Federal Register / Vol. 76, No. 3 / Wednesday, January 5, 2011 / Proposed Rules 491 

1 14 CFR 77.13(a), paragraphs (2), (3), (4) and (5) 

are not relevant to this issue. 

Consistent with the above statutory 

and regulatory framework, the FAA has 

adopted policy to establish the 

standards for which the FAA identifies 

‘‘obstructions’’ and ‘‘hazards’’ in the 

navigable airspace in furtherance of its 

responsibilities to manage the navigable 

airspace safely and efficiently. See 14 

CFR part 77, and FAA Order 7400.2, 

Procedures for Handling Airspace 

Matters. The FAA issues a 

determination advising whether the 

structure would be a hazard to air 

navigation. The FAA may condition its 

determination of no hazard with the 

structure appropriately being marked 

and lighted, as specified in the 

determination. FAA criteria for marking 

and lighting of tall structures are found 

in Advisory Circular No. 70/7460–1, 

Obstruction Marking and Lighting. 

Unless within the vicinity of an 

airport,1 proponents of new structures 

or alterations of existing structures must 

file notice with the FAA for ‘‘any 

construction or alteration of more than 

200 feet in height above the ground 

level at its site.’’ 14 CFR 77.13(a)(1). 

Consequently, as the FAA does not 

study these structures there is no FAA 

determination that would specify the 

marking of these structures. 

Background 

The emphasis to discover sources of 

renewable energy in the United States 

has prompted individuals and 

companies to explore all means of 

energy generation. Wind energy, 

converted into electrical energy by wind 

turbines, is widely pursued as a viable 

alternative. In order to determine if a 

site meets requirements to construct a 

wind turbine or wind farm, companies 

erect METs. These towers are used to 

gather wind data necessary for site 

evaluation and development of wind 

energy projects. The data generally is 

gathered over a year to ascertain if the 

targeted area represents a potential 

location for the installation of wind 

turbines. 

Requirements to file notice under part 

77 generally do not apply to structures 

at heights lower than 200 feet AGL 

unless close to an airport environment. 

Therefore, the FAA does not have a 

database of MET locations, nor does it 

conduct an aeronautical study to 

determine whether the particular 

structure would be hazardous to 

aviation. These towers are often 

installed in remote or rural areas, just 

under 200 feet above ground level 

(AGL), usually at 198 feet or less. These 

structures are portable, erected in a 

matter of hours, installed with guyed 

wires and constructed from a galvanized 

material often making them difficult to 

see in certain atmospheric conditions. 

While the METs described above are 

not subject to the provisions of part 77 

and therefore, the FAA does not 

conduct aeronautical studies to 

determine whether these structures are 

obstructions and adversely impact air 

navigation, the FAA does acknowledge 

that these towers under certain 

conditions may be difficult to see by 

low-level agricultural flights operating 

under visual flight rules. The color, 

portability of these towers, their 

placement in rural and remote areas, 

and their ability to be erected quickly 

are factors that pilots should be aware 

of when conducting operations in these 

areas. 

The FAA has received complaints and 

inquiries from agricultural operations in 

remote or rural areas regarding the 

safety impacts of these towers on lowlevel agricultural operations. In 

addition, representatives from the 

National Agricultural Aviation 

Association (NAAA) met with the FAA 

on November 16, 2010 to discuss safety 

specific concerns of the aerial 

application industry. The NAAA 

suggested safety guidelines and marking 

and lighting criteria in order to reduce 

the risks for aerial applications. A copy 

of the material provided by NAAA has 

been placed in the docket. 

Proposed Guidance 

The FAA is considering revising AC 

No. 70/7460–1, Obstruction Marking 

and Lighting, to include guidance for 

the voluntary marking of METs that are 

less than 200 feet AGL. The FAA 

recognizes the need to enhance the 

conspicuity of these METs, particularly 

for low-level agricultural operations and 

seeks public comment on the guidance 

provided below. 

The FAA recommends that the towers 

be painted in accordance to the marking 

criteria contained in Chapter 3, 

paragraphs 30–33 of AC No. 70/7460–1. 

In particular, we reference paragraph 

33(d), which discusses alternate bands 

of aviation orange and white paint for 

skeletal framework of storage tanks and 

similar structures, and towers that have 

cables attached. The FAA also 

recommends spherical and/or flag 

markers be used in addition to aviation 

orange and white paint when additional 

conspicuity is necessary. Markers 

should be installed and displayed 

according to the existing standards 

contained in Chapter 3, paragraph 34 of 

AC No. 70/70460–1. 

The FAA is also considering 

recommending high visibility sleeves on 

the outer guy wires of these METs. 

While the current Obstruction Marking 

and Lighting Advisory Circular does not 

contain such guidance for high visibility 

sleeves, the FAA specifically seeks 

comments on this recommendation. 

The FAA anticipates that a uniform 

and consistent scheme for voluntarily 

marking these METs would enhance 

safety by making these towers more 

readily identifiable for agricultural 

operations. 

