows the use of Continuous Opacity 
Monitors (COMs) in their stacks and provides an ongoing measurement of 
the opacity compliance. EPA understands that these three units 
originally installed and operated a re-heat system, but FCPP 
discontinued its use. EPA Region 9 is not aware of when APS 
discontinued using the re-heat system. The three venturi-equipped 
units, Units 1-3, do not have COMs or opacity limits, which are 
required on all other EGUs in Region 9 and likely all across the U.S. 
because SIPs, such as Arizona's, generally include a 20% opacity 
standard. Opacity standards are a regulatory tool that allows agencies 
and the public to ensure continuing compliance for PM.
    Over the past several years the PM source testing for Units 1 and 2 
have consistently complied with the PM limit of 0.03 lb/MMBtu by 
operating the venturi scrubbers. Unit 3 exceeded the limit in 2007 but 
after subsequent source tests averages an emission rate of below 0.03 
lb/MMBtu.
    EPA is requesting comment on allowing APS to continue to operate 
the venturi scrubbers on Units 1-3 provided it can demonstrate 
compliance with an emissions limit of 0.03 lb/MMBtu (as required by the 
NSPS Subpart Da for all post 1978 units) and a continuous opacity limit 
of 20%.
iv. Factor 4: Remaining Useful Life of Facility
    As with NO<INF>X</INF>, EPA is assuming that the remaining useful 
life of the facility is 20 years.
v. Factor 5: Degree of Visibility Improvement
    The modeled visibility improvements resulting from additional PM 
control are relatively small. See Table 4.

  Table 4--EPA Modeling Results--8th High Delta dv Improvement and Percent Change in Delta Deciview (dv) Impact
       From PM Control Compared to Baseline Impacts From 2001-2003 Using 1 ppb Ammonia Background Scenario
----------------------------------------------------------------------------------------------------------------
                                         Distance to FCPP   Baseline impact      Improvement from PM control
              Class I area              ------------------------------------------------------------------------
                                         Kilometers  (km)      Delta dv           Delta dv              %
----------------------------------------------------------------------------------------------------------------
Arches National Park...................               245              4.11               0.01                 0
Bandelier Wilderness Area..............               216              2.90               0.01                 0
Black Canyon of the Gunnison WA........               217              2.36               0                    0
Canyonlands NP.........................               214              5.24               0.02                 0
Capitol Reef NP........................               283              3.23               0.01                 0
Grand Canyon NP........................               345              1.63               0.01                 0
Great Sand Dunes NM....................               279              1.16               0                    0
La Garita WA...........................               202              1.72               0                    0
Maroon Bells Snowmass WA...............               294              1.04               0                    0
Mesa Verde NP..........................                62              5.95               0.02                 1
Pecos WA...............................               258              2.16               0.01                 0
Petrified Forest NP....................               224              1.40               0.01                 0
San Pedro Parks WA.....................               160              3.88               0.02                 1
Weminuche WA...........................               137              1.87               0                    0
West Elk WA............................               245              2.76               0                    0
Wheeler Peak WA........................               265              1.53               0.01                 0
                                        ------------------------------------------------------------------------
Total Delta dv or Average % Change in    ................             42.94               0.13                 0
 Delta dv..............................
----------------------------------------------------------------------------------------------------------------

    However, this factor may be somewhat misleading because the model 
does not include consideration of the visibility impairing plume that 
is almost always present after the steam plume from Units 1-3 
evaporates. The

[[Page 64232]]

term EPA uses for this plume is a ``secondary visible plume''. This 
secondary visible plume often stretches for over 20 miles from FCPP and 
is most apparent in the early mornings when the typical inversions cap 
the dispersion of the secondary visible plume. EPA does not have any 
information as to whether this secondary visible plume can be seen from 
Mesa Verde National Park, the closest Class 1 area to FCPP. EPA Region 
9 staff has observed this secondary visible plume in New Mexico out as 
far as Aztec and Bloomfield en route to Farmington from Albuquerque. 
Therefore, EPA is specifically seeking information on this secondary 
visible plume, its frequency and persistence, and whether or not it 
affects or can be observed from any Class 1 area.
    In the TSD, EPA discusses this secondary visible plume and whether 
it is related to the poor control of fine particulates by the venturi 
scrubbers. EPA is also seeking information as to whether this plume has 
been observed from Units 4 and 5. Although the modeled visibility 
improvements from requiring additional PM controls are small, EPA 
considers eliminating the secondary visible plume from Units 1-3 to be 
important for visibility in the area. EPA is proposing to require APS 
to install either ESPs (wet or dry) or baghouses to meet an emissions 
limit of 0.012 lb/MMBtu with a 10% opacity limit. EPA is also taking 
comment on whether BART can be satisfied by allowing APS to continue to 
operate its existing venturi scrubbers on Units 1-3 to demonstrate 
compliance with an emissions limit of 0.03 lb/MMBtu with a 20% opacity 
limit.

