Vol. 78 Tuesday, 

No. 24 February 5, 2013 

Part III 

Environmental Protection Agency 

40 CFR Part 49 

Approval of Air Quality Implementation Plans; Navajo Nation; Regional 

Haze Requirements for Navajo Generating Station; Proposed Rule 


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8274 Federal Register / Vol. 78, No. 24 / Tuesday, February 5, 2013 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 49 

[EPA–R09–OAR–2013–0009; FRL–9774–1] 

Approval of Air Quality Implementation 

Plans; Navajo Nation; Regional Haze 

Requirements for Navajo Generating 

Station 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: The Environmental Protection 

Agency (EPA) is proposing a sourcespecific federal implementation plan 

(FIP) requiring the Navajo Generating 

Station (NGS), located on the Navajo 

Nation, to reduce emissions of oxides of 

nitrogen (NOX) under the Best Available 

Retrofit Technology (BART) provision of 

the Clean Air Act (CAA or Act) in order 

to reduce visibility impairment resulting 

from NGS at 11 National Parks and 

Wilderness Areas. NGS, which was built 

over 35 years ago, is the largest coalfired power plant in the West in terms 

of generating capacity. It is central to the 

economies of the Navajo Nation and 

Hopi Tribe and supplies power to the 

states of Arizona, Nevada, and 

California. Electricity produced by NGS 

is also used to power the Central 

Arizona Project, which supplies surface 

water to three counties and numerous 

Indian tribes in Arizona. NGS is 

projected to continue operating at least 

until 2044. EPA is proposing to require 

NGS to achieve a nearly 80 percent 

reduction of its current overall NOX

emission rate. Our analysis indicates 

that installation of controls to achieve 

this reduction would result in 

significant visibility improvement that 

is well-balanced with the cost of those 

controls. For a number of reasons, 

including the importance of NGS to 

numerous Indian tribes located in 

Arizona and the federal government’s 

reliance on NGS to meet the 

requirements of water settlements with 

several tribes, EPA is proposing an 

alternative to BART that would provide 

flexibility to NGS in the schedule for the 

installation of new control equipment. 

We also describe other compliance 

schedules for consideration and 

comment. We recognize that there may 

be other approaches that could result in 

equivalent or better visibility benefits 

over time and that there may be changes 

in energy demand, supply or other 

developments over the next several 

decades that may change electricity 

generation on the Navajo Nation. EPA 

encourages a robust public discussion of 

our proposed BART determination and 

alternative, the additional alternatives 

described herein, and other possible 

approaches. EPA is prepared to issue a 

supplemental proposal if approaches 

other than the proposed BART 

determination or proposed alternative 

articulated in this notice are identified 

as satisfying the requirements of the 

Clean Air Act and meeting the needs of 

the stakeholders. EPA is committed to 

continuing to engage with stakeholders 

to develop a final FIP that maintains 

benefits to tribes and the regional 

economy while improving visibility in 

many of our nation’s most treasured 

National Parks and Wilderness Areas. 

DATES: Comments must be submitted no 

later than May 6, 2013. 

ADDRESSES: Submit comments, 

identified by docket number EPA–R09– 

OAR–2013–0009, by one of the 

following methods: 

Federal eRulemaking Portal: 

www.regulations.gov. Follow the on-line 

instructions. 

Email: r9ngsbart@epa.gov. 

Mail or deliver: Anita Lee (Air-2), U.S. 

Environmental Protection Agency 

Region 9, 75 Hawthorne Street, San 

Francisco, CA 94105–3901. 

Instructions: All comments will be 

included in the public docket without 

change and may be made available 

online at www.regulations.gov, 

including any personal information 

provided, unless the comment includes 

Confidential Business Information (CBI) 

or other information whose disclosure is 

restricted by statute. Information that 

you consider CBI or otherwise protected 

should be clearly identified as such and 

should not be submitted through 

www.regulations.gov or email. 

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 an email 

directly to EPA, your email 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 to accept oral and written 

comments on the proposed rulemaking. 

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 

www.regulations.gov and in hard copy 

at EPA Region 9, 75 Hawthorne Street, 

San Francisco, California. While 

documents in the docket are listed in 

the index, some information may be 

publicly available only at EPA Region 9 

(e.g., maps, voluminous reports, 

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 9, (415) 972– 

3958, r9ngsbart@epa.gov. 

SUPPLEMENTARY INFORMATION: 

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

and ‘‘our’’ refer to EPA. 

Table of Contents 

I. Background 

A. Navajo Generating Station 

B. Significance of NGS and Federal 

Collaboration 

C. Statutory and Regulatory Framework for 

Addressing Visibility 

D. Statutory and Regulatory Framework for 

Addressing Sources Located in Indian 

Country 

E. Statutory and Regulatory Framework for 

BART Determinations 

F. Relationship of Air Pollutants to 

Visibility Impairment 

G. EPA’s Advanced Notice of Proposed 

Rulemaking 

i. Information from Tribes 

ii. Information from NGS Owners 

iii. Comments from Other Stakeholders 

iv. Involvement of Other Federal Agencies 

II. EPA’s Proposed Action 

A. A NOX BART Determination for NGS Is 

‘‘Necessary or Appropriate’’ 

B. Available and Feasible Control 

Technologies and Five Factor Analysis 

for NOX Emissions 

i. Factor 1: Cost of Compliance 

ii. Factor 2: Energy and Non-Air Quality 

Impacts 

a. Affordability Analysis 

b. Electricity and Water Rate Analysis 

c. Summary of EPA’s Affordability and 

Rate Impacts Analyses 

iii. Factor 3: Existing Controls at the 

Facility 

iv. Factor 4: Remaining Useful Life of 

Facility 

v. Factor 5: Degree of Visibility 

Improvement 

C. EPA’s Proposed NOX Emission Limit for 

NGS 

D. EPA’s Proposed BART Alternative 

i. Compliance Flexibility Is Necessary or 

Appropriate 

ii. Background on Alternative Measures to 

BART 

iii. Legal Rationale for Extending 

Compliance Schedule for Alternative 

Measures for NGS 

iv. Description and Analysis of a Proposed 

Alternative Measure to BART 

E. Analysis of Additional Alternative 

Compliance Schedules 

F. Solicitation of Comments 

III. Administrative Requirements 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 


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1See document titled ‘‘Grand Canyon Annual 

Visitation.pdf’’ in the docket for this proposed 

rulemaking, available through https://irma.nps.gov/ 

Stats/. 

2See information on the Central Arizona Project 

at http://www.usbr.gov/projects/ 

Project.jsp?proj_Name=Central+Arizona+Project. 

See also report by the National Renewable Energy 

Lab (NREL), discussed in more detail in Section 

G.iii of this notice, titled ‘‘Navajo Generating 

Station and Air Visibility Regulations: Alternatives 

and Impacts’’, revision dated March 2012 (NREL 

report) in the docket for this proposed rulemaking. 

3See Section titled ‘‘Welcome’’ on CAP 

homepage: http://www.cap-az.com/ 

4See, for example, Section 4 of the NREL report 

and Comments from the Central Arizona Water 

Conservation District on the NREL report to DOI 

and EPA dated February 23, 201[2], in the docket 

for this proposed rulemaking. 

5See, for example, Section 6 of the NREL report. 

6 Id. 

7 Id. 

Order 13563: Improving Regulation and 

Regulatory Review 13563B. 

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 

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. Navajo Generating Station 

The Navajo Generating Station (NGS) 

is a coal-fired power plant located on 

the Navajo Nation Indian Reservation, 

just east of Page, Arizona, 

approximately 135 miles north of 

Flagstaff, Arizona. The three 750 MW 

units at NGS were constructed over 

1974—1976. At a capacity of 2250 MW, 

NGS is the largest coal-fired power plant 

in the western United States. 

NGS is located near many of our most 

treasured National Parks and 

Wilderness Areas. Congress mandated 

heightened protection for these areas in 

designating them as mandatory Class I 

Federal areas. Eleven Class I areas are 

located within 300 km of NGS: Arches 

National Park (NP), Bryce Canyon NP, 

Canyonlands NP, Capitol Reef NP, 

Grand Canyon NP, Mazatzal Wilderness 

Area (WA), Mesa Verde NP, Petrified 

Forest NP, Pine Mountain WA, 

Sycamore Canyon WA, and Zion NP. 

These areas support an active tourism 

industry drawing over 4 million visitors 

to the Grand Canyon National Park 

alone in 2011.1 In addition to EPA’s role 

implementing the Regional Haze 

program, the Federal Land Managers of 

these areas, the National Park Service 

and the U.S. Fish and Wildlife Service, 

under the Department of the Interior, 

and the U.S. Forest Service, under the 

Department of Agriculture, also play 

important roles in the protection of 

visibility in the mandatory Class I 

Federal areas. 

NGS is co-owned by six entities: The 

U.S. Bureau of Reclamation 

(Reclamation)—24.3 percent, Salt River 

Project (SRP), which also acts as the 

facility operator—21.7 percent, Los 

Angeles Department of Water and Power 

(LADWP)—21.2 percent, Arizona Public 

Service (APS)—14 percent, Nevada 

Power Company (NPC)—11.3 percent, 

and Tucson Electric Power (TEP)—7.5 

percent. NGS uses hot-side electrostatic 

precipitators (hot-side ESPs) to control 

emissions of particulate matter (PM) and 

flue gas desulfurization units (FGDs) to 

control emissions of sulfur dioxide 

(SO2). Over the 2009—2011 period, the 

owners of NGS voluntarily installed 

modern low-NOX burners with 

separated over-fire air (LNB/SOFA) to 

reduce emissions of NOX. 

B. Significance of NGS and Federal 

Collaboration 

Federal participation in NGS was 

authorized in the Colorado River Basin 

Project Act of 1968 as a preferred 

alternative to building hydroelectric 

dams in the Grand Canyon for providing 

power to the Central Arizona Project.2

The Central Arizona Project (CAP) is a 

336-mile water distribution system that 

delivers about 1.5 million acre-feet (AF) 

per year of Colorado River water from 

Lake Havasu in western Arizona to nontribal agricultural water users in central 

Arizona, Indian tribes located in 

Arizona, and municipal water users in 

Maricopa, Pinal, and Pima counties.3

This CAP water is used to meet the 

terms of a number of Indian water rights 

settlements in central Arizona and to 

reduce groundwater usage in the 

region.4 Electricity from NGS powers 

the pumps that move CAP water to its 

destinations along the distribution 

system. 

Several tribes located in Arizona have 

allocations of CAP water through water 

settlement agreements that have been 

approved through acts of Congress.5 In 

exchange for allocations of CAP water at 

reduced cost and access to funds for the 

development of water infrastructure, 

these tribes have released their claims to 

other water in Arizona. Excess NGS 

power owned by Reclamation that is not 

used by CAP is sold and profits are 

deposited into a fund to support the 

tribal water settlement agreements.6 The 

Department of the Interior (through the 

Bureau of Reclamation) plays an 

important role in the implementation of 

these settlement agreements and the 

management of the funds set aside for 

water infrastructure development for 

tribes. 

The coal used by NGS is supplied by 

the Kayenta Mine, operated by Peabody 

Energy and located on reservation lands 

of both the Navajo Nation and the Hopi 

Tribe. Taxes and royalties from NGS 

and the Kayenta Mine paid to the 

Navajo Nation and Hopi Tribe 

contribute significantly to the annual 

revenues for both governments.7

C. Statutory and Regulatory Framework 

for Addressing Visibility 

Part C, subpart II, of title I of the CAA 

as amended in 1977 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 was 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: Grand Canyon NP in 

Arizona (40 CFR 81.403); Mesa Verde 

NP in Colorado (Id. 81.406); and Arches, 

Bryce Canyon, Canyonlands, Capitol 

Reef, and Zion NP in Utah (Id. 81.430). 

These mandatory Class I Federal areas 

are among the 11 Class I areas within an 

approximately 300 km radius of NGS. 

On December 2, 1980, EPA 

promulgated the first phase of the 

required visibility regulations 

addressing visibility impairment that is 

reasonably attributable to a single 

source or a small group of sources, 

codified at 40 CFR 51.300–307. 45 FR 

80084. The 1980 regulations deferred 

regulating regional haze (i.e., 

widespread haze from a multitude of 

sources which impairs visibility in 

every direction over a large area), based 


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8Protecting Visibility in National Parks and 

Wilderness Areas, Committee on Haze in National 

Parks and Wilderness Areas, National Research 

Council, National Academy Press (1993). Available 

through: http://www.nap.edu/ 

openbook.php?record_id=2097&page=R2 

on a 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.’’ 8

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 (RHR) include a provision 

that states must 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. These 

five factors are the cost of controls, the 

energy and non-air quality impacts of 

controls, the existing controls at the 

source, the remaining useful life of the 

source, and the anticipated visibility 

benefits of controls. The CAA and RHR 

require BART to be installed and 

operated as expeditiously as practicable, 

but in no event later than five years 

from the date of the approved plan. 42 

U.S.C 7491(b)(2)(A), 42 U.S.C 

7491(g)(4), and 40 CFR 51.308(e)(1)(iv). 

EPA made revisions to the RHR after 

1999 and those revisions together with 

the RHR are codified at 40 CFR Part 51, 

Subpart P and Appendix Y. The 

regulations allow EPA to promulgate an 

alternative to BART provided the 

alternative results in greater reasonable 

progress than will result from 

installation and operation of BART. 40 

CFR 51.308(e)(2). 

D. Statutory and Regulatory Framework 

for Addressing Sources Located in 

Indian Country 

When the CAA was amended in 1990, 

Congress included a new provision, 

Section 301(d), granting EPA authority 

to treat Indian 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 may, but are not 

required to administer air programs 

under the CAA, were in the early stages 

of developing air planning programs 

known as Tribal Implementation Plans 

(TIPs) and would need additional time 

to develop air quality programs. 63 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 43964–65; 63 FR 7264–65. Similarly, 

EPA determined that it would be 

inappropriate to treat tribes in the same 

manner 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. In particular, EPA found 

that it was inappropriate to treat tribes 

in the same manner as states for the 

purposes of Section 110(c)(1), which 

requires EPA to promulgate a FIP within 

2 years after a state fails to make a 

required plan submission. 

Although EPA determined that it was 

inappropriate to treat tribes in the same 

manner as states for the purposes of 

Section 110(c)(1), 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 so as to achieve the 

appropriate purpose. 40 CFR 49.11. See 

also 63 FR 7265. Specifically, 40 CFR 

49.11(a) provides that EPA: 

[s]hall promulgate without unreasonable 

delay such Federal implementation plan 

provisions as are necessary or appropriate to 

protect air quality, consistent with the 

provisions of sections 30[1](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. 

As described in detail below, EPA has 

previously promulgated FIPs to regulate 

air pollutants emitted from the two coalfired electric generating facilities on the 

Navajo Nation, Four Corners Power 

Plant (FCPP) and NGS. In 1991, prior to 

the promulgation of the TAR, EPA 

revised an existing FIP that applied to 

Arizona to include a requirement for 

NGS to substantially reduce its SO2

emissions by installing scrubbers, based 

on a finding that the SO2 emissions 

were contributing to visibility 

impairment at the Grand Canyon 

National Park. 56 FR 50172 (October 3, 

1991); see also Central Arizona Water 

Conservation District v. United States 

Environmental Protection Agency, 990 

F.2d 1531 (9th Cir. 1993)(upholding 

EPA’s promulgation of the FIP). Then, 

in 1999, EPA proposed a FIP for NGS to 

fill the regulatory gap that existed 

because SIP rules issued by Arizona to 

regulate NGS were not applicable or 

enforceable on the Navajo Nation, and 

the Tribe had not sought approval of a 

TIP covering the plant. 64 FR 48731 

(September 8, 1999). EPA did not 

finalize the 1999 proposal and proposed 

a new FIP for NGS on September 12, 

2006. 71 FR 53631. EPA finalized the 

NGS FIP in 2010 generally making the 

emission limits from the Arizona SIP 


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9 In the 2010 NGS FIP, EPA finalized federally 

enforceable emission limits for SO2, particulate 

matter (PM), and opacity, and control measures for 

dust for NGS. The 2010 FIP lowered the opacity 

limit from 40 percent to 20 percent and included 

requirements to control emissions associated with 

coal and ash handling and storage. 