Issued in Washington, DC, on December 

29, 2010. 

Edith V. Parish, 

Manager, Airspace, Regulations and ATC 

Procedures Group. 

[FR Doc. 2010–33310 Filed 1–4–11; 8:45 am] 

BILLING CODE 4910–13–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R06–OAR–2010–0846; FRL–9246–8] 

Approval and Promulgation of 

Implementation Plans; New Mexico; 

Federal Implementation Plan for 

Interstate Transport of Pollution 

Affecting Visibility and Best Available 

Retrofit Technology Determination 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: EPA is proposing to 

disapprove a portion of the State 

Implementation Plan (SIP) revision 

submitted by the State of New Mexico 

for the purpose of addressing the ‘‘good 

neighbor’’ requirements of section 

110(a)(2)(D)(i) of the Clean Air Act 

(CAA or Act) for the 1997 8-hour ozone 

National Ambient Air Quality Standards 

(NAAQS or standards) and the 1997 fine 

particulate matter (PM2.5) NAAQS. The 

SIP revision addresses the requirement 

that New Mexico’s SIP must have 

adequate provisions to prohibit 

emissions from adversely affecting 

another state’s air quality through 

interstate transport. In this action, EPA 

is proposing to disapprove the New 

Mexico Interstate Transport SIP 

provisions that address the requirement 

of section 110(a)(2)(D)(i)(II) that 

emissions from New Mexico sources do 

not interfere with measures required in 

the SIP of any other state under part C 

of the CAA to protect visibility. In this 

action, EPA is also proposing to 

promulgate a Federal Implementation 

Plan (FIP) to prevent emissions from 

New Mexico sources from interfering 

with other states’ measures to protect 


srobinson on DSKHWCL6B1PROD with PROPOSALS
492 Federal Register / Vol. 76, No. 3 / Wednesday, January 5, 2011 / Proposed Rules 

visibility, and to implement nitrogen 

oxides (NOX) and sulfur dioxide (SO2) 

emission limits necessary at one source 

to prevent such interference. In 

addition, EPA is proposing sulfuric acid 

(H2SO4) and ammonia (NH3) hourly 

emission limits at the same source, to 

minimize the contribution of these 

compounds to visibility impairment. 

EPA is proposing monitoring, 

recordkeeping and reporting 

requirements to ensure compliance with 

such emission limitations. EPA also 

proposes that compliance with the 

emission limits be within three (3) years 

of the effective date of our final rule. 

Furthermore, EPA is proposing the FIP 

to address the requirement for best 

available retrofit technology (BART) for 

NOX for this source. This action is being 

taken under section 110 and part C of 

the CAA. 

DATES: Comments. Comments must be 

received on or before March 7, 2011. 

Public Hearing. EPA intends to hold 

a public hearing in Farmington, New 

Mexico to accept oral and written 

comments on the proposed rulemaking. 

EPA will provide notice and additional 

details at least 30 days prior to the 

hearing in the Federal Register. 

ADDRESSES: Submit your comments, 

identified by Docket No. EPA–R06– 

OAR–2010–0846, by one of the 

following methods: 

• Federal e-Rulemaking Portal: 

http://www.regulations.gov. 

• Follow the online instructions for 

submitting comments. 

• EPA Region 6 ‘‘Contact Us’’ Web 

site: http://epa.gov/region6/ 

r6coment.htm. Please click on ‘‘6PD 

(Multimedia)’’ and select ‘‘Air’’ before 

submitting comments. 

• E-mail: Mr. Guy Donaldson at 

donaldson.guy@epa.gov. Please also 

send a copy by e-mail to the person 

listed in the FOR FURTHER INFORMATION

CONTACT section below. 

• Fax: Mr. Guy Donaldson, Chief, Air 

Planning Section (6PD–L), at fax 

number 214–665–7263. 

• Mail: Mr. Guy Donaldson, Chief, 

Air Planning Section (6PD–L), 

Environmental Protection Agency, 1445 

Ross Avenue, Suite 1200, Dallas, Texas 

75202–2733. 

• Hand or Courier Delivery: Mr. Guy 

Donaldson, Chief, Air Planning Section 

(6PD–L), Environmental Protection 

Agency, 1445 Ross Avenue, Suite 1200, 

Dallas, Texas 75202–2733. Such 

deliveries are accepted only between the 

hours of 8 a.m. and 4 p.m. weekdays, 

and not on legal holidays. Special 

arrangements should be made for 

deliveries of boxed information. 

Instructions: Direct your comments to 

Docket No. EPA–R06–OAR–2010–0846. 

EPA’s policy is that all comments 

received will be included in the public 

docket without change and may be 

made available online at http:// 

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through http:// 

www.regulations.gov or e-mail. The 

http://www.regulations.gov Web site is 

an ‘‘anonymous access’’ system, which 

means EPA will not know your identity 

or contact information unless you 

provide it in the body of your comment. 

If you send an e-mail comment directly 

to EPA without going through http:// 

www.regulations.gov your e-mail 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, EPA may not be 

able to consider your comment. 