III. EPA Proposed Action on Material Handling Limits

    EPA is also proposing dust control requirements for FCPP. These 
requirements were included in the FIP that EPA finalized in 2007. APS 
appealed this portion of the 2007 FIP and EPA agreed to a voluntary 
remand of the dust control requirements to provide further 
justification in the record.
    FCPP receives approximately 10 million tons of coal per year for 
combusting in the Units 1-5. This material moves by conveyor belt 
across the property line through numerous transfer points before being 
loaded to the storage silos that feed the individual Units. Each of 
these transfer points along with the conveyor belts has the potential 
for PM emissions. The PM can be minimized by collecting devices or dust 
suppression techniques such as covered conveyors or spraying devices at 
the transfer points.
    After combustion, FCPP has a very large amount of ash that needs to 
be handled properly to prevent PM emissions to the air. The coal APS 
combusts at FCPP has as much as 25% ash. This means that there are over 
a million tons of ash that must be properly transported within the 
plant and then disposed. Some of this ash is stored in ash silos and is 
sold to companies that use it as an additive for making concrete. Much 
of the ash is currently disposed at a relatively new onsite ash 
landfill. All of this ash, which has the potential to become airborne 
PM, must be properly handled to prevent PM<INF>10</INF> NAAQS issues.
    FCPP's property line abuts the coal mine property and the entire 
coal handling and fly ash storage is within close proximity to Morgan 
Lake which is a recreational lake just beyond the FCPP's property line. 
EPA has received numerous complaints from Navajo Tribal members 
concerning excess dust generated from the new landfill. For these 
reasons, EPA considers it necessary or appropriate for dust/PM 
suppression measures to be enforceable to protect the ambient air 
quality.
    EPA is proposing to require APS to implement a dust control plan 
and a 20% opacity standard for all material handling operations. The 
dust plan must provide measures to ensure that the coal handling, ash 
handling and disposal and general dust generating sources do not exceed 
20% opacity. Dust control measures at coal fired power plants are 
important for maintaining the PM<INF>10</INF> NAAQS in the areas 
adjacent to the power plant properties. Most coal fired power plants 
that are grandfathered from the NSPS Subpart Y (40 CFR part 60) and 
from Prevention of Significant Deterioration (PSD) case by case BACT 
determinations are covered by general SIP rules regulating emissions 
and have associated opacity standards to assure proper operation of 
dust control or suppression measures during the times when stack 
testing is not conducted. Grandfathered facilities usually were subject 
to process weight PM limits under SIPs. These limits used an 
exponential equation approach to setting the allowable lb/hr PM based 
on the amount of material processed per hour. The limits typically 
become more stringent as a ratio of the allowable emissions to the 
throughput as the amount of material throughput increases. The SIPs 
also apply a general opacity limit to these PM emitting units.
    Because FCPP is located on the Navajo Reservation where generally 
applicable limits that often are included in SIPs do not exist, and 
because dust control measures at coal fired power plants are important 
for maintaining the PM<INF>10</INF> NAAQS in the areas adjacent to the 
power plant properties, EPA finds that it is necessary or appropriate 
to impose measures to limit the amount of PM emissions from these 
material handling emission sources. EPA recently imposed similar dust 
control requirements at the Navajo Generating Station which is also on 
the Navajo Nation Reservation.

IV. Administrative Requirements

A. Executive Order 12866: Regulatory Planning and Review

    This proposed action is not a ``significant regulatory action'' 
under the terms of Executive Order (EO) 12866 (58 FR 51735, October 4, 
1993) because it is a proposed rule that applies to only one facility 
and is not a rule of general applicability. This proposed rule, 
therefore, is not subject to review under EO 12866. This action 
proposes a source-specific FIP for the Four Corners Power Plant on the 
Navajo Nation.