10Protecting Visibility in National Parks and 

Wilderness Areas, Committee on Haze in National 

Parks and Wilderness Areas, National Research 

Council, National Academy Press (1993). 

11EPA has taken final action on our BART 

determination for the Four Corners Power Plant. 

See 77 FR 51620 dated August 24, 2012. 

rules for NGS federally enforceable, 

with one modification.9 75 FR 10174 

(March 5, 2010). The 2010 NGS FIP was 

promulgated under the authority in the 

CAA and 40 CFR 49.11(a) that underlies 

our proposal today. 

Because the Arizona SIP did not 

contain any NOX emission limits for 

NGS, the final 2010 FIP did not impose 

any limits on NOX. However, NGS is 

subject to the federal Acid Rain Program 

requirements under title IV of the Clean 

Air Act. NGS elected to comply early as 

a Phase I NOX facility subject to a NOX

limit of 0.40 lb/MMBtu, per unit, on an 

annual basis. Over the 2009—2011 

timeframe, the owners of NGS 

voluntarily installed new LNB/SOFA at 

NGS, with a NOX emission limit of 0.24 

lb/MMBtu. 

E. Statutory and Regulatory Framework 

for BART Determinations 

When Congress enacted Section 169A 

of the CAA in 1977 to protect visibility, 

it directed EPA to promulgate 

regulations that would require 

applicable implementation plans to 

include a determination of BART for 

certain major stationary sources that are 

‘‘reasonably anticipated to cause or 

contribute to any impairment of 

visibility in any [Class I area]’’. 42 

U.S.C. 7491(b)(2)(A) & (g). A source is 

BART-eligible if it is a fossil fuel-fired 

steam electric plant of more than 250 

MMBtu/hr heat input or other listed 

industrial source that has the potential 

to emit 250 tons or more of any 

visibility-impairing pollutant and that 

came into operation between 1962 and 

1977. Id. NGS meets these criteria and 

is a BART-eligible source. 

A BART-eligible source with a 

predicted visibility impact of 0.5 

deciviews (dv) or more in a Class I area 

‘‘contributes’’ to visibility impairment 

and is subject to BART. See 70 FR at 

39161 (July 6, 2005). NGS contributes to 

visibility impairment at 11 surrounding 

Class I areas in excess of this threshold, 

and is thus subject to 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. Those factors 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). EPA’s guidelines for 

evaluating BART are set forth in 

Appendix Y to 40 CFR Part 51, referred 

to as the BART Guidelines, and must be 

followed in making BART 

determinations for fossil fuel-fired 

electric generating plants larger than 

750 MW. 

F. Relationship of Air Pollutants to 

Visibility Impairment 

Emissions of NOX contribute to the 

formation of particulate matter (PM), 

which, in turn, interacts with light to 

impair visibility. The fundamental 

science of haze formation and visibility 

impairment is described in greater detail 

in a comprehensive study by National 

Research Council.10

Briefly, the smallest particles in the 

0.1 to 1 micron range interact with light 

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. 

Boiler stacks and material handling 

are sources of primary PM, or PM 

emitted directly into the atmosphere. Of 

primary PM emissions, those in the 

smaller particle size range, less than 2.5 

microns, tend to have the largest impact 

on visibility. PM emissions from boiler 

stacks can have varying particle size 

makeup depending on the PM control 

technology. PM from material handling, 

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

10 microns, because it is created from 

the breakup of larger particles of coal, 

soil, and rock. 

PM that is formed in the atmosphere 

from the photochemical transformation 

and condensation of gaseous chemical 

pollutants, also called secondary PM, 

tends to be fine, i.e., smaller than 1 

micron, because 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 that 

most effectively interacts with visible 

light. NOX and SO2 emissions from coalfired power plants are examples of 

gaseous chemical pollutants that react 

with other compounds in the 

atmosphere to form secondary PM. 

NOX is a gaseous pollutant that can be 

oxidized to form nitric acid. In the 

atmosphere, nitric acid in the presence 

of ammonia forms particulate 

ammonium nitrate. The formation of 

particulate ammonium nitrate depends 

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. 

G. EPA’s Advanced Notice of Proposed 

Rulemaking 

On August 28, 2009, EPA published 

an Advanced Notice of Proposed 

Rulemaking (ANPRM) regarding EPA’s 

intention to implement the BART 

requirement of the RHR for the two 

subject-to-BART coal-fired power plants 

located on the Navajo Nation, the Four 

Corners Power Plant 11 and the Navajo 

Generating Station. 74 FR 44313. In that 

ANPRM, EPA put forth our analysis of 

the cost and anticipated visibility 

benefits comparing selective catalytic 

reduction (SCR) and modern 

combustion controls for both power 

plants and requested comment. The 

ANPRM marked the beginning of an 

ongoing process of consultation with 

tribes and discussions with other key 

stakeholders on the issue of NOX control 

at FCPP and NGS. EPA received over 

6,000 comments on the ANPRM, most of 

which were identical electronic mail 

messages in support of requiring 

stringent air pollution controls at NGS. 

Comments from tribes located in 

Arizona, the owners of NGS, other 

stakeholders, and other federal agencies 

are discussed briefly below, and 

described in more detail in the TSD for 

this proposed rulemaking. 

i. Information from Tribes 

EPA received numerous comments on 

the ANPRM from tribes and tribal 

organizations, including the Navajo 

Nation, Hopi Tribe, Gila River Indian 

Community, Ak-Chin Indian 

Community, Tohono O’odham Nation, 

Pascua Yaqui Tribe, Fort McDowell 

Yavapai Nation, Yavapai-Apache 

Nation, and the Inter Tribal Council of 

Arizona. Comments from the Navajo 

Nation and Hopi Tribe focused on the 

significant contribution of coal-related 

royalties, taxes, and employment at NGS 

and the Kayenta Mine to the economies 

of the Navajo Nation and the Hopi 

Tribe. Comments from the Gila River 

Indian Community, the Tohono 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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12See document titled ‘‘Timeline of All Tribal 

Consultations on NGS.docx’’ in the docket for this 

proposed rulemaking. 

13See March 12, 2012 letter from four owners of 

NGS to EPA regarding Pending BART 

Determination for Navajo Generating Station, in the 

docket for this proposed rulemaking. 

14See information on SB 1368 Emission 

Performance Standards at http:// 

www.energy.ca.gov/emission_standards/ 

15See, for example, 2012 Draft Integrated 

Resource Plan Executive Summary available at 

https://www.ladwp.com/ladwp/faces/ 

wcnav_externalId/a-p-doc?_adf.ctrlstate=a8ti68apu_29&_afrLoop=234058941927000, 

or in the docket for this proposed rulemaking. 

16 Information in Table 1 is based on Table 1–3 

on page 13 of the NREL report. 

17 Id. 

18See email and attachment from Letty Belin, DOI 

to Janet McCabe, EPA, dated August 20, 2012, in the 

docket for this proposed rulemaking. 

19See Docket #: EPA–R09–OAR–2009–0598 on 

www.regulations.gov. 

O’odham Nation, and other tribes 

located in Arizona focused on the 

importance of continued operation of 

NGS as a source of power to the Central 

Arizona Water Conservation District 

(CAWCD), the operating arm of CAP, in 

order for the federal government to meet 

obligations under existing water 

settlement agreements. The importance 

to tribes of continued operation of NGS 

and affordable water costs cannot be 

overemphasized. Detailed discussions of 

tribal interests in NGS, including 

studies submitted by the Hopi Tribe and 

the Gila River Indian Community, are 

provided in the TSD for this proposed 

rulemaking. 

EPA has met with tribes on numerous 

occasions to discuss the significance of 

NGS to tribal economies and tribal 

water interests in Arizona.12

Consultations with tribes included 

potential economic impacts associated 

with a BART determination for NGS, as 

well as potential impacts from EPA’s 

Mercury and Air Toxics Standards 

(MATS) rulemaking. 

In recognition of the unusual 

complexity of regulating NGS, 

representatives from EPA, including the 

Assistant Administrator and the Deputy 

Assistant Administrator for the Office of 

Air and Radiation and the Regional 

Administrator for Region 9, visited NGS 

and affected communities in the area. 

EPA officials have also met with 

additional stakeholders, at various 

locations, including EPA offices in San 

Francisco, California and Washington, 

DC, and offices of individual tribal 

governing councils and the Inter Tribal 

Council of Arizona. 

ii. Information from NGS Owners 

SRP, operator and part-owner of NGS, 

provided information to EPA outlining 

several uncertainties that significantly 

increase the financial risk of near-term 

investments in new air pollution 

controls, including uncertainties in 

plant ownership and lease 

agreements.13

One of the owners of NGS is the Los 

Angeles Department of Water and Power 

(LADWP), a public utility located in 

California. Under California law (Senate 

Bill 1368),14 long-term investments in 

base load generation by California 

utilities must meet a carbon dioxide 

emission performance standard based 

on a combined cycle natural gas-fired 

base load power plant. NGS and other 

traditional coal-fired power plants that 

operate without carbon capture and 

sequestration do not meet this standard. 

Therefore, LADWP will be prohibited 

from continued participation and longterm investments in NGS beyond its 

current contract term of 2019. As a 

result, LADWP has indicated its 

intention to sell its 21.2 percent 

ownership stake in NGS. The future 

owner of LADWP’s share of NGS is 

currently uncertain.15

In addition, NGS’s current site lease 

with the Navajo Nation, as well as 

several other agreements and contracts, 

expire in 2019. Table 1 lists several 

leases, agreements, and contracts that 

must be renewed to ensure continued 

operation of NGS into the future.16

Although the owners of NGS are in 

negotiations with the Navajo Nation for 

a lease renewal to extend to 2044 and 

with Peabody Energy for a renewed coal 

supply contract, the outcomes of these 

negotiations are also not yet finalized. 

TABLE 1—LEASES, AGREEMENTS, AND

CONTRACT RENEWALS FOR NGS 

AND KAYENTA MINE

Description Renewal 

year 

Peabody Lease Renewal with Navajo Nation and Hopi Tribe ........... 2017 

Coal Supply Contract between 

Peabody and NGS ...................... 2019 

NGS Project Lease Renewal with 

Navajo Nation (Federal Rights of 

Way) ............................................ 2019 

Water Intake/Water Line Renewal 

(Federal Rights of Way) .............. 2019 

Railroad and Transmission Line 

Renewals (Federal Rights of 

Way) ............................................ 2021 

Southern Transmission Line Easement (Federal Rights of Way) .... 2022 

Because NGS is located in Indian 

country, lease and other rights-of-way 

agreement renewals must be approved 

by the Department of the Interior. These 

approvals, which are an unusual 

requirement for continued operation of 

a power plant, are federal actions that 

trigger review under the National 

Environmental Protection Act (NEPA).17

For actions significantly affecting the 

environment, NEPA review requires the 

development of an Environmental 

Impact Statement (EIS) and includes a 

substantial process for public 

involvement. The Department of the 

Interior estimates that NEPA review for 

approval of leases and other rights-ofway agreements may require 

approximately five years to complete.18

Therefore, even if the Navajo Nation and 

the owners of NGS reach agreement on 

renewed leases and other rights-of-way 

shortly, the owners of NGS may not 

have a lease fully approved by the 

Department of the Interior until 2019 or 

later. 

iii. Comments from Other Stakeholders 

In addition to the identical electronic 

mail messages from private citizens, 

EPA received general comments, both in 

support of and in opposition to stringent 

air pollution controls at NGS, from 

numerous individuals, state and local 

agencies, industry, utility and water 

groups, environmental and communitybased organizations, cities and 

municipalities in Arizona, U.S. and 

State Representatives, and the Governor 

and Treasurer of Arizona. All comments 

received on the ANPRM are available in 

the ANPRM docket.19

Several groups provided separate 

comment letters on the five-factor BART 

analysis discussed in the ANPRM, 

including the Arizona Department of 

Environmental Quality, the Utility Air 

Research Group, and a consortium of 

environmental and Navajo community 

organizations. The Colorado Department 

of Public Health and the Environment 

and the Attorney General of New 

Mexico submitted separate comments 

on potential co-benefits to mercury 

reduction resulting from certain NOX

controls. Numerous groups and 

individuals, including elected officials 

in Arizona, stressed the importance of 

NGS to the Arizona economy and raised 

concerns that a stringent BART 

determination such as SCR might force 

closure of NGS or otherwise result in 

economic harm to cities, tribes, and 

agricultural water users in Arizona. 

Other commenters stressed the 

importance of reducing the plant’s 

contribution to regional haze. EPA 

discusses comments, both in support of 

and in opposition to stringent controls 

at NGS, in more detail in the TSD for 

this proposed rulemaking. 


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20See ‘‘March 2012 Revision to NREL 

Report.pdf’’ and ‘‘Comments on NREL Report.pdf’’ 

in the docket for this proposed rulemaking. 

21See June 2012 report by NREL titled ‘‘Navajo 

Generating Station and Clean-Energy Alternatives: 

Options for Renewables’’ in the docket for this 

proposed rulemaking. 

22See Joint Federal Agency Statement Regarding 

Navajo Generating Station, dated January 4, 2013, 

in the docket for this proposed rulemaking. 

23See Navajo National Monument: A Place and 

its People, An Administrative History, Hal K. 

Rothman, 1991, National Park Service, Chapter IV: 

‘‘Land-Bound:’’ 1938–1962, available at: http:// 

www.nps.gov/history/history/online_books/nava/ 

adhi/adhi4e.htm. 

24Air Quality in National Parks, 2008 Annual 

Performance & Progress Report, National Resource 

Report NPS/NRPC/ARD/NRR—2009/151, 

September 2009, p. 30, in the docket for this 

proposed rulemaking. 

25 Id. Appendix B. Note that the other three 

mandatory Class I Federal areas located within 300 

km of NGS are Wilderness Areas that are managed 

by the U.S. Forest Service. 

26See 56 FR 50172 (October 3, 1991) and 75 FR 

10174 (March 5, 2010). 

iv. Involvement of Other Federal 

Agencies 

Following the ANPRM, EPA received 

comments from other federal agencies 

that have authority to oversee interests 

and activities related to NGS. The 

Bureau of Reclamation, under the 

Department of the Interior, is a partowner of NGS. However, Reclamation 

and four additional Interior agencies 

(National Park Service, Bureau of Indian 

Affairs, Office of Surface Mining, and 

U.S. Fish and Wildlife Service) also 

have regulatory authorities relating to 

NGS or the Kayenta coal mine that 

serves it. The U.S. Forest Service, an 

agency within the Department of 

Agriculture, has authority to protect 

visibility in the Class I areas in its 

jurisdiction. EPA has Clean Air Act 

authority to maintain air quality and 

improve visibility. The Department of 

Energy (DOE) Office of Energy 

Efficiency and Renewable Energy, Office 

of Indian Energy Policy and Programs, 

and National Laboratories have 

technical expertise and other resources 

related to clean energy development and 

production in Indian country. 

In 2011, DOI entered into an 

interagency agreement with DOE to 

commission the National Renewable 

Energy Laboratory (NREL) to conduct a 

study with the goal of providing an 

objective assessment of issues related to 

the power sector that are important for 

understanding the potential impacts on 

power and water rates of BART options 

for NGS. Under phase 1 of an intended 

two-phase study, NREL conducted an 

analysis focusing on the potential effects 

from costs associated with NOX control 

options or NGS closure. NREL 

completed the first part of its study in 

January 2012 and provided public 

comments it received on the study to 

EPA in March 2012.20 In June 2012, 

NREL completed a final chapter as part 

of its phase 1 study that provides a highlevel examination of alternatives to 

NGS.21

Given the extent of federal and tribal 

interests in NGS, on January 4, 2013, 

EPA, DOI, and DOE signed a joint 

federal agency statement committing to 

collaborate on several short- and longterm goals, including analyzing and 

pursuing strategies for providing clean, 

affordable and reliable power, affordable 

and sustainable water, and sustainable 

economic development to key 

stakeholders who currently depend on 

NGS.22 The agencies will work together 

with stakeholders to identify and 

undertake actions that support 

implementation of BART, including 

seeking funding to cover expenses for 

pollution control or other necessary 

upgrades for the federal portion of NGS. 