Electronic files should avoid the use of 

special characters, any form of 

encryption, and be free of any defects or 

viruses. 

Docket: All documents in the docket 

are listed in the http:// 

www.regulations.gov index. Although 

listed in the index, some information is 

not publicly available, e.g., CBI or other 

information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

will be publicly available only in hard 

copy. Publicly available docket 

materials are available either 

electronically in http:// 

www.regulations.gov or in hard copy at 

the Air Planning Section (6PD–L), 

Environmental Protection Agency, 1445 

Ross Avenue, Suite 700, Dallas, Texas 

75202–2733. The file will be made 

available by appointment for public 

inspection in the Region 6 FOIA Review 

Room between the hours of 8:30 a.m. 

and 4:30 p.m. weekdays except for legal 

holidays. Contact the person listed in 

the FOR FURTHER INFORMATION CONTACT

paragraph below or Mr. Bill Deese at 

214–665–7253 to make an appointment. 

If possible, please make the 

appointment at least two working days 

in advance of your visit. There will be 

a 15 cent per page fee for making 

photocopies of documents. On the day 

of the visit, please check in at the EPA 

Region 6 reception area at 1445 Ross 

Avenue, Suite 700, Dallas, Texas. 

The state submittal is also available 

for public inspection during official 

business hours, by appointment, at the 

New Mexico Environment Department, 

Air Quality Bureau, 1301 Siler Road, 

Building B, Santa Fe, New Mexico 

87507. 

FOR FURTHER INFORMATION CONTACT: Joe 

Kordzi, Air Planning Section (6PD–L), 

Environmental Protection Agency, 

Region 6, 1445 Ross Avenue, Suite 700, 

Dallas, Texas 75202–2733, telephone 

(214) 665–7186, fax number (214) 665– 

7263; e-mail address 

kordzi.joe@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Throughout this document wherever 

‘‘we,’’ ‘‘us,’’ or ‘‘our’’ is used, we mean the 

EPA. 

Outline 

I. Overview of Proposed Action 

II. Background 

A. SIP and FIP Background 

B. Statutory and Regulatory Framework 

Addressing Interstate Transport and 

Visibility 

1. The 1997 NAAQS for Ozone and PM2.5

and CAA 110(a)(2)(D)(i) 

2. Visibility Protection 

3. Best Available Retrofit Technology 

4. The Western Regional Air Partnership 

and Evaluation of Regional Haze Impacts 

III. Our Evaluation 

A. New Mexico’s Interstate Transport 

B. Federal Implementation Plan To 

Address Interstate Transport and 

Visibility and the BART Requirements 

for NOX

1. Additional SO2 Emission Limits for the 

SJGS 

2. Need for Additional NOX Controls 

3. NOX BART Evaluation 

a. The SJGS Is a BART Eligible Source 

b. The SJGS Is Subject to BART 

c. The SJGS NOX BART Determination 

IV. Proposed Action 

V. Statutory and Executive Order Reviews 

I. Overview of Proposed Action 

We are proposing to disapprove a 

portion of the SIP revision submitted by 

the State of New Mexico for the purpose 

of addressing the ‘‘good neighbor’’ 

provisions of the CAA section 

110(a)(2)(D)(i) with respect to visibility 

for the 1997 8-hour ozone NAAQS and 

the PM2.5 NAAQS. As a result of the 

proposed disapproval, we are also 

proposing a FIP to address the 

requirements of section 

110(a)(2)(D)(i)(II) with respect to 

visibility to ensure that emissions from 

New Mexico sources do not interfere 

with the visibility programs of other 

states. We are proposing to find that 

New Mexico sources, other than one, are 


srobinson on DSKHWCL6B1PROD with PROPOSALS
Federal Register / Vol. 76, No. 3 / Wednesday, January 5, 2011 / Proposed Rules 493 

1Unless otherwise specified, when we say the 

‘‘San Juan Generating Station,’’ or ‘‘SJGS,’’ we mean 

units 1, 2, 3, and 4, inclusive. 

2Power Plants Section, Four Corners Air Quality 

Task Force, Report of Mitigation Options, 

November 1, 2007, available at: http:// 

www.nmenv.state.nm.us/aqb/4C/Docs/ 

4CAQTF_Report_FINAL_PowerPlants.pdf. 

sufficiently controlled to eliminate 

interference with the visibility programs 

of other states, and for the one 

remaining source we are proposing to 

impose specific emissions limits that 

will eliminate such interstate 

interference. We are simultaneously 

evaluating whether the source at issue 

meets certain other related requirements 

under the Regional Haze (RH) program. 

As a result of this evaluation, we are 

likewise proposing to find that the 

proposed controls for the source at issue 

will address the NOX BART 

requirements of the RH program. In this 

action, we are not addressing whether 

the state has met other requirements of 

the RH program and will address those 

requirements in later actions. 