B. Paperwork Reduction Act

    This proposed action does not impose an information collection 
burden under the provisions of the Paperwork Reduction Act, 44 U.S.C. 
3501 et seq. Under the Paperwork Reduction Act, a ``collection of 
information'' is defined as a requirement for ``answers to * * * 
identical reporting or recordkeeping requirements imposed on ten or 
more persons * * *.'' 44 U.S.C. 3502(3)(A). Because the proposed FIP 
applies to a single facility, Four Corners Power Plant, the Paperwork 
Reduction Act does not apply. See 5 CFR 1320(c).
    Burden means the total time, effort, or financial resources 
expended by persons to generate, maintain, retain, or disclose or 
provide information to or for a Federal agency. This includes the time 
needed to review instructions; develop, acquire, install, and utilize 
technology and systems for the purposes of collecting, validating, and 
verifying information, processing and maintaining information, and 
disclosing and providing information; adjust the existing ways to 
comply with any previously applicable instructions and requirements; 
train personnel to be able to respond to a collection of information; 
search data sources; complete and review the collection of information; 
and transmit or otherwise disclose the information.
    An agency may not conduct or sponsor, and a person is not required 
to respond to a collection of information unless it displays a 
currently valid OMB control number. The OMB control

[[Page 64233]]

numbers for EPA's regulations in 40 CFR are listed in 40 CFR Part 9.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to prepare a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements under the Administrative 
Procedure Act or any other statute unless the agency certifies that the 
rule will not have a significant economic impact on a substantial 
number of small entities. Small entities include small businesses, 
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of today's proposed rule on 
small entities, small entity is defined as: (1) A small business as 
defined by the Small Business Administration's (SBA) regulations at 13 
CFR 121.201; (2) a small governmental jurisdiction that is a government 
of a city, county, town, school district or special district with a 
population of less than 50,000; and (3) a small organization that is 
any not-for-profit enterprise which is independently owned and operated 
and is not dominant in its field.
    After considering the economic impacts of this proposed action on 
small entities, I certify that this proposed action will not have a 
significant economic impact on a substantial number of small entities. 
The FIP for Four Corners Power Plant being proposed today does not 
impose any new requirements on small entities. See Mid-Tex Electric 
Cooperative, Inc. v. FERC, 773 F.2d 327 (DC Cir. 1985).

D. Unfunded Mandates Reform Act (UMRA)

    This proposed rule, if finalized, will impose an enforceable duty 
on the private sector owners of FCPP. However, this rule does not 
contain a Federal mandate that may result in expenditures of $100 
million (in 1996 dollars) or more for State, local, and tribal 
governments, in the aggregate, or the private sector in any one year. 
EPA's estimate for the total annual cost to install and operate SCR on 
all five units at FCPP and the cost to install and operate new PM 
controls on Units 1-3 does not exceed $100 million (in 1996 dollars) in 
any one year. Thus, this rule is not subject to the requirements of 
sections 202 or 205 of UMRA. This proposed action is also not subject 
to the requirements of section 203 of UMRA because it contains no 
regulatory requirements that might significantly or uniquely affect 
small governments. This rule will not impose direct compliance costs on 
the Navajo Nation, and will not preempt Navajo law. This proposed 
action will, if finalized, reduce the emissions of two pollutants from 
a single source, the Four Corners Power Plant.

E. Executive Order 13132: Federalism

    Under section 6(b) of Executive Order 13132, EPA may not issue an 
action that has federalism implications, that imposes substantial 
direct compliance costs on State or local governments, and that is not 
required by statute, unless the Federal government provides the funds 
necessary to pay the direct compliance costs incurred by State and 
local governments, or EPA consults with State and local officials early 
in the process of developing the proposed action. In addition, under 
section 6(c) of Executive Order 13132, EPA may not issue an action that 
has federalism implications and that preempts State law, unless the 
Agency consults with State and local officials early in the process of 
developing the proposed action.
    EPA has concluded that this proposed action, if finalized, may have 
federalism implications because it makes calls for emissions reductions 
of two pollutants from a specific source on the Navajo Nation. However, 
the proposed rule, if finalized, will not impose substantial direct 
compliance costs on the Tribal government, and will not preempt Tribal 
law. Thus, the requirements of sections 6(b) and 6(c) of the Executive 
Order do not apply to this action.
    Consistent with EPA policy, EPA nonetheless consulted with 
representatives of Tribal governments \14\ early in the process of 
developing the proposed action to permit them to have meaningful and 
timely input into its development.
---------------------------------------------------------------------------