The agencies will also work to jointly 

support a phase 2 report to analyze a 

full range of clean energy options for 

NGS over the next decades and work 

with stakeholders to develop a roadmap 

for achieving long-term, innovative 

clean energy solutions for NGS. This 

collaboration may span several years 

and EPA expects alternative strategies 

resulting from the collaboration may 

contribute to reductions in NOX

emissions at NGS. 

II. EPA’s Proposed Action 

A. A NOX BART Determination for NGS 

Is ‘‘Necessary or Appropriate’’ 

The numerous Class I areas that 

surround NGS are sometimes known as 

the Golden Circle of National Parks.23

Millions of tourists visit these areas, 

many visiting from other countries, to 

view the unique vistas of the Class I 

areas in this region. 

As Congress recognized, visibility is 

an important value and must be 

protected in these areas. Currently, air 

quality and visibility are impaired in the 

Class I areas surrounding NGS. 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 natural conditions in many 

places, particularly on the haziest 

days.’’ 24 Of the 11 mandatory Class I 

federal areas located within 300 km of 

NGS, eight national parks, including 

Grand Canyon, Canyonlands, and 

Capitol Reef, are among the areas 

monitored by the National Park 

Service.25 NGS is one of many 

contributors to regional haze in these 

areas and Congress recognized that all 

sources that emit air pollutants that may 

reasonably be anticipated to cause or 

contribute to visibility impairment 

would need to do their part to address 

the problem. 

Because NGS is a subject-to-BART 

source that would undergo a BART 

determination if located on state land, 

and based on the importance of 

visibility in the Golden Circle of 

National Parks, EPA is proposing to find 

that a BART determination for NOX

emissions from NGS is ‘‘necessary or 

appropriate’’ under the TAR. See 40 

CFR 49.11. 

Emissions of PM and SO2 at NGS are 

controlled by hot-side electrostatic 

precipitators (HS–ESPs) and wet 

scrubbers, respectively. EPA finalized 

emission controls and limits for SO2 and 

PM in our FIPs in 1991 and in 2010 (75 

FR 10174). On February 16, 2012, EPA 

finalized the MATS rulemaking that set 

a lower emission limit for PM (77 FR 

9304). The emission limits EPA 

established for SO2 in 1991 were 

determined to achieve greater 

reasonable progress than would 

BART,26 therefore the reasonable 

progress goals of CAA Section 

169A(b)(2) for SO2 at NGS are already 

satisfied. Because emissions of PM are 

well controlled at NGS through 

federally enforceable limits, EPA is not 

proposing that it is ‘‘necessary or 

appropriate’’ under the TAR to 

determine BART for PM emissions at 

NGS. 

B. Available and Feasible Control 

Technologies and Five Factor Analysis 

for NOX Emissions 

Reducing NOX emissions from electric 

generating units generally involves: (1) 

Combustion controls to reduce the 

production of NOX from fuel-bound 

nitrogen and as a by-product of high 

temperature combustion reactions 

between atmospheric nitrogen (N2) and 

oxygen (O2) in the air; or (2) combustion 

controls in combination with postcombustion add-on controls to reduce 

the amount of NOX emitted in flue gas 

by converting NOX to diatomic nitrogen 

(N2) via a catalytic or non-catalytic 

process. 

As discussed in detail in the TSD for 

this proposed rulemaking, SRP 

submitted to EPA a BART analysis in 

2008 and several revisions thereafter. 

SRP identified the following control 

options as technically feasible at NGS 

for reducing NOX emissions: LNB/ 

SOFA, flue gas recirculation (FGR), 

selective non-catalytic reduction 

(SNCR), and selective catalytic 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
8280 Federal Register / Vol. 78, No. 24 / Tuesday, February 5, 2013 / Proposed Rules 

27BART Analysis for the Navajo Generating 

Station Units 1—3, Prepared for Salt River Project— 

Navajo Generating Station by ENSRAECOM, 

Document Number 05830–012–300, dated 

November 2007. 

28See Salt River Project—Navajo Generating 

Station Units 1, 2, 3 SCR and Baghouse Capital Cost 

Estimate Report, Prepared by Sargent and Lundy, 

Project Number 12656–001, August 17, 2010, in the 

docket for this proposed rulemaking. 

29See Updated Best Available Retrofit 

Technology Analysis, Navajo Generating Station, 

from Kelly J. Barr, SRP to Deborah Jordan, EPA 

dated January 20, 2012, in the docket for this 

proposed rulemaking. 

30See letter from Kelly J. Barr, SRP to Deborah 

Jordan, EPA dated July 20, 2012, in the docket for 

this proposed rulemaking. 

31See Updated Best Available Retrofit 

Technology Analysis, Navajo Generating Station, 

from Kelly J. Barr, SRP to Deborah Jordan, EPA, 

dated January 20, 2012, in the docket for this 

proposed rulemaking. 

reduction (SCR).27 The option that 

achieves the largest reduction in NOX

emissions is a combination of 

combustion controls and postcombustion add-on controls, i.e., LNB/ 

SOFA in combination with SCR. 

Although SRP identified FGR as 

technically feasible, it did not conduct 

additional analysis on FGR, based on its 

determination that FGR is less effective 

than LNB/SOFA. 

For the control of NOX emissions, 

EPA has determined that the 

technologies identified by SRP are the 

main technically feasible NOX control 

technologies. For the most stringent 

control option (LNB/SOFA in 

combination with SCR), SRP 

determined that a 2+2 catalyst system 

(four-catalyst layer design with initial 

deployment of two catalyst layers) could 

achieve an emission rate of 

approximately 0.05 lb/MMBtu under 

ideal operating conditions in order to 

ensure compliance with an emission 

limit of 0.07—0.08 lb/MMBtu on a 30- 

day rolling average. SRP suggested that 

the 60 percent compliance margin 

between its intended design target (0.05 

lb/MMBtu) and its suggested NOX

emission limit (0.08 lb/MMBtu) is 

needed to allow for normal operating 

fluctuations associated with minor 

equipment upsets, fuel characteristics 

impacting NOX production, and SCR 

process delays due to load changes. 

As discussed in more detail in the 

TSD for this proposed rulemaking, for 

several reasons, including information 

from a catalyst vendor that an SCR 

system at NGS using three layers of 

catalyst can meet a limit of 0.08 lb/ 

MMBtu and four layers of catalyst can 

meet a limit of 0.05 lb/MMBtu, EPA is 

proposing to determine that Units 1—3 

can meet an emission limit of 0.055 lb/ 

MMBtu using four layers of catalyst. 

EPA expects this proposed emission 

limit of 0.055 lb/MMBtu to provide an 

adequate compliance margin for normal 

fluctuations because compliance will be 

measured on a plant wide rolling 

average basis of 30 boiler operating 

days. EPA understands that Units 1—3 

at NGS currently operate on a 3-year 

outage cycle and that if SCR is installed, 

catalyst replacement would be timed to 

coincide with outage cycles to reduce 

costs. EPA is specifically requesting 

comment on whether NGS can maintain 

its current 3-year outage cycle with four 

layers of catalyst to meet a limit of 0.055 

lb/MMBtu and on the adequacy of the 

margin of compliance provided by the 

limit. 

i. Factor 1: Cost of Compliance 

The cost of compliance is expressed 

as the total capital cost of controls, the 

total annual cost of controls (i.e., annual 

operating costs plus amortized capital 

costs), and the cost effectiveness of 

controls. Cost effectiveness is expressed 

in cost per ton of pollutant reduced ($/ 

ton), and is calculated by dividing the 

total annual cost by the total amount of 

pollutant reduced per year. 40 CFR Part 

51, Appendix Y, IV.D.4.c. 

For this proposed rulemaking, EPA 

evaluated the total capital and total 

annual cost estimates SRP submitted to 

EPA for SCR (excluding additional costs 

for LNB/SOFA) in 2010 against the EPA 

Control Cost Manual.28 EPA has 

generally accepted the total capital and 

total annual cost estimates submitted by 

SRP, except that we have used an 

interest rate that is consistent with EPA 

cost analyses and eliminated three line 

item costs that are not included in the 

EPA Control Cost Manual. The costs 

presented in Table 2 for SCR+LNB/ 

SOFA with four layers of catalyst 

represent EPA’s estimate for SCR+LNB/ 

SOFA at 0.055 lb/MMBtu. The TSD for 

this proposed rulemaking describes our 

analysis and rationale to support our 

revised cost analysis for SCR at NGS, as 

well as our cost analyses for SCR with 

3 layers of catalyst at a level of 0.08 lb/ 

MMBtu. 

In January 2012, SRP provided 

updated cost estimates for SNCR and 

LNB/SOFA.29 EPA did not make any 

revisions to these estimates. Although 

SRP’s 2010 cost estimate for SCR and 

their 2012 cost estimate for SNCR 

excluded the costs of LNB/SOFA, the 

values shown in Table 2 are for 

SCR+LNB/SOFA and SNCR+LNB/ 

SOFA. Between 2008 and 2012, SRP has 

suggested different emission rates 

achievable with SNCR, ranging from 

0.15 lb/MMBtu to 0.20 lb/MMBtu. EPA 

evaluated SNCR+LNB/SOFA at a level 

of 0.18 lb/MMBtu, and LNB/SOFA at a 

level of 0.24 lb/MMBtu. Our evaluation 

of SNCR+LNB/SOFA at 0.18 lb/MMBtu 

is generally consistent with levels 

achieved at NGS during a SNCR 

demonstration test (0.16—0.17 lb/ 

MMBtu), but lower than the emission 

limit of 0.20 lb/MMBtu SRP suggested 

as providing an adequate margin of 

compliance.30

TABLE 2—TOTAL CAPITAL AND TOTAL ANNUAL COSTS OF NOX CONTROLS ON UNITS 1–3 AT NGS 

LNB/SOFA* SNCR+ LNB/ 

SOFA 

SCR+ LNB/ 

SOFA (EPA 

estimate) 

SCR+ LNB/ 

SOFA (SRP 

estimate) 

Total Capital Cost ($ millions) ......................................................................... $45 $84 $541 $589 

Total Annual Costs ..........................................................................................

($ millions) ....................................................................................................... $5 $29 $64 $80 

Annual NOX Reductions Estimated by EPA (tpy) ........................................... 10,865 16,608 28,573 26,180 

* Costs for LNB/SOFA are actual costs expended over 2009—2011. 

Average cost effectiveness and 

incremental cost effectiveness of 

SCR+LNB/SOFA, SNCR+LNB/SOFA, 

and LNB/SOFA are presented in Table 

3. The SRP average and incremental cost 

effectiveness numbers reported in Table 

3 come from SRP and are generally 

based on the assumption that 

SCR+LNB/SOFA would achieve an 

emission limit of 0.08 lb/MMBtu.31 The 

EPA cost effectiveness values in Table 3 

for SCR+LNB/SOFA are based on a NOX

emission limit of 0.055 lb/MMBtu and 

the EPA estimates for total annual cost 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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32See TSD for this proposed rulemaking for a 

discussion of small differences in cost effectiveness 

values for LNB/SOFA and SNCR+LNB/SOFA 

calculated by EPA and SRP, and shown in Table 3. 

33 77 FR 51619 (August 24, 2012). 

34 77 FR 33021 (June 4, 2012). 

35See Colorado Department of Public Health 

BART Determination for Public Service Company— 

Hayden Station, available at http:// 

www.colorado.gov/cs/Satellite/CDPHE-AP/CBON/ 

1251595092457, and in the docket for this proposed 

rulemaking. 

36EPA’s Cost Control Manual does not include 

indirect or ancillary costs such as water rates in the 

evaluation of cost-effectiveness under factor 1. EPA 

is considering those costs under factor 2. 

37 Given the time that will likely be required for 

full public discussion of this proposal, 

consideration of the information submitted during 

the public comment, and the possibility of a 

supplemental proposal following comments we 

receive on Alternatives 2 and 3, it is possible that 

this rule may not be finalized until 2014, in which 

case the timeframe for compliance would also shift, 

from 2018 to 2019. 

in Table 2. EPA did not revise SRP cost 

estimates for LNB/SOFA or SNCR.32

TABLE 3—AVERAGE AND INCREMENTAL COST EFFECTIVENESS FOR NOX CONTROLS ON UNITS 1–3 AT NGS CALCULATED

BY EPA AND SRP 

LNB/SOFA SNCR+LNB/SOFA ($/ton) SCR+LNB/SOFA ($/ton) 

Average Cost Effectiveness (Average for Units 1—3) 

EPA .................................. $486 per ton ...................................... $1,745 per ton ................................... $2,240 per ton. 

SRP .................................. $519 per ton ...................................... $1,481 per ton ................................... $2,926 per ton. 

Incremental Cost Effectiveness (Average for Units 1—3) 

SNCR+LNB/SOFA (vs. LNB/SOFA) SCR+LNB/SOFA (vs. SNCR+LNB/ 

SOFA) 

SCR+LNB/SOFA (vs. LNB/SOFA) 

EPA .................................. $4,110 per ton ................................... $2,933 per ton ................................... $3,315 per ton. 

SRP .................................. $3,135 per ton ................................... $5,282 per ton ................................... Not calculated. 

The average cost effectiveness of 

SCR+LNB/SOFA estimated by EPA is 

not substantially higher than the average 

cost effectiveness of SNCR+LNB/SOFA, 

and the incremental cost effectiveness of 

SCR+LNB/SOFA is lower than 

SNCR+LNB/SOFA (see Table 3). 

The cost effectiveness values 

calculated by both EPA and SRP for 

SCR+LNB/SOFA are lower than or 

within the range of other BART 

evaluations that required SCR. For 

example, BART analyses for other 

electric generating facilities requiring 

SCR had a range of costs: Four Corners 

Power Plant (on the Navajo Nation) 

Units 1—5: $2,500—$3,200 per ton of 

NOX removed;33 PacifiCorp Naughton 

Plant Unit 3 (Wyoming): $2,830 per ton 

of NOX removed;34 and Hayden Station 

(in Colorado) Units 1 and 2: $3,400— 

$4,100 per ton of NOX removed.35

Based on EPA’s cost estimates and our 

analysis of average and incremental cost 

effectiveness, EPA has determined that 

SCR is cost effective at NGS.36

ii. Factor 2: Energy and Non-Air Quality 

Impacts 

The BART Guidelines describe the 

second factor, the energy and non-air 

quality environmental impacts of 

compliance, as an examination of 

whether the use of the control 

technology would result in direct energy 

penalties or benefits, and whether there 

are environmental impacts other than 

air quality due to emissions of the 

pollutant in question or due to the 

control technology. The BART 

Guidelines also state that under the 

energy impacts analysis, the reviewing 

authority may consider ‘‘whether a 

given alternative would result in 

significant economic disruption or 

unemployment.’’ 70 FR 39169. In 

selecting a ‘‘best’’ alternative, the BART 

Guidelines further state that ‘‘there may 

be unusual circumstances that justify 

taking into consideration the conditions 

of the plant and the economic effects of 

requiring the use of a given control 

technology.’’ 70 FR 39171. Thus, 

although neither the CAA nor the RHR 

require states or EPA to consider the 

affordability of controls or ratepayer 

impacts as part of a BART analysis, the 

BART guidelines allow (but do not 

require) consideration of ‘‘affordability’’ 

in the BART analysis. 