Section 110(a)(2)(D)(i)(II) of the Act 

requires that states have a SIP, or submit 

a SIP revision, containing provisions 

‘‘prohibiting any source or other type of 

emission activity within the state from 

emitting any air pollutant in amounts 

which will * * * interfere with 

measures required to be included in the 

applicable implementation plan for any 

other State under part C [of the CAA] to 

protect visibility.’’ 

Because of the impacts on visibility 

from the interstate transport of 

pollutants, we interpret the ‘‘good 

neighbor’’ provisions of section 110 of 

the Act described above as requiring 

states to include in their SIPs measures 

to prohibit emissions that would 

interfere with the reasonable progress 

goals set to protect Class I areas in other 

states. New Mexico submitted a SIP to 

address these requirements in 

September 2007. In this action, we are 

proposing to disapprove the New 

Mexico SIP submission as not meeting 

the requirements of section 

110(a)(2)(D)(i)(II) with respect to 

visibility. The SIP submission made by 

the state anticipated the timely 

submission of a substantive RH SIP 

submission as the means of meeting the 

requirements of section 

110(a)(2)(D)(i)(II). New Mexico has yet 

to submit such a RH SIP. In addition, 

the state has not revised its submission 

to address the requirements of section 

110(a)(2)(D)(i)(II) with respect to 

visibility by any alternative means. 

By December 17, 2007, each State 

with one or more Class I Federal areas 

was also required to submit a RH SIP 

that included goals that provide for 

reasonable progress towards achieving 

natural visibility conditions. 40 CFR 

51.308(d)(1). We previously found that 

New Mexico had failed to submit a 

complete RH SIP by December 17, 2007. 

74 FR 2392 (January 15, 2009). This 

finding started a two year clock for the 

promulgation of a RH FIP by EPA or the 

approval of a complete RH SIP from 

New Mexico. CAA § 110(c)(1). 

To address the above concerns, we are 

also proposing to promulgate a FIP that 

ensures that emissions from New 

Mexico sources do not interfere with 

other states’ measures to protect 

visibility in accordance with section 

110(a)(2)(D)(i)(II) for the 1997 8-hour 

ozone and 1997 PM2.5 NAAQS, and also 

to address the requirements under the 

RH program for BART by imposing 

limits for NOX for the San Juan 

Generating Station (SJGS).1 This FIP 

will limit the emissions of SO2 and NOX

from the SJGS. Together, the reduction 

in NOX from our proposed NOX BART 

determination, and the proposed SO2

emission limits to establish federal 

enforceability of current SO2 levels will 

serve to ensure there are enforceable 

mechanisms in place to prohibit New 

Mexico NOX and SO2 emissions from 

interfering with efforts to protect 

visibility in other states pursuant to the 

requirements of section 

110(a)(2)(D)(i)(II) of the CAA. NOX and 

SO2 are significant contributors to 

visibility impairment in and around 

New Mexico. As the Four Corners Task 

Force notes,2 ‘‘[r]eduction of NOX is 

particularly important to improve 

visibility at Mesa Verde National Park, 

which is 43 km away from SJGS. * * * 

[V]isibility has degraded at Mesa Verde 

over the past decade, and the portion of 

degradation due to nitrate has increased 

(while there has been no trend in 

degradation due to sulfate).’’ For NOX

emissions, we are proposing to require 

the SJGS to meet an emission limit of 

0.05 pounds per million British Thermal 

Units (lb/MMBtu) at Units 1, 2, 3, and 

4, representing an approximately 83% 

reduction from the SJGS’s baseline NOX

emissions. This NOX limit is achievable 

by installing and operating Selective 

Catalytic Reduction (SCR). For SO2, we 

are proposing to require the SJGS to 

meet an emission limit of 0.15 lb/ 

MMBtu. Both of these emission limits 

would be measured on the basis of a 

30-day rolling average. We are also 

proposing hourly average emission 

limits for sulfuric acid (H2SO4) and 

ammonia (NH3) for the SJGS, to 

minimize the contribution of these 

compounds to visibility impairment of 

Class I areas. 

Furthermore, we propose that 

compliance with the emission limits be 

within three (3) years of the effective 

date of our final rule. Additionally, we 

are proposing monitoring, 

recordkeeping, and reporting 

requirements to ensure compliance with 

emission limitations. Please see Section 

IV (Proposed Action) and the proposed 

regulation language at the end of this 

Federal Register action for more 

information. 

II. Background 

A. SIP and FIP Background 

The CAA requires each state to 

develop a plan that provides for the 

implementation, maintenance, and 

enforcement of the NAAQS. CAA 

section 110(a). We establish NAAQS 

under section 109 of the CAA. 

Currently, the NAAQS address six (6) 

criteria pollutants: Carbon monoxide, 

nitrogen dioxide, ozone, lead, 

particulate matter, and sulfur dioxide. 

The plan developed by a state is referred 

to as the SIP. The content of the SIP is 

specified in section 110 of the CAA, 

other provisions of the CAA, and 

applicable regulations. A primary 

purpose of the SIP is to provide the air 

pollution regulations, control strategies, 

and other means or techniques 

developed by the state to ensure that the 

ambient air within that state meets the 

NAAQS. However, another important 

aspect of the SIP is to ensure that 

emissions from within the state do not 

have certain prohibited impacts upon 

the ambient air in other states through 

the interstate transport of pollutants. 