    \14\ ``Representatives of State and local governments'' include 
non-elected officials of State and local governments and any 
representative national organizations not listed in footnote 3.
---------------------------------------------------------------------------

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    Executive Order 13175, entitled ``Consultation and Coordination 
with Indian Tribal Governments'' (65 FR 67249, Nov. 9, 2000), requires 
EPA to develop ``an accountable process to ensure meaningful and timely 
input by tribal officials in the development of regulatory policies 
that have tribal implications.'' Under Executive Order 13175, to the 
extent practicable and permitted by law, EPA may not issue a regulation 
that has tribal implications, that imposes substantial direct 
compliance costs on Indian tribal governments, and that is not required 
by statute, unless the Federal government provides the funds necessary 
to pay direct compliance costs incurred by tribal governments, or EPA 
consults with tribal officials early in the process of developing the 
proposed regulation and develops a tribal summary impact statement. In 
addition, to the extent practicable and permitted by law, EPA may not 
issue a regulation that has tribal implications and pre-empts tribal 
law unless EPA consults with tribal officials early in the process of 
developing the proposed regulation and prepares a tribal summary impact 
statement.
    EPA has concluded that this proposed rule, if finalized, may have 
tribal implications because it will require emissions reductions of two 
pollutants by a major stationary source located and operating on the 
Navajo reservation. However, this proposed rule, if finalized, will 
neither impose substantial direct compliance costs on tribal 
governments nor pre-empt Tribal law because the proposed FIP imposes 
obligations only on the owners or operator of the Four Corners Power 
Plant.
    EPA has consulted with officials of the Navajo Nation in the 
process of developing this proposed FIP. EPA had an in-person meeting 
with Tribal representatives prior to the proposal and will continue to 
consult with Tribal officials during the public comment period on the 
proposed FIP. In addition, EPA provided Navajo Nation and other tribal 
governments additional time to submit formal comments on our Advanced 
Notice of Proposed Rulemaking. Several tribes, including the Navajo, 
submitted comments which EPA considered in developing this NPR. 
Therefore, EPA has allowed the Navajo Nation to provide meaningful and 
timely input into the development of this proposed rule and will 
continue to consult with the Navajo Nation and other affected Tribes 
prior to finalizing our BART determination.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    Executive Order 13045: Protection of Children from Environmental 
Health Risks and Safety Risks (62 FR 19885, April 23, 1997), applies to 
any rule that: (1) is determined to be economically significant as 
defined under Executive Order 12866, and (2) concerns an environmental 
health or safety risk that EPA has reason to believe may have a 
disproportionate effect on children. If the regulatory action meets 
both criteria, the Agency must evaluate the environmental health or 
safety effects of the planned rule on children, and

[[Page 64234]]

explain why the planned regulation is preferable to other potentially 
effective and reasonably feasible alternatives considered by the 
Agency.
    This proposed rule is not subject to Executive Order 13045 because 
it requires emissions reductions of two pollutants from a single 
stationary source. Because this proposed action only applies to a 
single source and is not a proposed rule of general applicability, it 
is not economically significant as defined under Executive Order 12866, 
and does not have a disproportionate effect on children. However, to 
the extent that the rule will reduce emissions of PM and 
NO<INF>X</INF>, which contributes to ozone formation, the rule will 
have a beneficial effect on children's health by reducing air pollution 
that causes or exacerbates childhood asthma and other respiratory 
issues.