EPA is exercising its discretion to 

include in this second factor an analysis 

to examine the viability of NGS’s 

continued operation if new NOX

controls are required. This analysis 

compares electricity generation costs 

after installing new NOX controls at 

NGS against the cost to purchase an 

equivalent amount of power on the 

wholesale market. Because stakeholders 

have expressed concern that installation 

of new controls at NGS may cause the 

facility to close, the purpose of this 

analysis is to assess whether it would be 

more economical for the owners of NGS 

to install controls and continue 

operation, or to retire the facility and 

purchase power in order to meet their 

obligations to supply electricity to their 

customers. EPA has also included an 

analysis to estimate potential indirect 

impacts to ratepayers who use 

electricity supplied by SRP or water 

supplied by CAP. A complete 

discussion of other energy and non-air 

quality impacts is provided in the TSD 

for this proposed rulemaking. 

As discussed previously, NGS is 

unique because it was constructed and 

is owned in part by the federal 

government to provide electricity to 

distribute water to tribes located in 

Arizona and a diverse group of other 

water users. NGS is also located on the 

Navajo Nation and the Kayenta Mine 

that supplies its coal is located on the 

reservation lands of both the Navajo 

Nation and the Hopi Tribe. 

The Navajo Nation and the Hopi Tribe 

have expressed concern that requiring 

additional controls at NGS could result 

in lost employment, taxes, and royalties 

to their tribal governments if the owners 

of NGS chose to retire units or curtail 

operations rather than install new air 

pollution controls. 

a. Affordability Analysis 

As mentioned above, EPA conducted 

an analysis to estimate electricity 

generation costs if SCR or SNCR were 

installed at NGS within 5 years of a final 

rulemaking (i.e., by 2018 if this rule is 

finalized in 2013) 37 compared to costs 

to purchase an equivalent amount of 

power on the wholesale market. This 

analysis assumes that the owners of 

NGS would choose the least costly 

option for providing power to their 


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38The results reported here assume that LADWP’s 

share of NGS is purchased by another publiclyowned utility. Results from other scenarios (e.g., if 

LADWP’s share is purchased by an investor-owned 

utility) are discussed in the TSD for this proposed 

rulemaking. 

39NREL further concludes that even with 

electricity generation rate increases resulting from 

SCR, NGS would still be one of the lowest cost 

generators in the Desert Southwest. 40The NREL analysis commissioned by DOI, as 

well as separate studies commissioned by other 

stakeholders, conducted similar rate analyses. Two 

studies by Harvey Economics, one commissioned 

by SRP and the other commissioned by the Gila 

River Indian Community examined potential 

impacts to electricity rates and Tribal and nonTribal CAP water users in Arizona. A third study 

by Arizona State University commissioned by SRP 

examined the contribution of NGS and the Kayenta 

Mine to the broader regional and Arizona economy. 

Although EPA has included these studies in the 

docket for our proposed rulemaking, EPA is not 

providing a critical review or assessment of the 

methodologies of those studies. 

customers. The results of this analysis 

are summarized briefly here. 

Our analysis is based on a 25-year 

discounted cash flow model that 

calculates the net present value (NPV) of 

the total revenue required to generate 

electricity at NGS over 2012–2036 for 

several different operating scenarios. 

The model assumes a 20-year 

amortization period for scenarios 

involving installation of new air 

pollution controls and uses a 25-year 

discounted cash flow to account for the 

approximate 5-year period between the 

present day and the installation of new 

controls. The scenarios include: The 

current Business As Usual (BAU) 

scenario that accounts for installation in 

2009—2011 of LNB/SOFA, the 

installation of SNCR on all units at NGS 

by 2018, the installation of SCR on all 

units by 2018, and the scenario of 

purchasing energy on the wholesale 

market beginning in 2018 and 

thereafter.38 The results are shown in 

Table 4. 

TABLE 4—NET PRESENT VALUE (NPV) OF TOTAL REVENUE REQUIRED TO GENERATE ELECTRICITY OVER 2012–2036 

WITH NOX CONTROLS COMPARED TO EQUIVALENT WHOLESALE MARKET POWER PURCHASES

Business as 

usual (BAU) 

(LNB/SOFA) 

Increase 

from BAU if 

SNCR 

Increase 

from BAU if 

SCR 

Increase from BAU if power purchased 

on market 

Low Mid High 

NPV ($ millions) ............................................................... $7,766 $278 $648 $673 $951 $1,040 

Percent Increase compared to BAU ................................ n/a 4% 8.3% 8.7% 12.2% 13.4% 

We estimate that the retrofit of all 

three units at NGS with SCR would 

result in an incremental increase in the 

NPV of the revenue required to generate 

electricity at NGS of $648 million over 

the business as usual (BAU) case, which 

is lower than the increase over BAU of 

the cost to purchase the equivalent 

amount of electricity on the wholesale 

market considering the low, mid, and 

high market trends ($673—$1,040 

million). These results shows that 

although SCR would increase the cost of 

electricity generation by 16 percent in 

2018 (see Table 5), on a 25-year NPV 

basis, installation and operation of SCR 

remains less than the total cost to 

purchase electricity on the wholesale 

market from elsewhere in the West. The 

analysis conducted by NREL shows 

similar results that also indicate that 

installation of SCR at NGS by 2018 

would likely cost less than replacing it 

with power purchased from elsewhere 

in the West.39

TABLE 5—INCREASE IN ELECTRICITY GENERATION COSTS IN 2018 IF SCR INSTALLED AT NGS 

Business as usual electricity generation 

cost Electricity generation cost with SCR 

Percent 

increase 

compared to 

BAU 

Bureau of Reclamation ............................. 3.27 cents/kWh ......................................... 3.73 cents/kWh ......................................... 14 

Publicly-Owned Utilities (SRP, LADWP) .. 3.49 cents/kWh ......................................... 3.97 cents/kWh ......................................... 14 

Investor-Owned Utilities (APS, TEP, 

NPC).

3.88 cents/kWh ......................................... 4.61 cents/kWh ......................................... 19 

Average Total Plant ........................... 3.56 cents/kWh ......................................... 4.13 cents/kWh ......................................... 16 

Table 5 shows that the increase in 

electricity generation cost for the 

owners of NGS, ranging from a 14 

percent increase for Reclamation and 

the publicly-owned utilities to an 

estimated 19 percent increase for the 

investor-owned utilities, would differ 

based on how each owner recovers 

capital investments. In other words, the 

increase in electricity generation costs 

for investor-owned utilities is higher 

because the capital recovery includes a 

rate of return for investors. 

b. Electricity and Water Rate Analysis 

In order to determine how the 

projected increase in electricity 

generation cost would affect retail 

customers, EPA also estimated the 

potential increase in retail electricity 

rates for SRP customers, and the 

potential increase in CAP water rates.40

As discussed previously, Reclamation 

owns 24.3 percent of NGS for the benefit 

of the CAP. Power from NGS is used by 

CAP to pump surface water from the 

Colorado River to much of Arizona. 

Construction of CAP was authorized by 

Congress in 1968 under the Colorado 

River Basin Project Act to deliver 

Arizona’s surface water entitlement of 

the Colorado River to the state. 

Under the Colorado River Basin 

Project Act, any electricity owned by 

Reclamation based on its percentage 

ownership of NGS that is not used by 

CAP (excess power) is sold. The 

Colorado River Basin Project Act 

requires profits from Reclamation’s 

excess power sales to be deposited in 

the Lower Colorado River Basin 

Development Fund (Development 

Fund). The Development Fund was 

originally authorized under the 


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41CAWCD calls the delivery portion of water 

costs the ‘‘fixed OM&R’’ costs and the energy 

portion of water costs (the portion associated with 

NGS power costs) the ‘‘variable OM&R’’ costs. 

42Although the Bureau of Reclamation has 

constructed dams that generate hydroelectric 

power, EPA understands that CAP’s main source of 

power comes from Reclamation’s ownership share 

in NGS. 

43For comparison, two Navajo non-governmental 

organizations, the To Nizhoni Ani and Black Mesa 

Water Coalition, provided information on their 

water costs to EPA in the docket for this proposed 

rulemaking. This information stated that members 

of the Navajo Nation, who do not get water from 

CAP, pay much higher costs for water than CAP 

customers, ranging from one to four cents per gallon 

(equivalent to over $3,000 to over $13,000 per acre 

foot of water). 

Colorado River Basin Project Act to 

repay construction costs of CAP to the 

federal government. Subsequent 

settlement acts with several tribes, 

however, have authorized use of the 

Development Fund to pay the delivery 

portion of the cost of CAP water (also 

called fixed operation, maintenance and 

replacement costs, or OM&R costs) 41 for 

certain Indian tribes, and to pay the 

costs to construct the delivery systems 

to bring CAP water to certain Indian 

tribes. 

CAP’s 336-mile water delivery system 

was completed in 1993 and delivers 1.5 

million AF of water annually to 

Maricopa, Pima, and Pinal Counties 

through a series of canals and pumping 

stations. The CAP water delivery system 

is required to pump water up an 

elevation of 3,000 feet from Lake Havasu 

to the city of Tucson. The Central 

Arizona Water Conservation District 

(CAWCD) is the operating entity for 

CAP. According to CAWCD, CAP water 

currently meets over 20 percent of 

Arizona’s total water demands, and 

within CAP’s service area, which 

encompasses about 80 percent of 

Arizona’s water users and taxpayers, 

CAP water meets about 50 percent of the 

municipal demands. Approximately 40 

percent of CAP’s water delivery supply 

is dedicated to Native American use. 

Our analysis indicates that, although 

SRP’s cost to generate electricity would 

increase by 16 percent if SCR were 

installed (Table 5), the maximum 

increase for SRP’s retail customers is 

estimated to be 0.06 cents per kWh, an 

increase of 0.66 percent (Table 6). For 

customers of the utilities that have a 

portfolio of power generating sources, 

e.g., all NGS owners except 

Reclamation,42 the increased electricity 

generation cost at NGS from installation 

of SCR would flow into a broader 

consumer retail rate calculation based 

on the entire portfolio of the utility’s 

electricity generation assets and 

purchase power contracts, which 

typically include coal (including other 

coal plants in addition to NGS), natural 

gas, nuclear, and some renewable 

energy. Therefore, the increase in retail 

rates paid by SRP customers is not 

expected to be proportional, on a 

percentage basis, to SRP’s increase in 

electricity generation costs at NGS. 

In contrast, Reclamation’s share of 

power produced by NGS is used by CAP 

or sold for the benefit of the 

Development Fund. CAP relies on NGS 

for over 90 percent of its power needs. 

The estimated 14 percent increase in the 

electricity generation cost for 

Reclamation (Table 5), would translate 

into a 14 percent increase in the portion 

of the CAWCD water rate associated 

with the electrical cost of pumping 

water (energy costs, or variable OM&R), 

as shown in Table 6, because NGS is 

CAP’s main source of power. 

TABLE 6—PROJECTED ELECTRICITY AND WATER RATES IN 2018 IF NOX CONTROLS ARE INSTALLED AT NGS 

BAU 

(LNB/SOFA) 

SNCR SCR 

Rate increase Percent 

increase Rate increase Percent increase 

Electricity Rate to SRP Customers ....................................... 9.26 cents/kWh .. 0.02 cents/kWh .. 0.2 0.06 cents/kWh .. 0 .66 

CAWCD Water Rate paid by M&I Users ..............................

(fixed + variable OM&R) .......................................................

$141/AF ............. $2.99/AF ............ 2.1 $8.40/AF ............ 6 .0 

CAWCD Water Rate paid by Tribal and Agricultural Users

(variable OM&R) ...................................................................

$58/AF ............... $2.99/AF ............ 5.2 $8.40/AF ............ 14 

Municipal and industrial (M&I) users 

of CAP water pay not only energy costs 

(variable OM&R) but also delivery costs 

(fixed OM&R) of water. Total water rates 

in 2018 for M&I users are projected by 

CAWCD to be $141 per AF; therefore, a 

rate increase from SCR of $8.40 per AF 

represents a 6 percent increase in CAP 

water rates.43 However, the actual 

increase to total water costs would 

depend on the user’s individual degree 

of reliance on CAP water. For example, 

the city of Phoenix relies on CAP for 45 

percent of its water supply. Therefore, a 

6 percent increase in CAP water rates 

would effectively result in a 4 percent 

overall water cost increase to customers 

in Phoenix because CAP water 

represents only a portion of its water. 

In contrast to M&I users, as part of the 

Arizona Water Settlements Act of 2004, 

agricultural water users and tribes pay 

only the energy costs of CAP water; 

therefore, the same $8.40 per AF 

increase in water rates represents a 14 

percent increase. EPA is aware of 13 

tribes located in Arizona that currently 

have CAP water allocations through 

settlement agreements or use CAP water 

under contract (see Table 7 and the TSD 

for this proposed rulemaking for 

additional information and references). 

EPA does not have information 

regarding the degree of reliance on CAP 

water for tribes or agricultural water 

users. However, agricultural or tribal 

customers that have non-CAP sources of 

water will experience a smaller 

percentage increase in total water costs 

than users that rely entirely on CAP 

water (e.g., see Phoenix example 

discussed above). 

TABLE 7—TRIBES WITH CAP 

ALLOCATIONS OR CAP CONTRACTS

Tribe 

CAP Allocation or contract volume 

(acre feet 

per year) 

Gila River Indian Community ... 311,800 

Ak-Chin Indian Community ....... 85,000 

Tohono O’odham Nation .......... 74,000 

San Carlos Apache Tribe ......... 60,665 

White Mountain Apache Indian 

Tribe ...................................... 23,782 

Fort McDowell Yavapai Nation 18,233 

Salt River Pima-Maricopa Indian Community .................... 13,300 

Navajo Nation ........................... 6,411 

Yavapai-Apache Nation (Camp 

Verde) ................................... 1,200 

Hopi Tribe ................................. 1,000 

Pascua Yaqui Tribe .................. 500 

Yavapai-Prescott Tribe ............. 500 

Tonto Apache Nation ................ 128 


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44See page 22 of NREL report. 

45See EPA’s Ambient Air Quality Impact Report, 

dated October 2008, for the proposed PSD permit 

for NGS, in the docket for this proposed 

rulemaking. 

46See Agreement between Grand Canyon Trust 

and Salt River Project on NGS dated November 19, 

2008, in the docket for this proposed rulemaking. 

In its analysis, NREL estimated a low 

and high range of potential water rate 

increases based on SCR installation and 

operation cost estimates from the 

National Park Service and from SRP (see 

Table 8). NREL’s estimates of increased 

water rates from the installation and 

operation of SCR are consistent with our 

estimates. Separate analyses for the Gila 

River Indian Community and SRP by 

Harvey Economics estimated pumping 

cost increases that are slightly lower 

than NREL and EPA estimates. 

TABLE 8—COMPARISON OF PROJECTED WATER RATE INCREASES FROM SCR INSTALLATION ESTIMATED BY EPA AND

OTHER STUDIES

NREL High EPA NREL Low Harvey 

CAP Water Rate Increase ................................................................................... $8.58/AF ...... $8.40/AF ..... $7.10/AF ...... $6.60/AF 

Increase to M&I Users ......................................................................................... 7% ............... 6% ............... 6% ............... Not calculated 

Increase to Tribes and Agricultural Users ........................................................... 16% ............. 14% ............. 13% ............. 11% 

c. Summary of EPA’s Affordability and 

Rate Impacts Analyses 

Based on our analyses, the 25-year 

NPV of costs to produce power at NGS 

with SCR installed and operated on all 

units should be below the market prices 

of wholesale power. 

However, as discussed previously in 

section I.G.ii, EPA understands that the 

timing of regulatory compliance is an 

important consideration given potential 

ownership changes and that the current 

term of NGS’s lease with the Navajo 

Nation, as well as other leases and 

rights-of-way agreements, extend only to 

2019. Based on public statements made 

by stakeholders, and as indicated in the 

March 2012 NREL report, the owners of 

NGS intend to pursue a renewed lease 

agreement with the Navajo Nation that 

extends to 2044. However, until a 

renewed lease that supports continued 

long-term operation of NGS is 

negotiated and approved by DOI, 

significant capital investment needed to 

modernize NGS with new air pollution 

controls may be viewed unfavorably 

without additional certainty that the 

costs can be recovered over a reasonable 

amortization period. 