CAA section 110(a)(2)(D)(i). States are 

required to update or revise SIPs under 

certain circumstances. See CAA section 

110(a)(1). One such circumstance is our 

promulgation of a new or revised 

NAAQS. Id. Each state must submit 

these revisions to us for approval and 

incorporation into the federallyenforceable SIP. 

If a State fails to make a required SIP 

submittal or if we find that the State’s 

submittal is incomplete or 

unapprovable, then we must promulgate 

a FIP to fill this regulatory gap. CAA 

section 110(c)(1). As discussed 

elsewhere in this notice, we have made 

findings related to New Mexico SIP 

revisions needed to address interstate 

transport and the requirement that 

emissions from New Mexico sources do 

not interfere with measures required in 

the SIP of any other state to protect 

visibility, pursuant to section 

110(a)(2)(D)(i)(II) of the CAA. We are 

proposing a FIP to address the 

deficiencies in the New Mexico 

Interstate Transport SIP. 


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494 Federal Register / Vol. 76, No. 3 / Wednesday, January 5, 2011 / Proposed Rules 

3Areas designated as mandatory Class I Federal 

areas consist of national parks exceeding 6,000 

acres, wilderness areas and national memorial parks 

exceeding 5,000 acres, and all international parks 

that were in existence on August 7, 1977. CAA 

section 162(a). In accordance with section 169A of 

the CAA, EPA, in consultation with the Department 

of Interior, promulgated a list of 156 areas where 

visibility is identified as an important value. See 44 

FR 69122 (November 30, 1979). The extent of a 

mandatory Class I area includes subsequent changes 

in boundaries, such as park expansions. CAA 

section 162(a). Although states and tribes may 

designate as Class I additional areas which they 

consider to have visibility as an important value, 

the requirements of the visibility program set forth 

in section 169A of the CAA apply only to 

‘‘mandatory Class I Federal areas.’’ Each mandatory 

Class I Federal area is the responsibility of a 

‘‘Federal Land Manager’’ (FLM). CAA section 302(i). 

When we use the term ‘‘Class I area’’ in this action, 

we mean a ‘‘mandatory Class I Federal area.’’ 

B. Statutory and Regulatory Framework 

Addressing Interstate Transport and 

Visibility 

1. The 1997 NAAQS for Ozone and 

PM2.5 and CAA 110(a)(2)(D)(i) 

On July 18, 1997, we promulgated 

new NAAQS for 8-hour ozone and for 

PM2.5. 62 FR 38652. Section 110(a)(1) of 

the CAA requires states to submit SIPs 

to address a new or revised NAAQS 

within 3 years after promulgation of 

such standards, or within such shorter 

period as we may prescribe. Section 

110(a)(2) of the CAA lists the elements 

that such new SIPs must address, as 

applicable, including section 

110(a)(2)(D)(i), which pertains to the 

interstate transport of certain emissions. 

On April 25, 2005, we published a 

‘‘Finding of Failure to Submit SIPs for 

Interstate Transport for the 8-hour 

Ozone and PM2.5 NAAQS.’’ 70 FR 

21147. This included a finding that New 

Mexico and other states had failed to 

submit SIPs for interstate transport of air 

pollution affecting visibility, and started 

a 2-year clock for the promulgation of a 

FIP by us, unless a State made a 

submission to meet the requirements of 

section 110(a)(2)(D)(i) and we approved 

the submission. Id. 

On August 15, 2006, we issued our 

‘‘Guidance for State Implementation 

Plan (SIP) Submission to Meet Current 

Outstanding Obligations Under Section 

110(a)(2)(D)(i) for the 8-Hour Ozone and 

PM2.5 National Ambient Air Quality 

Standards’’ (2006 Guidance). We 

developed the 2006 Guidance to make 

recommendations to states for making 

submissions to meet the requirements of 

section 110(a)(2)(D)(i) for the 1997 8- 

hour ozone standards and the 1997 

PM2.5 standards. 

As identified in the 2006 Guidance, 

the ‘‘good neighbor’’ provisions in 

section 110(a)(2)(D)(i) of the CAA 

require each state to submit a SIP that 

prohibits emissions that adversely affect 

another state in the ways contemplated 

in the statute. Section 110(a)(2)(D)(i) 

contains four distinct requirements 

related to the impacts of interstate 

transport. The SIP must prevent sources 

in the state from emitting pollutants in 

amounts which will: (1) Contribute 

significantly to nonattainment of the 

NAAQS in other states; (2) interfere 

with maintenance of the NAAQS in 

other states; (3) interfere with provisions 

to prevent significant deterioration of air 

quality in other states; or (4) interfere 

with efforts to protect visibility in other 

states. 