H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This action is not subject to Executive Order 13211 (66 FR 28355 
(May 22, 2001)), because it is not a significant regulatory action 
under Executive Order 12866.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act of 1995 (NTTAA), Public Law 104-113, 12 (10) (15 U.S.C. 272 note) 
directs EPA to use voluntary consensus standards (VCS) in its 
regulatory activities unless to do so would be inconsistent with 
applicable law or otherwise impractical. VCS are technical standards 
(e.g., materials specifications, test methods, sampling procedures and 
business practices) that are developed or adopted by the VCS bodies. 
The NTTAA directs EPA to provide Congress, through annual reports to 
OMB, with explanations when the Agency decides not to use available and 
applicable VCS.
    Consistent with the NTTAA, the Agency conducted a search to 
identify potentially applicable VCS. For the measurements listed below, 
there are a number of VCS that appear to have possible use in lieu of 
the EPA test methods and performance specifications (40 CFR Part 60, 
Appendices A and B) noted next to the measurement requirements. It 
would not be practical to specify these standards in the current 
proposed rulemaking due to a lack of sufficient data on equivalency and 
validation and because some are still under development. However, EPA's 
Office of Air Quality Planning and Standards is in the process of 
reviewing all available VCS for incorporation by reference into the 
test methods and performance specifications of 40 CFR Part 60, 
Appendices A and B. Any VCS so incorporated in a specified test method 
or performance specification would then be available for use in 
determining the emissions from this facility. This will be an ongoing 
process designed to incorporate suitable VCS as they become available. 
EPA is requesting comment on other appropriate VCS for measuring 
opacity or emissions of PM and NO<INF>X</INF>.
    Particulate Matter Emissions--EPA Methods 1 though 5.
    Opacity--EPA Method 9 and Performance Specification Test 1 for 
Opacity Monitoring.
    NO<INF>X</INF> Emissions--Continuous Emissions Monitors.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629, February 16, 1994), establishes 
federal executive policy on environmental justice. Its main provision 
directs federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority populations and low-income 
populations in the United States.
    EPA has determined that this proposed rule, if finalized, will not 
have disproportionately high and adverse human health or environmental 
effects on minority or low-income populations because it increases the 
level of environmental protection for all affected populations without 
having any disproportionately high and adverse human health or 
environmental effects on any population, including any minority or low-
income population. This proposed rule requires emissions reductions of 
two pollutants from a single stationary source, Four Corners Power 
Plant.

List of Subjects in 40 CFR Part 49

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Indians, Intergovernmental relations, Reporting 
and recordkeeping requirements.

    Dated: October 6, 2010.
Jared Blumenfeld,
Regional Administrator, Region IX.

    Title 40, chapter I of the Code of Federal Regulations is proposed 
to be amended as follows:

PART 49--[AMENDED]

    1. The authority citation for part 49 continues to read as follows:

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

    2. Section 49.23 is amended by adding paragraphs (i) and (j) to 
read as follows:


Sec.  49.23  Federal Implementation Plan Provisions for Four Corners 
Power Plant, Navajo Nation.

* * * * *
    (i) Regional Haze Best Available Retrofit Technology limits for 
this plant are in addition to the requirements in paragraphs (a) 
through (h) of this section. All definitions and testing and monitoring 
methods of this section apply to the limits in paragraph (i) of this 
section except as indicated in paragraphs (i)(1) through (4) of this 
section. Within 180 days of the effective date of this paragraph (i), 
the owner or operator shall submit a plan to the Regional Administrator 
that identifies the control equipment and schedule for complying with 
this paragraph (i). The owner or operator shall amend and submit this 
amended plan to the Regional Administrator as changes occur. The 
interim limits for each unit shall be effective 180 days after re-start 
of the unit after installation of SCR controls for that unit and until 
the plant-wide limit goes into effect. The plant-wide NO<INF>X</INF> 
limit shall be effective no later than 5 years after the effective date 
of this rule. APS may elect to meet the plant-wide limit early to 
remove the individual unit limits. Particulate limits for Units 1, 2, 
and 3 shall be effective 180 days after re-start of the units after 
installation of the PM controls but no later than 5 years after the 
effective date of this paragraph (i). Particulate limits for Units 4 
and 5 shall be effective 180 days after re-start of the units after 
installation of the SCR controls.
    (1) Particulate Matter for units 1, 2, and 3 shall be limited to 
0.012 lb/MMBtu for each unit as measured by the average of 3 test runs 
with each run collecting a minimum of 60 dscf of sample gas and with a 
duration of at least 120 minutes. Sampling shall be performed according 
to 40 CFR Part 60 Appendices A-1 through A-3, Methods 1 through 4 and 
Method 5 or Method 5e. The averaging time for any other demonstration 
of the Particulate Matter compliance or exceedence shall be