Our analysis also shows that 

increased electricity rates to customers 

of the utilities that own NGS should be 

relatively low. However, because of 

CAP’s nearly complete reliance on NGS 

for power, we estimate that CAP water 

rates would increase by $8.40 per AF, 

representing a 6 percent increase in 

rates to M&I users and a 14 percent 

increase to tribes and agricultural water 

users. 

EPA understands that a potential 

increase in water rates to tribes is a 

critical issue for them. We note that, as 

described in the following section, past 

pollution control investments at this 

facility have made use of alternative 

financing methods that limited impacts 

on CAP water rates. Furthermore, the 

NREL report indicated that mechanisms 

may exist to help avoid or mitigate the 

estimated level of impact. EPA, in 

conjunction with DOI and DOE, have 

committed to work together on several 

short- and long-term goals, including 

innovative clean energy options for 

electricity generation and seeking 

funding to cover expenses for the 

federal portion of pollution control at 

NGS. However, it is not clear at this 

time whether or what type of 

mechanisms might be available to lessen 

increased costs. Therefore, as explained 

further below, EPA believes that the 

potential economic impacts discussed 

in this section argue for thoughtful 

consideration of how flexibility in the 

compliance timeframe can be provided 

consistent with the air quality goals of 

the Clean Air Act. 

EPA seeks comment on opportunities 

to reduce and/or avoid significant 

impacts on tribes while ensuring 

visibility protection for the 11 affected 

Class I areas. 

iii. Factor 3: Existing Controls at the 

Facility 

As stated previously, NGS currently 

uses hot-side ESPs to control PM. To 

reduce emissions of SO2, SRP installed 

wet limestone FGDs over the period 

1997–1999 on each unit, as required 

under a FIP issued by EPA on October 

3, 1991 (56 FR 50172, codified at 40 

CFR 49.5513(d)(1)), to remedy visibility 

impairment at the Grand Canyon 

National Park that was reasonably 

attributable to NGS. The total cost of the 

FGD units was $420 million. 

Reclamation’s 24.3 percent share of the 

FGD units was funded through CAP 

construction appropriations and 

CAWCD is repaying these costs to the 

federal government as part of total CAP 

project costs over a 50-year period. The 

1991 FIP set an emission limit for SO2

of 0.10 lb/MMBtu on a plant-wide 

rolling annual average basis. On March 

5, 2010 (75 FR 10174), EPA issued a 

gap-filling FIP for NGS to federalize 

emission limits for PM of 0.06 lb/ 

MMBtu on a plant-wide 3-hour average 

basis, an opacity limit of 20 percent, and 

a 3-hour average SO2 limit of 1 lb/ 

MMBtu. The SO2 emission limit in the 

final 2010 FIP ensures that actual SO2

emissions from NGS will remain 90 

percent lower on an annual basis than 

they were before the scrubbers were 

installed to comply with the 1991 

visibility FIP. Additionally, EPA’s final 

MATS rule set a filterable PM limit of 

0.03 lb/MMBtu. This limit applies to 

Units 1–3 at NGS. 

Prior to 2009, NGS used closecoupled over fire air (CCOFA) to control 

NOX emissions. In April 2009, SRP 

submitted a Prevention of Significant 

Deterioration (PSD) permit application 

to EPA Region 9 to voluntarily install 

and operate advanced combustion 

controls (LNB/SOFA) on Units 1—3. 

The LNB/SOFA triggered PSD review 

for significant increases in emissions of 

carbon monoxide (CO). Reclamation’s 

share of the LNB/SOFA installation was 

funded from the Development Fund. 

These costs were then reimbursed by 

SRP on an amortized basis and the 

remaining balance was reimbursed by 

CAWCD.44 Because SRP submitted its 

permit application for the LNB/SOFA 

modification after EPA had begun its 

BART analysis for NGS, in the Ambient 

Air Quality Impact Report (AAQIR) 45

for the proposed PSD permit (AZ 08–01) 

EPA stated that: 

The early installation of the LNB/SOFA 

systems will not affect the baselines for cost 

or visibility improvements in the BART 

determination, and therefore will not 

influence EPA’s determination of the proper 

NOX reductions required to be achieved from 

BART. 

Additionally, in an agreement 46

regarding the EPA proposed PSD permit 

AZ 08–01, signed November 19, 2008, 

by Bill Heddon, Executive Director of 

Grand Canyon Trust (GCT) and Richard 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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47See final PSD permit issued by EPA Region 9 

dated November 20, 2008, in the docket for this 

proposed rulemaking. 

48See EPA Control Cost Manual, Section 6, page 

2–48, available from http://www.epa.gov/ttncatc1/ 

dir1/c_allchs.pdf. 

49The SRP approach, and differences from the 

WRAP protocol, are described in Appendix A of 

Revised BART Analysis for the Navajo Generating 

Station Units 1–3, ENSR Corporation, Document 

No. 05830–012–300, January 2009, Salt River 

Project, Tempe, AZ, in the docket for this proposed 

rulemaking. 

50CALMET/CALPUFF Protocol for BART 

Exemption Screening Analysis for Class I Areas in 

the Western United States, Western Regional Air 

Partnership (WRAP); Gail Tonnesen, Zion Wang; 

Ralph Morris, Abby Hoats and Yiqin Jia, August 15, 

2006. Available on UCR Regional Modeling Center 

web site, BART CALPUFF Modeling, http:// 

pah.cert.ucr.edu/aqm/308/bart.shtml. 

Hayslip, Associate General Manager of 

SRP, GCT agreed to withdraw its 

November 14, 2008, comment letter to 

EPA, provided SRP understood that: 

Grand Canyon Trust stands by its support 

for the installation of low-NOX burners and 

separated overfire air at the Navajo 

Generating Station as long as their 

installation and operation will not prejudice 

in any way the implementation of more 

effective NOX and particulate matter controls 

(including SCR or SNCR, and baghouse 

technology) to more fully address Navajo’s 

visibility impacts under the reasonable 

attribution and regional haze programs. 

SRP installed LNB/SOFA combustion 

controls on Unit 3 in 2009, on Unit 2 in 

2010, and on Unit 1 in 2011. Therefore, 

all three units currently operate with 

modern advanced combustion controls 

and are required to meet the NOX limit 

set in the final PSD permit issued by 

EPA on November 20, 2008, of 0.24 lb/ 

MMBtu on a 30-day rolling average.47

Because EPA, GCT, and SRP agreed 

that the installation of advanced 

combustion controls would not affect or 

prejudice our BART determination for 

NGS, EPA’s analysis of the cost 

effectiveness of SCR used the baseline 

emission rate from 2001—2003, prior to 

the installation of the LNB/SOFA. 

However, because EPA’s proposed 

BART determination is being issued for 

public comment in 2013, after the 

installation of advanced combustion 

controls has been completed on all 

units, EPA is also providing cost 

effectiveness information calculated 

using LNB/SOFA as the baseline, which 

is equivalent to calculating incremental 

cost effectiveness of SCR+LNB/SOFA 

compared to LNB/SOFA alone (see 

Table 3). These values are also 

discussed as the incremental cost 

effectiveness estimates in Section 3 of 

the TSD for this proposed rulemaking. 

The affordability and rate impact 

analysis, discussed above, considers the 

installation of LNB/SOFA over the 

period of 2009—2011 as expenditures 

that have already occurred; therefore, 

additional calculations for the analysis 

using LNB/SOFA as baseline are not 

needed. 

Based on the information above, EPA 

is proposing to determine that 

consideration of the existing controls at 

NGS does not warrant eliminating SCR 

as the top technically feasible and cost 

effective NOX emission control 

technology for NGS. 

iv. Factor 4: Remaining Useful Life of 

Facility 

EPA is proposing to determine that 

the appropriate remaining useful life for 

NGS, as used as an amortization period 

for the cost of controls, should be 20 

years. The various uncertainties 

currently facing NGS, including 

ownership changes and current lease 

and right-of-way agreement 

negotiations, could affect NGS’s ability 

to operate into the future; however, 

without an enforceable obligation for a 

shorter useful life, EPA has determined 

it is most appropriate to rely on a 20- 

year useful life as the default for 

amortization purposes. 

EPA also understands from recent 

discussions on the lease renewal for 

NGS that the owners may be negotiating 

the renewal lease period to end in 2044 

(over 30 years from 2013). Although a 

30-year amortization period may be 

more realistic for NGS, a longer 

amortization period would reduce the 

annualized cost of capital improvements 

and, thus, decrease the $/ton cost 

effectiveness value. Because the use of 

the shorter amortization period is more 

conservative (increases the $/ton cost 

effectiveness value), EPA’s calculations 

of cost effectiveness in our analysis rely 

on a 20-year amortization period. 

However, EPA recognizes that if the 

capital costs of controls can be 

amortized over a longer period, the cost 

effectiveness of new controls would 

appear more favorable. 

The default amortization period used 

in the EPA Control Cost Manual is 20 

years,48 and given the indications that 

the remaining life of NGS could be 

shorter or longer, EPA is proposing to 

determine that use of a 20-year 

remaining useful life is appropriate. 

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 39170. The 

BART guidelines recommend using the 

CALPUFF air quality dispersion model 

to estimate the visibility improvements 

from alternative control technologies at 

each nearby 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. EPA 

included in our modeling analysis the 

11 Class I areas that are within 300 km 

of NGS. These areas are listed in Table 

10 below, along with estimated 

visibility impacts. 

Visibility is often described in terms 

of visual range in kilometers or miles. 

The deciview scale is an alternative 

measure of visibility impairment: lower 

deciview values represent better 

visibility and greater visual range, while 

increasing deciview values represent 

increasingly poor visibility. 

EPA’s 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 98th percentile is 

recommended rather than the maximum 

value to avoid undue influence from 

unusual meteorological conditions. The 

‘‘delta’’ refers to the difference between 

total deciview impact from the facility 

including natural background, and 

deciviews of natural background alone, 

so ‘‘delta deciviews’’ is the estimate of 

the facility’s impact on visibility. In 

practice, ‘‘deciview impact’’ is often 

used in place of ‘‘delta deciview 

impact’’ and the two terms should be 

assumed to have the same meaning. 

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 would ‘‘contribute’’ to 

visibility impairment. 

CALPUFF modeling is generally 

performed according to a modeling 

protocol, which sets out the model 

version, choice of geographic domain, 

input preparation procedures, and the 

various model settings to be used. EPA’s 

modeling for this proposed rulemaking 

generally followed the same approach in 

SRP’s modeling,49 which in turn was 

based on the 2006 Western Regional Air 

Partnership (WRAP) protocol,50

developed for subject-to-BART 

screening modeling of NGS and other 

western facilities. The WRAP protocol 

was reviewed by multiple regulatory 

agencies, including EPA, the National 

Park Service, the U.S. Forest Service 

(USFS), and air agencies of WRAP 

member states; it was accepted by 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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51Letter 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 

16, 2009, document number 0016 in the docket for 

the ANPRM: EPA–R09–OAR–2009–0598. 52 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, available at: http:// 

www.epa.gov/scram001/7thconf/calpuff/ 

phase2.pdf, and in the docket for this proposed 

rulemaking. 53Ammonia concentrations for Mesa Verde 

National Park were not based on the backcalculation method for these simulations, but 

instead were derived from measured ammonia 

concentrations in the Four Corners area, as 

described in 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). 54Federal Land Managers’ Air Quality Related 

Values Work Group (FLAG) Phase I Report— 

Revised (2010), U.S. Forest Service, National Park 

Service, U.S. Fish and Wildlife Service, October 

2010. Available on web page http:// 

www.nature.nps.gov/air/Permits/flag. 55Pitchford, Marc, 2006, ‘‘New IMPROVE 

algorithm for estimating light extinction approved 

for use’’, The IMPROVE Newsletter, Volume 14, 

Number 4, Air Resource Specialists, Inc.; web page: 

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

Publications/news_letters.htm; Revised IMPROVE 

algorithm for Estimating Light Extinction from 

Particle Speciation Data, IMPROVE, January 2006. 

web page: http://vista.cira.colostate.edu/improve/ 

publications/graylit/gray_literature.htm. 

56 It is worth noting that an EPA guidance memo 

suggests that the comparison can use either annual 

average background conditions, or the average of 

the best (cleanest) 20 percent of days. ‘‘Regional 

Haze Regulations and Guidelines for Best Available 

Retrofit Technology (BART) Determinations’’, 

memorandum from Joseph W. Paisie, EPA OAQPS, 

July 19, 2006, p. 2. 

57EPA did not average the 98th percentiles from 

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

percentile from all the daily values from the three 

years taken together. This does not significantly 

affect the overall results. 

WRAP states for use in their Regional 

Haze SIPs. Differences between the SRP 

approach and the WRAP approach are 

discussed in more detail in the TSD for 

this proposed rulemaking. 

While EPA generally followed the 

SRP approach, EPA used different 

ammonia background concentrations 

and a different method for converting 

CALPUFF concentrations to visibility 

impact estimates. These differences, 

described in detail below, result in 

substantial differences in predicted 

visibility impacts. 

The values of ammonia background 

concentrations are important because 

ammonia is a component of 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 motor vehicles, 

livestock operations, fertilizer 

application associated with farming, 

and ammonia slip from the use of 

ammonia in SCR and SNCR 

technologies to control NOX emissions. 

Sensitivity of the model results to other 

ammonia assumptions are discussed in 

the TSD, and do not change the ranking 

of control options for evaluating 

visibility improvement, or the overall 

conclusions of the visibility analysis. 

The U.S. Forest Service informed EPA 

that the ammonia background 

concentrations modeled by Arizona 

Public Service for the Four Corners 

Power Plant in January 2008 were lower 

than observed concentrations.51 The 

USFS recommended a method of backcalculating the ammonia background 

based on monitored values of sulfate 

and nitrate. EPA’s ANPRM provided 

modeling results based on using the 

USFS’s back-calculation methodology, 

for both Four Corners and NGS. 

The visibility modeling supporting 

today’s proposal for NGS uses a 

constant ammonia background of 1 ppb, 

which is the default value 

recommended for western areas by the 

Interagency Workgroup on Air Quality 

Modeling.52 The TSD describes the 

results of sensitivity simulations using 

different concentrations of background 

ammonia. This includes supplemental 

modeling using a range of 0.2–1 ppb 

ammonia background concentrations as 

used by SRP, as well as supplemental 

modeling using back-calculated 

ammonia concentrations,53 with a 

thorough discussion of the backcalculation methodology. 

Aside from the background ammonia 

assumptions, the other significant 

difference between EPA’s modeling 

approach and the SRP approach is the 

procedure for calculating visibility 

impacts within CALPOST, a CALPUFF 

post-processor. This difference has two 

aspects, the ‘‘visibility method’’ used to 

convert CALPUFF pollutant 

concentrations into deciviews, and the 

choice of natural background 

conditions, which affects the calculation 

of delta deciviews. 

A key choice in the visibility method 

is between Method 6 and Method 8, 

implementing the original and the 

revised IMPROVE equation, 

respectively. The IMPROVE equation 

converts monitored or modeled 

pollutant concentrations into extinction, 

which is the fraction of light removed 

from a sight path; deciviews are 

calculated from extinction. Many BART 

assessments were performed before the 

revised IMPROVE equation was 

incorporated into CALPUFF, so the 

original equation was generally used for 

past assessments. However, in this 

proposal EPA is primarily relying on the 

revised IMPROVE equation. The revised 

IMPROVE equation is currently 

preferred by the Federal Land 

Managers,54 because it has less bias in 

estimating visibility under the worst 

visibility conditions.55 As discussed in 

the TSD, EPA performed sensitivity 

simulations and found that using the 

original IMPROVE equation would on 

average give baseline impacts about 3 

percent lower than using the revised 

equation, with a range of 15 percent 

lower to 9 percent higher depending on 

the Class I area. 