The 2006 Guidance stated that states 

may make a simple SIP submission 

confirming that it was not possible at 

that time to assess whether there is any 

interference with measures in the 

applicable SIP for another state 

designed to ‘‘protect visibility’’ for the 

8-hour ozone and PM2.5 NAAQS until 

RH SIPs are submitted and approved. 

RH SIPs were required to be submitted 

by December 17, 2007. See 74 FR 2392 

(January 15, 2009); see also discussion 

infra section II.B.2. 

On September 17, 2007 we received a 

SIP from New Mexico to address the 

interstate transport provisions of CAA 

110(a)(2)(D)(i) for the 1997 8-hour ozone 

and PM2.5 NAAQS. In this submission, 

the state indicated that it intended to 

meet the requirements of section 

110(a)(2)(D)(i)(II) with respect to 

visibility by submission of a timely RH 

SIP. To date, the state has not made a 

RH SIP submission. In addition, the 

state has not made a submission 

demonstrating noninterference with the 

visibility programs of other states in 

accordance with section 

110(a)(2)(D)(i)(II) by any other means. 

In prior actions, we approved the New 

Mexico SIP submittal for (1) the 

‘‘significant contribution to 

nonattainment’’ prong of section 

110(a)(2)(D)(i) (75 FR 33174, June 11, 

2010) and (2) the ‘‘interfere with 

maintenance’’ and ‘‘interfere with 

measures to prevent significant 

deterioration’’ prongs of section 

110(a)(2)(D)(i) (75 FR 72688, November 

26, 2010). In this action, we are 

proposing to disapprove the New 

Mexico Interstate Transport SIP with 

respect to the requirement that 

emissions from New Mexico sources do 

not interfere with measures required in 

the SIP of any other state to protect 

visibility. See CAA section 

110(a)(2)(D)(i)(II). We are proposing to 

promulgate a FIP in order to cure this 

defect in the New Mexico Interstate 

Transport SIP. 

2. Visibility Protection 

In section 169A of the 1977 

Amendments to the CAA, Congress 

created a program for protecting 

visibility in the nation’s national parks 

and wilderness areas. This section of the 

CAA establishes as a national goal the 

‘‘prevention of any future, and the 

remedying of any existing, impairment 

of visibility in mandatory Class I 

Federal areas 3 which impairment 

results from manmade air pollution.’’ 

CAA § 169A(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. section 

169A(g)(6). In 1980, we promulgated 

regulations to address visibility 

impairment in Class I areas that is 

‘‘reasonably attributable’’ to a single 

source or small group of sources, i.e., 

‘‘reasonably attributable visibility 

impairment’’ (RAVI). 45 FR 80084 

(December 2, 1980). These regulations 

represented the first phase in addressing 

visibility impairment. We deferred 

action on RH that emanates from a 

variety of sources until monitoring, 

modeling and scientific knowledge 

about the relationships between 

pollutants and visibility impairment 

were improved. Id. 

Congress added section 169B to the 

CAA in 1990 to address RH issues, and 

we promulgated regulations addressing 

RH in 1999. 64 FR 35714 (July 1, 1999), 

codified at 40 CFR part 51, subpart P 

(the regional haze rule or RHR). The 

RHR revised the existing visibility 

regulations to integrate provisions 

addressing RH impairment and 

established a comprehensive visibility 

protection program for Class I areas. The 

requirements for RH, found at 40 CFR 

51.308 and 51.309, are included in our 

visibility protection regulations at 40 

CFR 51.300–309. States were required to 

submit the first SIP addressing RH 

visibility impairment no later than 

December 17, 2007. 40 CFR 51.308(b). 

On January 15, 2009, we published a 

‘‘Finding of Failure to Submit State 

Implementation Plans Required by the 

1999 regional haze rule.’’ 74 FR 2392. 

We found that New Mexico and other 

states had failed to submit for our 

review and approval complete SIPs for 

improving visibility in the nation’s 

national parks and wilderness areas by 

the required date of December 17, 2007. 

We found that New Mexico failed to 

submit the plan elements required by 40 

CFR 51.309(g), the reasonable progress 

requirements for areas other than the 16 

Class I areas covered by the Grand 

Canyon Visibility Transport 

Commission Report. New Mexico also 

failed to submit the plan element 

required by 40 CFR 51.309(d)(4), which 


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4NM has an option to submit a RH SIP under 

either section 51.308 or section 51.309. Although 

they have indicated their preference is for the latter, 

the NOx BART FIP we are proposing would apply 

to either. 

5BART-eligible sources are those sources, which 

have the potential to emit 250 tons or more of a 

visibility-impairing air pollutant, that were put in 

place between August 7, 1962 and August 7, 1977, 

and whose operations fall within one or more of 26 

specifically listed source categories. 

6Appendix Y to 40 CFR Part 51—Guidelines for 

BART Determinations Under the Regional Haze 

Rule. 

requires BART for stationary source 

emissions of NOx and PM under either 

40 CFR 51.308(e)(1) or 51.308(e)(2).4

This finding started a 2-year clock for 

the promulgation of a FIP by EPA, 

unless the State made a RH SIP 

submission and we approved it. 