[[Page 64235]]

based on a 6 hour average. Particulate testing shall be performed 
annually as required by paragraph (e)(3) of this section. This test 
with 2 hour test runs may be substituted and used to demonstrate 
compliance with the particulate limits in paragraph (d)(2) of this 
section.
    (2) Particulate Matter from units 4 and 5 shall be limited to 0.015 
lb/MMbtu for each unit as measured by the average of 3 test runs with 
each run collecting a minimum of 60 dscf of sample gas and with a 
duration of at least 120 minutes. Sampling shall be performed according 
to 40 CFR Part 60 Appendices A-1 through A-3, Methods 1 through 4 and 
Method 5 or Method 5e. The averaging time for any other demonstration 
of the particulate matter compliance or exceedence shall be based on a 
6 hour average.
    (3) No owner or operator shall discharge or cause the discharge of 
emissions from the stacks of Units 1, 2, 3, 4 or 5 into the atmosphere 
exhibiting greater than 10% opacity, excluding uncombined water 
droplets, averaged over any six (6) minute period.
    (4) Plantwide nitrogen oxide emission limits.
    (i) The plantwide nitrogen oxide limit, expressed as nitrogen 
dioxide, shall be 0.11 lb/MMbtu as averaged over a rolling 30 calendar 
day period. NO<INF>2</INF> emissions for each calendar day shall be 
determined by summing the hourly emissions measured in pounds of 
NO<INF>2</INF> for all operating units. Heat input for each calendar 
day shall be determined by adding together all hourly heat inputs, in 
millions of BTU, for all operating units. Each day the thirty day 
rolling average shall be determined by adding together that day and the 
preceding 29 days pounds of NO<INF>2</INF> and dividing that total 
pounds of NO<INF>2</INF> by the sum of the heat input during the same 
30 day period. The results shall be the 30 day rolling pound per 
million BTU emissions of NO<INF>X</INF>.
    (ii) The interim NO<INF>X</INF> limit for each individual boiler 
with SCR control shall be as follows:
    (A) Unit 1 shall meet a rolling 30 calendar day NO<INF>X</INF> 
limit of 0.21 lb/MMBtu,
    (B) Unit 2 shall meet a rolling 30 calendar day limit of 0.17 lb/
MMBtu,
    (C) Unit 3 shall meet a rolling 30 calendar day limit of 0.16 lb/
MMBtu,
    (D) Units 4 and 5 shall meet a rolling 30 calendar day limit of 
0.11 lb/MMBtu, each.
    (iii) Testing and monitoring shall use the 40 CFR part 75 monitors 
and meet the 40 CFR part 75 quality assurance requirements. In addition 
to these 40 CFR part 75 requirements, relative accuracy test audits 
shall be performed for both the NO<INF>2</INF> pounds per hour 
measurement and the heat input measurement. These shall have relative 
accuracies of less than 20%. This testing shall be evaluated each time 
the 40 CFR part 75 monitors undergo relative accuracy testing.
    (iv) If a valid NO<INF>X</INF> pounds per hour or heat input is not 
available for any hour for a unit, that heat input and NO<INF>X</INF> 
pounds per hour shall not be used in the calculation of the 30 day 
plant wide rolling average.
    (v) Upon the effective date of the plantwide NO<INF>X</INF> 
average, the owner or operator shall have installed CEMS and COMS 
software that complies with the requirements of this section.
    (j) Dust. Each owner or operator shall operate and maintain the 
existing dust suppression methods for controlling dust from the coal 
handling and ash handling and storage facilities. Within ninety (90) 
days after promulgation of this paragraph (j), the owner or operator 
shall develop a dust control plan and submit the plan to the Regional 
Administrator. The owner or operator shall comply with the plan once 
the plan is submitted to the Regional Administrator. The owner or 
operator shall amend the plan as requested or needed. The plan shall 
include a description of the dust suppression methods for controlling 
dust from the coal handling and storage facilities, ash handling, 
storage and landfilling, and road sweeping activities. Within 18 months 
of promulgation of this paragraph (j) each owner or operator shall not 
emit dust with opacity greater than 20 percent from any crusher, 
grinding mill, screening operation, belt conveyor, or truck loading or 
unloading operation.

[FR Doc. 2010-26262 Filed 10-18-10; 8:45 am]
BILLING CODE 6560-50-P


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