The BART Guidelines recommend 

that visibility impacts should be 

estimated in deciviews relative to 

natural background conditions, that is, 

in delta deciviews. In accordance with 

the BART Guidelines, EPA used the 

average of the best 20 percent days as 

background.56

Table 9 presents the visibility impacts 

of the 98th percentile of 24-hour delta 

deciviews for each Class I area for each 

year, averaged over 2001–2003.57 For 

each Class I area, the table shows the 

deciview impact for the base case, and 

the deciview improvement from that 

baseline impact when controls are 

applied. Also shown are the cumulative 

deciview impacts, which are the simple 

sum of impacts or improvements over 

all the Class I areas. Table 10 shows the 

average number of days with a baseline 

impact or improvement of at least 0.5 

dv; it also shows two ‘‘dollars per 

deciview’’ measures of cost 

effectiveness, both of which divide the 

total annual cost of the control in 

millions of dollars per year by an 

improvement in deciviews. For the first 

metric, ‘‘$/max dv’’, annual cost (Table 

2) is divided by the 98th percentile 

deciview improvement at the Class I 

area with the greatest improvement 

(Table 9). The second metric, ‘‘$/ 

cumulative dv’’, divides annual cost by 

the cumulative 98th percentile deciview 

improvement. In assessing the degree of 

visibility improvement from controls, 

EPA relied heavily on the maximum 

deciview improvement among the Class 

I areas and the number of areas showing 

improvement (i.e., all 11 Class I areas), 

with cumulative improvement 

providing a supplemental measure that 

combines information on the number of 

areas and on individual area 

improvement. The $/dv metrics shown 

in Table 10 provide additional, costrelated information that supplements to 

the cost effectiveness ($/ton) that was 

considered in Factor 1: Cost of 

Compliance. 


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TABLE 9—EPA MODELING RESULTS—BASELINE IMPACTS AND IMPROVEMENT FROM NOX CONTROLS, 98TH PERCENTILE

DELTA DECIVIEWS (DV) FROM 2001–2003, USING 1 PPB AMMONIA BACKGROUND

Class I area 

Distance to 

NGS 

Baseline 

impact 

Improvement 

from LNB/SOFA 

Improvement 

from 

SNCR+LNB/ 

SOFA 

Improvement 

from SCR+LNB/ 

SOFA 

(km) (dv) (dv) (%) 

(dv) (%) (dv) (%) 

Arches NP ........................................................................ 245 4.5 1.7 37 2.2 50 3.5 77 

Bryce Canyon NP ............................................................ 96 4.9 1.6 33 2.3 46 3.6 74 

Canyonlands NP .............................................................. 173 6.0 2.1 35 2.9 48 4.6 76 

Capitol Reef NP ............................................................... 90 7.7 2.1 28 3.1 40 5.4 71 

Grand Canyon NP ........................................................... 29 8.4 1.9 23 2.9 35 5.4 64 

Mazatzal WA .................................................................... 279 1.5 0.6 41 0.8 52 1.1 75 

Mesa Verde NP ............................................................... 253 3.2 1.3 42 1.8 55 2.6 81 

Petrified Forest NP .......................................................... 235 3.4 1.4 41 1.8 54 2.7 78 

Pine Mountain WA ........................................................... 287 1.3 0.5 41 0.7 54 1.0 75 

Sycamore Canyon WA .................................................... 204 2.4 0.9 37 1.2 50 1.8 75 

Zion NP ............................................................................ 134 4.4 1.4 31 2.0 45 3.3 76 

Cumulative ................................................................ .................... 48 16 33 22 45 35 73 

TABLE 10—EPA MODELING RESULTS FROM 2001–2003, USING 1 PPB AMMONIA BACKGROUND—ADDITIONAL VISIBILITY

METRICS

Baseline 

Impact 

Improvement From 

LNB/SOFA 

Improvement from 

SNCR+LNB/SOFA 

Improvement From 

SCR+LNB/SOFA 

Average number of days greater than or equal to 0.5 dv 

at Class I area with most-impacted Baseline 

(Canyonlands NP) ........................................................ 130 27 21% 44 34% 72 55% 

$/max dv (millions) ........................................................... n/a $2.5 ................ $9.3 ................ $11.8 ................

$/cumulative dv (millions) ................................................ n/a $0.3 ................ $1.3 ................ $1.8 ................

As shown in Tables 9 and 10, the 

modeled visibility benefits of 

SCR+LNB/SOFA are substantially 

greater than those of SNCR+LNB/SOFA 

or LNB/SOFA. The modeled 98th 

percentile visibility improvement due to 

installation of LNB/SOFA equals or 

exceeds 0.5 deciviews at all 11 Class I 

areas, exceeds 1 deciview at most of 

these Class I areas, and reaches 2.1 

deciviews at two of these Class I areas. 

For SNCR+LNB/SOFA, the modeled 

visibility improvement exceeds 0.5 

deciviews at all 11 Class I areas, exceeds 

1 deciview at most of these Class I areas, 

and reaches roughly 3 deciviews at 

three of these Class I areas. For 

SCR+LNB/SOFA, the improvement 

exceeds 1 deciview at all 11 Class I 

areas, exceeds 2 deciviews at most of 

these areas, and reaches 5.4 deciviews at 

two of these areas. 

EPA is proposing to determine that 

the anticipated visibility benefits of 

NOX controls at NGS supports 

SCR+LNB/SOFA as the most stringent 

technically feasible and cost effective 

NOX emission control technology for 

NGS. 

C. EPA’s Proposed NOX Emission Limit 

for NGS 

The BART Guidelines give states and 

EPA discretion in determining the 

relative weight of each factor in making 

a BART determination. A summary of 

the results of EPA’s factor analysis is 

shown in Table 11. 

TABLE 11—SUMMARY OF EPA’S FIVE FACTOR NOX BART ANALYSIS FOR NGS 

Factor LNB/SOFA SNCR+LNB/SOFA SCR+LNB/SOFA 

Limit(lb/MMBtu) ........................................................ 0.24 .................................... 0.18 .................................... 0.055. 

1 Average Cost Effectiveness ....................................... $486/ton ............................. $1,745/ton .......................... $2,240/ton. 

Incremental Cost Effectiveness ................................ N/A ..................................... $ 4,110/ton ........................ $2,933/ton (v. SNCR), 

$3,315/ton (v. LNB). 

2 Comparison of SCR vs. Market (compliance by 

2018).

Increase in Net Present Value from SCR = $648 million vs. NPV from Market Cases = 

$673–$1040 million. 

SRP Electricity Rate in 2018 (compliance by 2018) 9.26¢/kWh (Baseline) ........ 9.28¢/kWh ......................... 9.32¢/kWh. 

Energy-Only Water Rate in 2018 (compliance by 

2018).

$58/acre-foot (Baseline) .... $61/acre-foot ..................... $66/acre-foot. 

3 Existing Controls ........................................................ LNB/SOFA installed in 2009–2011 

4 Remaining Useful Life ................................................ EPA Default Amortization Period is 20 years. NGS seeking to extend lease to 2044 

5 Highest Visibility Benefit of Controls .......................... 2.1 dv ................................. 3.1 dv ................................. 5.4 dv. 

Sum of Visibility Benefit from 11 Class I areas ....... 16 dv .................................. 22 dv .................................. 35 dv. 


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58For simplicity, EPA has assumed the rule will 

be finalized in 2013 in our analysis of alternatives 

to BART. 

Based on our five factor analysis, EPA 

is proposing to determine a plantwide 

emission limit of 0.055 lb/MMBtu as 

BART for NGS, based on a rolling 

average of 30 boiler operating days, 

achievable with the installation of SCR. 

We are proposing this emissions limit as 

BART for NOX because: (1) The average 

and incremental costs of SCR are cost 

effective; (2) EPA anticipates that the 

installation and operation of SCR to 

meet the proposed BART limit should 

not cause the owners of NGS to retire 

units and that the history of funding air 

pollution control at NGS suggests that 

other significant impacts may be 

avoided or mitigated; (3) the voluntary 

installation of LNB/SOFA in 2009–2011 

at NGS has achieved some NOX

reductions, but not the level achievable 

with SCR; (4) NGS is projected to 

continue operation at least to 2044; and 

(5) the anticipated visibility 

improvements from SCR would be 

significant at 11 Class I areas. Based on 

these factors, EPA is proposing to 

determine that an emission limit of 

0.055 lb/MMBtu is BART for NGS. This 

emission limit represents a reduction of 

nearly 80 percent from the existing 

permitted NOX emission limit. 

D. EPA’s Proposed BART Alternative 

Under the CAA, compliance with 

emission limits determined as BART 

must be ‘‘as expeditious as practicable 

but in no event later than five years’’ 

after the effective date of the final BART 

determination (See CAA 169A(b)(2)(A) 

and (g)(4)). That date would be 2018, if 

the rule is finalized in 2013, or 2019 if, 

due to a need for extended public 

discussion or a supplemental proposal, 

the rule is finalized in 2014.58 As 

previously stated, EPA recognizes that 

the circumstances related to NGS create 

unusual and significant challenges for a 

5-year compliance schedule. We 

therefore have considered other options 

that are consistent with the CAA and 

RHR, that also provide for a more 

flexible, extended compliance schedule. 

EPA’s BART regulations allow an 

alternative to BART provided the 

alternative results in greater reasonable 

progress than would have been achieved 

through installation of BART. 40 CFR 

51.308(e)(2). The regulations provide 

that an alternative to BART must ensure 

that all necessary emission reductions 

occur during the period of the first longterm strategy for regional haze, or in 

2018 for States that were required to 

submit regional haze SIPs in December 

2007. 40 CFR 51.308(e)(2)(iii). Thus, the 

RHR provided five additional years for 

the implementation of alternatives to 

BART (known as ‘‘better than BART’’). 

In today’s proposal, we are proposing 

a BART alternative (Alternative 1) for 

NGS that would require the plant to 

meet a NOX limit of 0.055 lb/MMBtu on 

one unit per year in 2021, 2022, and 

2023. We also describe and solicit 

comment on a framework for extending 

the compliance schedule beyond 2023, 

and will issue a supplemental proposal 

if we receive comments supporting a 

later compliance date. 

i. Compliance Flexibility Is Necessary or 

Appropriate 

EPA is proposing an alternative to 

provide the owners of NGS options for 

flexibility in achieving emissions 

reductions required under our proposed 

BART determination. SRP expressed 

concern that the owners of NGS may 

choose to retire the facility if faced with 

the financial risk of making a large 

capital investment within 5 years 

without also having certainty that the 

lease and contract re-negotiations would 

conclude in a timely and favorable 

manner. EPA understands that the 

owners of NGS face numerous 

uncertainties and the unusual 

requirement to comply with NEPA for 

lease and other rights-of-way approvals, 

which apply only to NGS and Four 

Corners Power Plant. EPA also 

understands the importance of the 

continued operation of NGS and the 

Kayenta Mine to the Navajo Nation and 

Hopi Tribe as a source of direct 

revenues through lease payments or coal 

royalties, as well as the importance of 

Reclamation’s share of NGS to supply 

water to many tribes located in Arizona 

in accordance with several water 

settlement acts. 

In this proposal, EPA is proposing 

Alternative 1 as a ‘‘better than BART’’ 

alternative that addresses the 

uncertainties described in the previous 

section. We are also requesting 

comment on two other alternatives that 

provide longer schedules for 

compliance. Because we would need 

additional information to propose to 

approve a longer compliance schedule 

beyond the timeframe in Alternative 1, 

we would supplement our proposal if 

we intend to finalize either of the longer 

compliance schedules discussed below. 

As discussed below, all of the 

alternatives include a NOX emission rate 

of 0.055 lb/MMBtu, but vary in the 

amount of time provided for 

compliance. Alternative 1 and the other 

two on which we are soliciting 

comment assume that NGS will 

continue to operate well into the future, 

but EPA recognizes that there may be 

changes in energy demand or in how 

energy is supplied in this region that 

could form the basis of other options. 

EPA welcomes comment on our 

proposed BART determination and 

proposed alternative (Alternative 1), as 

well as the other alternatives we 

describe here and other options from 

interested parties. 

ii. Background on Alternative Measures 

to BART 

EPA has previously provided 

flexibility to the Four Corners Power 

Plant (FCPP), also located on the Navajo 

Nation, to achieve emission reductions 

of NOX under either BART or an 

alternative measure to BART. 77 FR 

51619 (August 24, 2012). Changes in 

ownership at FCPP and differences 

between the five boilers operated at 

FCPP, contributed, in part, to a decision 

by the owners of FCPP to put forth an 

alternative emission control strategy 

that included closure of the three 

smaller and less efficient units and 

somewhat delayed installation of SCR 

on the two largest units, resulting in 

greater emission reductions than under 

EPA’s proposed BART determination. 

On February 25, 2011, EPA proposed 

this alternative emission control strategy 

as an alternative measure that would 

result in more progress towards 

achieving visibility improvements in the 

surrounding Class I areas (76 FR 10530). 

In that Supplemental Proposal, EPA put 

forth the legal and historical background 

for proposing a BART Alternative (76 

FR 10533). Briefly, the RHR allows 

states (and EPA) the ability to consider 

alternatives to BART (40 CFR 

51.308(e)(2)). The regulation requires a 

demonstration, based on a weight of 

evidence evaluation, that the alternative 

measure will achieve greater reasonable 

progress than would have resulted from 

installation and operation of BART. The 

regulation provides that: 

[i]f the distribution of emissions is not 

substantially different than under BART, and 

the alternative measure results in greater 

emission reductions, then the alternative 

measure may be deemed to achieve greater 

reasonable progress. 

40 CFR 51.308(e)(3). The RHR also 

requires that emission reductions from 

the alternative program take place 

during the period of the first long-term 

strategy for regional haze (40 CFR 

51.308(e)(2)(iii), which ends in 2018. 

EPA’s final action on FCPP required the 

facility to achieve emission reductions 

under the alternative emission control 

strategy by July 31, 2018. 


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59See spreadsheet titled ‘‘BART 

Alternatives.xlsx’’ in the docket for this proposed 

rulemaking. 

iii. Legal Rationale for Extending 

Compliance Schedule for Alternative 

Measures for NGS 

For NGS, EPA is proposing a BART 

alternative (Alternative 1) consistent 

with 40 CFR 51.308(e)(2). In particular, 

EPA is proposing that consideration of 

a compliance schedule beyond 2018 for 

Alternative 1 at NGS is appropriate for 

several reasons, including the singular 

importance of NGS to many tribes 

located in Arizona and their water 

settlement agreements with the federal 

government, the numerous uncertainties 

facing the owners of NGS, the 

requirement for NEPA review of a lease 

extension, and the early and voluntary 

installation of modern combustion 

controls over the 2009–2011 timeframe. 

The timeframe for compliance would 

not, in itself, avoid or mitigate increases 

in water rates for tribes located in 

Arizona; however, it would provide 

time for the collaborating federal 

agencies to explore options to avoid or 

minimize potential impacts to tribes, 

including seeking funding to cover 

expenses for the federal portion of 

pollution control at NGS. 