3. Best Available Retrofit Technology 

Section 169A of the CAA directs 

states to evaluate the use of retrofit 

controls at certain major stationary 

sources with the potential to emit 

greater than 250 tons or more of any 

pollutant, in order to address visibility 

impacts from these sources. 

Specifically, it requires states to revise 

their SIPs to contain such measures as 

may be necessary to make reasonable 

progress towards the natural visibility 

goal, including a requirement that 

certain categories of existing major 

stationary sources built between 1962 

and 1977 procure, install, and operate 

the ‘‘Best Available Retrofit 

Technology,’’ as determined by the State 

or us in the case of a plan promulgated 

under section 110(c) of the CAA. CAA 

section 169A(b)(2)(A). States are 

directed to conduct BART 

determinations for such sources that 

may be anticipated to cause or 

contribute to any visibility impairment 

in a Class I area. The RHR required all 

states to submit implementation plans 

that, among other measures, contain 

either emission limits representing 

BART for certain sources constructed 

between 1962 and 1977, or alternative 

measures that provide for greater 

reasonable progress than BART. 40 CFR 

51.308(e). On July 6, 2005, we published 

the Guidelines for BART Determinations 

Under the Regional Haze Rule (‘‘BART 

Guidelines’’) to assist states in 

determining which of their sources 

should be subject to the BART 

requirements and in determining 

appropriate emission limits for each 

applicable source. 70 FR 39104. 

The process of establishing BART 

emission limitations can be logically 

broken down into three steps: first, 

states identify those sources which meet 

the definition of ‘‘BART-eligible source’’ 

set forth in 40 CFR 51.301 5; second, 

states determine whether each source 

‘‘emits any air pollutant which may 

reasonably be anticipated to cause or 

contribute to any impairment of 

visibility in any such area’’ (a source 

which fits this description is ‘‘subject to 

BART’’); and third, for each source 

subject to BART, states then identify the 

appropriate type and the level of control 

for reducing emissions. 

States must consider the following 

factors in making BART determinations: 

(1) The costs of compliance; (2) the 

energy and nonair quality 

environmental impacts of compliance; 

(3) any existing pollution control 

technology in use 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). Section 

51.308(e)(1)(ii)(B) requires that BART 

determinations for fossil fuel-fired 

electric generating plants with a total 

generating capacity in excess of 750 

megawatts, must be made according to 

the BART Guidelines.6 A state is 

encouraged, but not required, to follow 

the BART Guidelines in making BART 

determinations for other types of 

sources. 

States must address all visibilityimpairing pollutants emitted by a source 

in the BART determination process. The 

most significant visibility impairing 

pollutants are SO2, NOX, and PM. We 

have stated that states should use their 

best judgment in determining whether 

volatile organic compounds (VOCs) or 

ammonia (NH3) and ammonia 

compounds impair visibility in Class I 

areas. 

The Regional Planning Organizations 

(RPOs) provided air quality modeling to 

the states to help them in determining 

whether potential BART sources can be 

reasonably expected to cause or 

contribute to visibility impairment in a 

Class I area. Under the BART 

Guidelines, states may select an 

exemption threshold value for their 

BART modeling, below which a BARTeligible source would not be expected to 

cause or contribute to visibility 

impairment in any Class I area. 70 FR 

39104. The state must document this 

exemption threshold value in the SIP 

and must state the basis for its selection 

of that value. Id. Any source with 

emissions that model above the 

threshold value would be subject to a 

BART determination review. Id. The 

BART Guidelines acknowledge varying 

circumstances affecting different Class I 

areas. States should consider the 

number of emission sources affecting 

the Class I areas at issue and the 

magnitude of the individual sources’ 

impacts. Id. Any exemption threshold 

set by the state should not be higher 

than 0.5 deciview. Id. 

The RHR establishes the deciview 

(dv) as the principal metric for 

measuring visibility. Id. This visibility 

metric expresses uniform changes in 

haziness in terms of common 

increments across the entire range of 

visibility conditions, from pristine to 

extremely hazy conditions. Visibility is 

sometimes expressed in terms of the 

visual range which is the greatest 

distance, in kilometers or miles, at 

which a dark object can just be 

distinguished against the sky. The 

deciview is a more useful measure for 

tracking progress in improving 

visibility, because each deciview change 

is an equal incremental change in 

visibility perceived by the human eye. 

Most people can detect a change in 

visibility at one deciview. 

A RH SIP must include sourcespecific BART emission limits and 

compliance schedules for each source 

subject to BART. Once a state has made 

its BART determination, the BART 

controls must be installed and in 

operation as expeditiously as 

practicable, but no later than five (5) 

years after the date of our approval of 

the RH SIP. CAA section 169(g)(4); 40 

CFR 51.308(e)(1)(iv). In addition to what 

is required by the RHR, general SIP 

requirements mandate that the SIP must 

also include all regulatory requirements 

related to monitoring, recordkeeping, 

and reporting for the BART controls on 

the source. See CAA section 110(a)(2). 