EPA is exercising its authority and 

discretion under section 301(d)(4) of the 

Clean Air Act, 42 U.S.C. 7601(d)(4), and 

40 CFR 49.11(a) to propose an extended 

timeframe for an alternative measure 

under the RHR for NGS. EPA considers 

this extension of time to be consistent 

with the general programmatic 

requirements. In the 1999 RHR, EPA 

provided states with the flexibility to 

adopt alternatives to BART but required 

any such alternative to be fully 

implemented by the end of the first 

planning period. 40 CFR 

51.308(e)(2)(iii). States and regulated 

sources accordingly had almost 20 years 

under the RHR to design and implement 

alternative measures to BART. Because 

of the myriad stakeholder interests and 

complex governmental interests unique 

to NGS, we are only now addressing the 

BART requirements for NGS. Given the 

timing of our proposed action, any 

BART alternative would need to be fully 

implemented on the same timeframe as 

BART, under the current regional haze 

regulations. For all the reasons 

explained above, we consider it 

appropriate to consider an extended 

compliance period for NGS. Therefore, 

notwithstanding the requirements in 40 

CFR 51.308(e)(2)(iii) for BART 

alternatives to be implemented by 2018 

(if the rule is finalized in 2013), we are 

proposing in Alternative 1 to require 

that emission reductions from an 

alternative to BART at NGS take place 

by 2023. 

Our proposal to require emission 

reductions by 2023 is also supported by 

the Tribal Authority Rule codified at 40 

CFR 49.11(a). The TAR reflects EPA’s 

commitment to promulgate ‘‘such 

Federal implementation plan provisions 

as are necessary or appropriate to 

protect air quality’’ in Indian country 

where a tribe either does not submit a 

tribal implementation (TIP) or does not 

receive approval of a submitted TIP. 

(Emphasis added.) 

The use of the term ‘‘provisions as are 

necessary or appropriate’’ indicates 

EPA’s determination that it may only be 

necessary or appropriate to promulgate 

a FIP of limited scope. The United 

States Court of Appeals for the Tenth 

Circuit has previously endorsed the 

application of this approach in a 

challenge to the FIP for the Four Corners 

Power Plant, stating: ‘‘[40 CFR 49.11(a)] 

provides the EPA discretion to 

determine what rulemaking is necessary 

or appropriate to protect air quality and 

requires the EPA to promulgate suc 

rulemaking.’’ Arizona Public Service 

Company v. EPA. The court went on to 

observe: ‘‘Nothing in section 49.11(a) 

requires EPA * * * to submit a plan 

meeting the completeness criteria of [40 

CFR part 51] Appendix V.’’ Id. While 

the decision in Arizona Public Service 

Company focused on 40 CFR Part 51 

Appendix V, EPA believes the same 

considerations apply to the 

promulgation of a FIP intended to 

address the objectives set forth in 40 

CFR 51.308(e)(2). In particular, EPA has 

discretion to determine if and when a 

FIP addressing the objectives set forth in 

40 CFR 51.308(e)(2) should be 

promulgated, which necessarily 

includes discretion to determine the 

timing for complying with the 

requirements of any such FIP. 

iv. Description and Analysis of a 

Proposed Alternative Measure to BART 

EPA recognizes that the owners of 

NGS elected to install modern LNB/ 

SOFA on one unit per year at the facility 

over the 2009–2011 timeframe. The NOX

reductions achieved by installing the 

modern LNB/SOFA were not required 

under any regulatory program of the 

CAA; therefore, installation of new 

combustion controls (i.e. LNB/SOFA) 

was voluntary. SRP obtained a preconstruction PSD permit from EPA in 

2008 for a significant increase in CO 

emissions, a criteria pollutant that does 

not impair visibility, as a result of the 

installation and operation of new 

combustion controls. EPA notes that 

LNB/SOFA is a potential control option 

evaluated in this BART analysis, and 

that LNB/SOFA is typically used in 

conjunction with installation of SCR or 

SNCR to first reduce emissions of NOX

formed during combustion before 

further control by the downstream postcombustion control system. EPA 

recognizes that the owners of NGS could 

have waited until a final BART 

determination was issued and effective 

before installing any new controls, 

including the LNB/SOFA. 

SRP’s early and voluntary installation 

of LNB/SOFA over the 2009–2011 

timeframe resulted in more NOX

emissions reductions during the 2009– 

2018 period than if LNB/SOFA were 

installed concurrently with SCR by 

2018. Our BART proposal requires NGS 

to achieve the BART limit of 0.055 lb/ 

MMBtu no later than 5 years after our 

final rule. For purposes of this 

evaluation, we are assuming the rule is 

finalized in 2013 and that NGS would 

be required to meet the emissions limit 

achievable with SCR+LNB/SOFA 5 

years after 2013, or by 2018. EPA is 

proposing to apply these early and 

voluntary NOX emission reductions as a 

credit in our analysis of BART 

alternatives. EPA has determined that 

application of a credit for NOX

reductions achieved by LNB/SOFA 

during the 2009–2018 period is 

appropriate here because if LNB/SOFA 

were not already installed at NGS, the 

BART determination EPA is proposing 

today would have incorporated 

installation of LNB/SOFA in 

combination with SCR as BART. We 

calculate that the early NOX emission 

reductions achieved by installation of 

LNB/SOFA in the 2009–2011 timeframe 

at NGS totals 92,715 tons.59 EPA is 

proposing to find that an alternative is 

‘‘better than BART’’ if the adjusted total 

NOX emissions over the 2009–2044 

timeframe (i.e., emissions remaining 

after subtracting 92,715 tons for the 

LNB/SOFA credit for early and 

voluntary emission reductions) are less 

than total emissions under our proposed 

BART determination for the same 

period (i.e., 358,974 tons). 

We are proposing in Alternative 1, as 

an alternative to BART, to require NGS 

to meet a NOX limit of 0.055 lb/MMBtu 

on one unit per year in 2021, 2022, and 

2023. EPA notes that the installation 

years for Alternative 1 coincide with 

scheduled major outages at NGS. 

As shown in Table 12 below, EPA has 

calculated that the total amount of NOX

that would be emitted from NGS over 

the 2009–2044 timeframe under EPA’s 

proposed BART determination will 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
8290 Federal Register / Vol. 78, No. 24 / Tuesday, February 5, 2013 / Proposed Rules 

60Emissions over 2009–2044 for EPA’s proposed 

BART determination are calculated assuming 

compliance with a proposed limit of 0.055 lb/ 

MMBtu by 2018, and actual installation years for 

LNB/SOFA, i.e., 2009–2011 period. EPA has 

selected the period 2009–2044 as most appropriate 

because it includes the early installation dates for 

LNB/SOFA and extends until the anticipated 2044 

termination date of the new site lease currently 

under negotiation between the Navajo Nation and 

the owners of NGS. Other timeframes can be used 

for the ‘‘better than BART’’ analysis (e.g., 2001– 

2064), however, these timeframes are unlikely to 

materially alter the analysis. 

equal 358,974 tons.60 EPA has also 

calculated that the total NOX emissions 

over 2009–2044 under Alternative 1, 

with the credit for the actual early and 

voluntary emission reductions, will be 

338,189 tons. Based on its adjusted total 

NOX emissions, Alternative 1 meets the 

‘‘better than BART’’ threshold (i.e., 

338,189 tons is less than 358,974 tons). 

Therefore, EPA is proposing Alternative 

1 (compliance with BART emission 

limits on one unit per year in 2021, 

2022, and 2023) as a better-than-BART 

alternative that results in greater 

reasonable progress than would be 

achieved under BART. 

TABLE 12—ANALYSIS OF PROPOSED BART ALTERNATIVE

BART Alternative 1 

Installation Years ........................................................... by 2018 ..................................... 2021, 2022, and 2023. 

Total Emissions (tons) ................................................... 358,974 ..................................... 430,904. 

LNB/SOFA Credit (tons) ................................................ n/a ............................................. 92,175. 

Adjusted Emissions (tons) ............................................. n/a ............................................. 338,189. 

Better than BART? ........................................................ n/a ............................................. Yes. 

(338,189 tons < 358,974 tons). 

E. Analysis of Additional Alternative 

Compliance Schedules 

To the extent that there may be 

interest in additional flexibility beyond 

the 2021–2023 compliance schedule 

under Alternative 1, EPA has evaluated 

two additional compliance schedules, 

using the ‘‘better than BART’’ analysis 

framework described above, to evaluate 

additional time for compliance, i.e., 

compliance on one unit per year in 

2023, 2024, and 2025 (Alternative 2) 

and compliance on one unit per year in 

2024, 2025, and 2026 (Alternative 3). 

EPA is not proposing Alternatives 2 and 

3 because these alternatives require 

additional information from 

stakeholders in order to meet the ‘‘better 

than BART’’ threshold. We are soliciting 

comment on Alternatives 2 and 3, and, 

if appropriate, will supplement this 

proposal before finalizing any 

alternative to BART that extends the 

compliance schedule beyond the 

timeframe proposed in Alternative 1. 

As shown in Table 13, Alternatives 2 

and 3 do not, as currently evaluated, 

meet the ‘‘better than BART’’ threshold 

because the adjusted emissions 

(accounting for the LNB/SOFA credit for 

early NOX reductions) exceed total 

emissions under BART. Table 13 refers 

to the amount by which the alternative 

exceeds BART as the ‘‘NOX emissions 

reduction deficit.’’ For Alternatives 2 

and 3, the NOX emission reduction 

deficits are 15,179 tons and 33,160 tons, 

respectively, showing that as the 

compliance dates under a given 

alternative extend further into the 

future, the NOX emission reduction 

deficit grows. Because Alternatives 2 

and 3 do not by themselves meet the 

‘‘better than BART’’ threshold, EPA 

views Alternatives 2 and 3 as viable 

only if the owners of NGS achieve 

additional emission reductions to bridge 

the deficit in NOX emission reductions. 

These additional emission reductions 

could be implemented as short-term 

(e.g., for some subset of the period 

2009–2044) or long-term (e.g., achieved 

annually until 2044) measures. 

As shown in Table 13, if the owners 

of NGS complied with the schedule 

under Alternative 2 and implemented a 

short-term emission reduction bridge 

(for example, over a 10-year period from 

2013–2023), the owners of NGS would 

need to achieve additional NOX

emission reductions of 1,518 tons per 

year. Similarly, implementing a longterm emission reduction bridge (for 

example, over the period of 2013–2044) 

would require additional NOX emission 

reductions of 490 tons per year. The 

short and long term emission reduction 

bridges in Table 13 provide examples of 

how additional emission reductions 

might be distributed over time. The 

actual annual emission reductions that 

NGS would need to bridge the NOX

deficit would depend, not only on the 

size of the deficit, but on the specific 

measures and time periods chosen by 

the owners of NGS. Depending on the 

magnitude of the required emission 

bridge, EPA anticipates that reductions 

could be achieved without expending 

substantial funds before the lease, NEPA 

review, and other processes are 

completed. Such reductions could be 

implemented as NOX reductions 

achieved annually in equal increments 

to meet the emissions bridge, or some 

other structure that achieves the total 

emission reductions at different 

intervals. Thus, EPA is soliciting 

comment on how NGS could achieve 

the emission reduction bridge necessary 

for these longer compliance schedules 

to meet the ‘‘better than BART’’ 

threshold and will supplement our 

proposal before an alternative with a 

compliance schedule beyond 2023 is 

finalized. 

TABLE 13—ANALYSIS OF ADDITIONAL ALTERNATIVES

BART Alternative 2 Alternative 3 

Installation Years .............................................. by 2018 .............................. 2023, 2024, and 2025 ............... 2024, 2025, and 2026. 

Total Emissions (tons) ..................................... 358,974 .............................. 466,869 ..................................... 484,849. 

LNB/SOFA Credit (tons) .................................. n/a ...................................... 92,175 ....................................... 92,175. 

Adjusted Emissions (tons) ............................... n/a ...................................... 374,154 ..................................... 392,134. 

Better than BART? ........................................... n/a ...................................... No .............................................. No. 

Emission Reduction Deficit (tons) .................... n/a ...................................... 15,179 ....................................... 33,160. 

Short-term Emission Bridge (tpy) .....................

(years in place) ................................................

n/a ...................................... 1,518 tpy over 2013–2023 ........ 3,015 tpy over 2013–2024. 


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TABLE 13—ANALYSIS OF ADDITIONAL ALTERNATIVES—Continued 

BART Alternative 2 Alternative 3 

Long-term Emission Bridge (tpy) .....................

(years in place) ................................................

n/a ...................................... 490 tpy over 2013–2044 ........... 1,070 tpy over 2013–2044. 

In summary, EPA is requesting 

comment on technically and 

economically feasible technologies or 

mechanisms to serve as enforceable 

emission reduction bridges (whether 

short or long term) that would allow 

consideration of alternatives that would 

not otherwise meet the ‘‘better than 

BART’’ threshold for NOX (e.g., 

Alternatives 2 or 3 or other alternatives 

suggested by stakeholders during the 

public comment period for this 

proposed rule). EPA also seeks comment 

on the schedule on which reductions 

from an emissions bridge would need to 

be achieved. If EPA receives proposals 

from stakeholders during the comment 

period that put forth a plan for specific 

emission reduction bridges to bring total 

emissions over 2009–2044 of an 

extended compliance schedule (beyond 

2023) at or below the ‘‘better than 

BART’’ threshold of 358,974 tons, EPA 

may issue a supplemental proposal for 

public comment. 

F. Solicitation of Comments 

EPA is requesting comment on our 

proposed level of BART control of 0.055 

lb/MMBtu for NOX. We are also 

requesting comment on our proposed 

BART Alternative 1 with a compliance 

timeframe of 2021–2023, resulting in 

greater reasonable progress than would 

otherwise be achieved under BART by 

crediting NGS for its early and 

voluntary installation of LNB/SOFA. 

EPA is requesting comment on 

Alternatives 2 and 3 that provide 

additional time for compliance and 

would require the owners of NGS to 

implement additional emission 

reductions in order to assure greater 

reasonable progress than would 

otherwise be achieved under BART. In 

particular, we are requesting comment 

from stakeholders on potential 

technologies that can serve to bridge the 

NOX emission reduction deficit for 

compliance schedules that do not, by 

themselves, meet the ‘‘better than 

BART’’ threshold (i.e., Alternatives 2 

and 3). EPA will publish a supplemental 

proposal before we would finalize any 

alternative that requires an emission 

reduction bridge to be ‘‘better than 

BART’’. 

In recognition of the importance of 

NGS to the local and regional economy 

and the multitude of interests and 

stakeholders involved, EPA is providing 

a 90-day comment period on this 

proposed rulemaking and will continue 

to engage in consultation with tribes 

located in Arizona during the 

rulemaking process. EPA seeks 

comment on the analysis and 

conclusions presented in this proposal 

and invites suggestions for other 

alternatives that reduce NOX emissions 

at NGS and its contribution to visibility 

impairment while providing long-term, 

sustainable benefits to tribes. 

IV. Administrative Requirements 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 13563 

This action proposes a source-specific 

FIP for the Navajo Generating Station on 

the Navajo Nation. Under the terms of 

Executive Order (EO) 12866 (58 FR 

51735, October 4, 1993) and EO 13563 

(76 FR 3821, January 21, 2011), because 

this proposed rule applies to only one 

facility, it is not a rule of general 

applicability. This proposed rule, 

therefore, is exempt from review under 

EO 12866 and EO 13563. 

B. Paperwork Reduction Act 

This action does not impose an 

information collection burden under the 

provisions of the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. Burden is 

defined at 5 CFR 1320.3(b). 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, Navajo Generating 

Station, the Paperwork Reduction Act 

does not apply. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of today’s proposed rule on small 

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

small business as defined by the Small 

Business Administration’s (SBA) 

regulations at 13 CFR 121.201; (2) a 

small governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

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

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

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of this proposed action on small 

entities, I certify that this proposed 

action will not have a significant 

economic impact on a substantial 

number of small entities. The Navajo 

Generating Station is not a small entity 

and the FIP for Navajo Generating 

Station being proposed today does not 

impose any compliance requirements on 

small entities. See Mid-Tex Electric 

Cooperative, Inc. v. FERC, 773 F.2d 327 

(D.C. Cir. 1985). We continue to be 

interested in the potential impacts of the 

proposed rule on small entities and 

welcome comments on issues related to 

such impacts. 

D. Unfunded Mandates Reform Act 

(UMRA) 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), 2 U.S.C. 

1531–1538, requires Federal agencies, 

unless otherwise prohibited by law, to 

assess the effects of their regulatory 

actions on State, local, and tribal 

governments and the private sector. 

Federal agencies must also develop a 

plan to provide notice to small 

governments that might be significantly 

or uniquely affected by any regulatory 

requirements. The plan must enable 

officials of affected small governments 

to have meaningful and timely input in 

the development of EPA regulatory 

proposals with significant Federal 

intergovernmental mandates and must 

inform, educate, and advise small 

governments on compliance with the 

regulatory requirements. 

This rule does not contain a Federal 

mandate that may result in expenditures 

of $100 million or more for state, local, 

and tribal governments, in the aggregate, 

or the private sector in any one year. 


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61See document titled: ‘‘Timeline of All Tribal 

Consultation on NGS.docx’’, in the docket for this 

proposed rulemaking. 

EPA anticipates the annual cost to the 

private sector of this proposed rule to be 

$64 million per year (see Table 2). Thus, 

this rule is not subject to the 

requirements of sections 202 or 205 of 

UMRA. This proposed rule will not 

impose direct compliance costs on state, 

local or tribal governments. This 

proposed action will, if finalized, 

reduce the emissions of NOX from a 

single source, the Navajo Generating 

Station. 

In developing this rule, EPA 

consulted with small governments 

pursuant to a plan established under 

section 203 of UMRA to address impacts 

of regulatory requirements in the rule 

that might significantly or uniquely 

affect small governments. EPA put forth 

an Advanced Notice of Proposed 

Rulemaking on August 28, 2009 

regarding our intention to propose a 

BART determination for NGS and the 

Four Corners Power Plant. We received 

comments from numerous small 

governments, including tribal 

governments, and governments of 

several towns in Arizona. This proposed 

rule will not impose direct compliance 

costs on any small governments. 

However, increased electricity and 

water costs associated with this 

proposed rule may indirectly affect 

small governments. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the states, on the 

relationship between the national 

government and the states, or in the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. This action 

proposes emission reductions of NOX at 

a specific stationary source located in 

Indian country. Thus, Executive Order 

13132 does not apply to this action. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

Under Executive Order 13175 (65 FR 

67249, November 9, 2000), EPA may not 

issue a regulation that has tribal 

implications, that imposes substantial 

direct compliance costs, and that is not 

required by statute, unless the federal 

government provides the funds 

necessary to pay the 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. 

EPA has concluded that this action 

will have tribal implications, and 

consequently EPA has consulted with 

tribal officials during the process of 

developing the proposed regulation. The 

proposed regulation will neither impose 

substantial direct compliance costs on 

tribal governments, nor pre-empt tribal 

law. However, several tribes located in 

Arizona have expressed concerns 

regarding the potential impact of this 

regulation on their economic interests. 

The Navajo Nation and Hopi Tribe 

focused on the significant contribution 

of coal-related royalties, taxes and 

employment at NGS and the Kayenta 

Mine to their economies. Comments 

from other Arizona tribes focused on the 

importance of NGS as a source of power 

to the CAP in order for the federal 

government to meet obligations under 

existing water settlement agreements. 

The importance to tribes of continued 

operation of NGS and affordable water 

costs cannot be overemphasized. In 

Section II.B.ii, EPA explains in detail 

the tribal information that we received 

and considered in this proposed 

rulemaking. 

In order to understand more fully the 

concerns of the tribes, senior level EPA 

officials from both Washington, DC and 

San Francisco have personally visited 

the NGS facility in Page, Arizona. EPA 

sent invitations to all tribes in Arizona 

to consult with EPA during the 

development of our BART 

determination for NGS. We received 

correspondence and comments on our 

ANPRM from officials of numerous 

tribes, including the Navajo Nation, the 

Hopi Tribe, the Gila River Indian 

Community, the Ak-Chin Indian 

Community, the Tohono O’odham 

Nation, the Fort McDowell Indian 

Community, the Pascua Yaqui Tribe, 

and the Salt River-Pima Maricopa 

Indian Community. On September 16, 

2011, and February 8, 2012, EPA held 

consultation sessions about NGS with 

representatives from approximately 

eleven tribes participating in one or 

both meetings. Additionally, EPA had 

in-person consultation meetings with 

tribal representatives prior to this 

proposal on August 7 and August 27, 

2012. Representatives from nine tribes 

attended. In addition to formal 

consultation, EPA has had numerous 

meetings and conference calls with 

tribes at their request throughout the 

process of developing the action we are 

proposing today. A timeline of all 

correspondence and consultation with 

tribes on NGS is included in the docket 

for this proposed rulemaking.61 EPA 

will continue to consult with Tribal 

officials during the public comment 

period on the proposed FIP. Several 

tribes, including the Navajo, submitted 

comments which EPA considered in 

developing this proposed action. 

Therefore, EPA has allowed tribes to 

provide meaningful and timely input 

into the development of this proposed 

rule and will continue to consult with 

affected tribes prior to finalizing our 

BART determination or any alternative 

to BART. The technical support 

document for this proposed rulemaking 

provides a detailed discussion of 

comments received from tribes during 

the comment period for the ANPRM and 

subsequent consultation and 

correspondence, and EPA’s responses to 

those comments. 

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 

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 NOX

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 NOX, 

which contribute to ozone and fine 

particulate matter formation as well as 

visibility impairment, the rule will have 

a beneficial effect on children’s health 

be 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 exempt under 

Executive Order 12866. 


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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. 

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 NOX from a single 

stationary source, Navajo Generating 

Station. 

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: January 17, 2013. 

Jared Blumenfeld, 

Regional Administrator, Region 9. 

Title 40, chapter I of the Code of 

Federal Regulations is proposed to be 

amended as follows: 

PART 49—[INDIAN COUNTRY: AIR 

QUALITY PLANNING AND 

MANAGEMENT] 

■ 1. The authority citation for part 49 

continues to read as follows: 

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

■ 2. Section 49.5513 is amended by 

adding paragraph (j) to read as follows: 

§ 49.5513 Federal Implementation Plan 

Provisions for Navajo Generating Station, 

Navajo Nation. 

* * * * * 

(j)(1) Applicability. Regional Haze 

Best Available Retrofit Technology 

limits for this plant are in addition to 

the requirements of paragraphs (a) 

through (i) of this section. The 

provisions of this paragraph (j) are 

severable, and if any provision of this 

paragraph (j), or the application of any 

provision of this paragraph (j) to any 

owner/operator or circumstance, is held 

invalid, the application of such 

provision to other owner/operators and 

other circumstances, and the remainder 

of this paragraph (j), shall not be 

affected thereby. 

(2) Definitions. Terms not defined in 

this paragraph (j)(2) shall have the 

meaning given to them in the Clean Air 

Act or EPA’s regulations implementing 

the Clean Air Act and in paragraph (c) 

of this section. For purposes of this 

paragraph (j): 

(i) Boiler operating day means a 24- 

hour period between 12 midnight and 

the following midnight during which 

any fuel is combusted at any time in the 

steam-generating unit. It is not 

necessary for fuel to be combusted the 

entire 24-hour period. 

(ii) Coal-fired unit means any of Units 

1, 2, or 3 at Navajo Generating Station. 

(iii) Continuous emission monitoring 

system or CEMS means the equipment 

required by 40 CFR Part 75 and this 

paragraph (j). 

(iv) Emissions limitation or emissions 

limit means the federal emissions 

limitation required by this section. 

(v) Group of coal-fired units means 

Units 1, 2 and 3 at Navajo Generating 

Station. 

(vi) lb means pound(s). 

(vii) NOX means nitrogen oxides 

expressed as nitrogen dioxide (NO2). 

(viii) Owner(s)/operator(s) means any 

person(s) who own(s) or who operate(s), 

control(s), or supervise(s) one more of 

the units of the Navajo Generating 

Station. 

(ix) MMBtu means million British 

thermal unit(s). 

(x) Operating hour means any hour 

that fossil fuel is fired in the unit. 

(xi) Unit means any of Units 1, 2, or 

3 at Navajo Generating Station. 

(xii) Valid data means CEMs data that 

is not out of control as defined in 40 

CFR Part 75. 

(3) Compliance date. The owner/ 

operator may elect to comply with the 

NOX emission limitations in this 

paragraph (j) either: 

(i) Within five years of the effective 

date of the final rulemaking, or 

(ii) On one coal-fired unit per year by 

2021, 2022, and 2023. 

(4) NOX emission limitations. The 

owner/operator of each coal-fired unit 

subject to this paragraph (j) shall not 

emit or cause to be emitted NOX in 

excess of the following: 

(i) Under paragraph (j)(3)(i) of this 

section: within 5 years of the effective 

of the final rule, 0.055 pounds per 

million British thermal units (lb/ 

MMBtu) from any group of coal-fired 

units, averaged on a rolling average 

basis over 30-boiler-operating days. 

(ii) Under paragraph (j)(3)(ii) of this 

section: 

(A) After 2021, 0.178 lb/MMBtu from 

any group of coal-fired units, averaged 

on a rolling basis over 30-boileroperating days. 

(B) After 2022, 0.117 lb/MMBtu from 

any group of coal-fired units, averaged 

on a rolling basis over 30-boileroperating days. 

(C) On and thereafter 2023, 0.055 lb/ 

MMBtu from any group of coal-fired 

units, averaged on a rolling basis over 

30-boiler-operating days. 

(5) Continuous emission monitoring 

system. (i) At all times after the dates 


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specified in paragraph (j)(3) of this 

section, the owner/operator of each unit 

shall maintain, calibrate, and operate a 

CEMS, in full compliance with the 

requirements found at 40 CFR Part 75, 

to accurately measure NOX, diluent, and 

stack gas volumetric flow rate from each 

unit. Valid data means data recorded 

when the CEMS is not out-of-control as 

defined by Part 75, as defined in 

paragraph (j)(2) of this section. All valid 

CEMS hourly data shall be used to 

determine compliance with the 

emission limitations for NOX in 

paragraph (j)(4) of this section for each 

unit. If the CEMs data is not valid, that 

CEMs data shall be treated as missing 

data and not used to calculate the 

emission average. CEMs data does not 

need to be bias adjusted as defined in 

40 CFR Part 75. Each required CEMS 

must obtain valid data for at least 90 

percent of the unit operating hours, on 

an annual basis. 

(ii) The owner/operator of each unit 

shall comply with the quality assurance 

procedures for CEMS found in 40 CFR 

Part 75. In addition to these Part 75 

requirements, relative accuracy test 

audits shall be calculated for both the 

NOX pounds per hour measurement and 

the heat input measurement. The 

calculation of NOX pounds per hour and 

heat input relative accuracy shall be 

evaluated each time the CEMS undergo 

relative accuracy testing. 

(6) Compliance Determination for 

NOX. (i) The 30-day rolling average NOX

emission rate for each group of coalfired units shall be calculated for each 

calendar day, even if a unit is not in 

operation on that calendar day, in 

accordance with the following 

procedure: step one, for each unit, sum 

the hourly pounds of NOX emitted 

during the current boiler-operating day 

(or most recent boiler-operating day if 

the unit is not in operation), and the 

preceding twenty-nine (29) boileroperating days, to calculate the total 

pounds of NOX emitted over the most 

recent thirty (30) boiler-operating day 

period for each coal-fired unit; step two, 

for each unit, sum the hourly heat input, 

in MMBtu, during the current boileroperating day (or most recent boileroperating day if the unit is not in 

operation), and the preceding twentynine (29) boiler-operating days, to 

calculate the total heat input, in 

MMBtu, over the most recent thirty (30) 

boiler-operating day period for each 

coal-fired unit; step 3, sum together the 

total pounds of NOX emitted from the 

group of coal-fired units over each unit’s 

most recent thirty (30) boiler-operating 

day period (the most recent 30 boileroperating day periods for different units 

may be different); step four, sum 

together the total heat input from the 

group of coal-fired units over each unit’s 

most recent thirty (30) boiler-operating 

day period; and step five, divide the 

total pounds of NOX emitted from step 

three by the total heat input from step 

four for each group of coal-fired units, 

to calculate the 30-day rolling average 

NOX emission rate for each group of 

coal-fired units, in pounds of NOX per 

MMBtu, for each calendar day. Each 30- 

day rolling average NOX emission rate 

shall include all emissions and all heat 

input that occur during all periods 

within any boiler-operating day, 

including emissions from startup, 

shutdown, and malfunction. 

(ii) If a valid NOX pounds per hour or 

heat input is not available for any hour 

for a unit, that heat input and NOX

pounds per hour shall not be used in the 

calculation for that 30 boiler operating 

day period. 

(7) Recordkeeping. The owner or 

operator of each unit shall maintain the 

following records for at least five years: 

(i) All CEMS data, including the date, 

place, and time of sampling or 

measurement; parameters sampled or 

measured; and results as required by 

Part 75 and as necessary to calculate 

each units pounds of NOX and heat 

input for each hour. 

(ii) Each calendar day rolling average 

group emission rates for NOX calculated 

in accordance with paragraph (j)(5)(i) of 

this section. 

(iii) Each unit’s 30 boiler operating 

day pounds of NOX and heat input. 

(iv) Records of quality assurance and 

quality control activities for emissions 

measuring systems including, but not 

limited to, any records required by 40 

CFR Part 75. 

(v) Records of the relative accuracy 

calculation of the NOX lb/hr 

measurement and hourly heat input. 

(vi) Records of all major maintenance 

activities conducted on emission units, 

air pollution control equipment, and 

CEMS. 

(vii) Any other records required by 40 

CFR Part 75. 

(8) Reporting. All reports and 

notifications under this paragraph (j) 

shall be submitted to the Director, 

Navajo Environmental Protection 

Agency, P.O. Box 339, Window Rock, 

Arizona 86515, and to the Director of 

Enforcement Division, U.S. EPA Region 

IX, at 75 Hawthorne Street, San 

Francisco, CA 94105. (i) The owner/ 

operator shall notify EPA within two 

weeks after completion of installation of 

NOX control technology on any of the 

units subject to this section. 

(ii) Within 30 days after the first 

applicable compliance date in 

paragraph (j)(3) of this section and 

within 30 days of every second calendar 

quarter thereafter (i.e., semi-annually), 

the owner/operator shall submit a report 

that lists for each calendar day, 

calculated in accordance with paragraph 

(j)(6) of this section, total lb of NOX and 

heat input (as used to calculate 

compliance per paragraph (j)(4) of this 

section, for each unit’s last 30 boiler 

operating days. Included in this report 

shall be the results of the last relative 

accuracy test audit and the calculated 

relative accuracy for lb/hr NOX and heat 

input performed 45 days prior to the 

end of that reporting period. The end of 

the year report shall also include the 

percent valid data for each NOX, 

diluent, and flow monitor used in the 

calculations of compliance with 

paragraph (j)(4) of this section. 

(9) Enforcement. Notwithstanding any 

other provision in this implementation 

plan, any credible evidence or 

information relevant as to whether the 

unit would have been in compliance 

with applicable requirements if the 

appropriate performance or compliance 

test had been performed, can be used to 

establish whether or not the owner or 

operator has violated or is in violation 

of any standard or applicable emission 

limit in the plan. 

(10) Equipment Operations. At all 

times, including periods of startup, 

shutdown, and malfunction, the owner 

or operator shall, to the extent 

practicable, maintain and operate the 

unit including associated air pollution 

control equipment in a manner 

consistent with good air pollution 

control practices for minimizing 

emissions. Determination of whether 

acceptable operating and maintenance 

procedures are being used will be based 

on information available to the Regional 

Administrator, or their designee, which 

may include, but is not limited to, 

monitoring results, review of operating 

and maintenance procedures, and 

inspection of the unit. 

(11) The affirmative defense 

provisions of paragraphs (c)(1) and (g)(3) 

of this section, related only to 

malfunctions, apply to this paragraph 

(j). 

[FR Doc. 2013–01858 Filed 2–4–13; 8:45 am] 

BILLING CODE 6560–50–P 


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