4. The Western Regional Air Partnership 

and Evaluation of Regional Haze 

Impacts 

The Western Regional Air Partnership 

(WRAP) is a voluntary partnership of 

state, tribal, federal, and local air 

agencies dealing with regional air 

quality issues in the West. Member 

states include Alaska, Arizona, 

California, Colorado, Idaho, Montana, 

New Mexico, North Dakota, Oregon, 

South Dakota, Utah, Washington, and 

Wyoming. The WRAP established 

various committees to assist in 

managing and developing RH work 

products. New Mexico is a WRAP 

member. The WRAP evaluates air 

quality impacts, including RH impacts, 

associated with regionally significant 

emission sources. In so doing, the 

WRAP has conducted air quality 

modeling. The states in the West have 


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7More information on WRAP and their work can 

be found on the Internet at http://www.wrapair2.org 

and in the TSD for this action. 

8 In December, 2003, New Mexico submitted its 

RH SIP pursuant to the requirements of sections 

169A and 169B of the CAA and the regional haze 

rule. However, in American Corn Growers Ass’n v. 

EPA, 291 F.3d 1 (DC Cir. 2002), the U.S. Court of 

Appeals for the District of Columbia Circuit issued 

a ruling vacating and remanding the BART 

provisions of the regional haze rule. In 2006, EPA 

issued BART guidelines to address the court’s 

ruling in that case. See 70 FR 39104 (July 6, 2005). 

On January 13, 2009, New Mexico resubmitted 

portions of its RH SIP, but not the requirements 

addressing reasonable progress pursuant to 40 CFR 

51.309(g). 

9Consultation provided through the WRAP have 

been documented in calls and meetings on the 

WRAP Web site, available at http:// 

www.wrapair.org/cal/calendar.php. 

used this modeling to establish their 

reasonable progress goals for RH.7

The RH program, as reflected in the 

regulations, recognizes the importance 

of addressing the long-range transport of 

pollutants for visibility and encourage 

states to work together to develop plans 

to address haze. The regulations 

explicitly require each State to address 

its ‘‘share’’ of the emission reductions 

needed to meet the reasonable progress 

goals for surrounding Class I areas. 

States working together through a 

regional planning process are required 

to address an agreed upon share of their 

contribution to visibility impairment in 

the Class I areas of their neighbors. 40 

CFR 51.308(d)(3)(ii). The States in the 

West worked together through the 

WRAP to determine their contribution 

to visibility impairment at the relevant 

federal Class I areas in the region and 

the emissions reductions from each 

State needed to attain the reasonable 

progress goals for each area. Regional 

planning organizations (RPOs) such as 

the WRAP provided much of the 

technical work necessary to develop RH 

SIPs, including the modeling used to 

establish reasonable progress goals. The 

WRAP evaluated air quality impacts, 

including RH impacts, associated with 

regionally significant emission sources. 

In so doing, the WRAP conducted air 

quality modeling. The modeling done 

by the RPOs relied on assumptions 

regarding emissions over the relevant 

planning period. Embedded in these 

assumptions were anticipated emissions 

reductions from each of the states in the 

RPO, including reductions from BART 

and other measures to be adopted as 

part of the states long-term strategy for 

addressing RH. The states in the West, 

in turn, have used this modeling to 

establish their reasonable progress goals 

for RH. The reasonable progress goals in 

the draft and final RH SIPs that have 

now been prepared by states in the West 

accordingly are based, in part, on the 

emissions reductions from nearby states 

that were agreed on through the WRAP 

process. 

III. Our Evaluation 

A. New Mexico’s Interstate Transport 

SIP 

We received a SIP from New Mexico 

to address the interstate transport 

provisions of CAA 110(a)(2)(D)(i) for the 

1997 8-hour ozone and PM2.5 NAAQS 

on September 17, 2007. Concerning the 

provision preventing sources in the state 

from emitting pollutants in amounts 

which will interfere with efforts to 

protect visibility in other states, New 

Mexico stated that: 

• New Mexico sources of emissions 

do not interfere with implementation of 

reasonably attributable visibility 

impairment; 

• Its December 2003 RH SIP 

demonstrated reasonable progress in 

reducing impacts on Class I areas on the 

Colorado Plateau;8 and 

• The 2007 SIP update for RH will 

analyze any impacts from New Mexico 

that extend beyond the Colorado Plateau 

and determine appropriate long-term 

strategies for control measures. As 

mentioned previously, New Mexico has 

yet to provide this SIP revision. 

New Mexico’s submission addressed 

the requirement that it not interfere with 

the visibility programs of other states by 

stating that it would submit an 

approvable RH SIP by December 2007. 

The state did not otherwise establish 

that emissions from its sources would 

not interfere with the visibility 

programs of other states. After 

intervening events precluded the 

development of an approvable RH SIP, 

the state did not make any subsequent 

SIP submission to address the 

requirements of section 

110(a)(2)(D)(i)(II) with respect to 

impacts on the visibility programs of 

other states. Consequently, because the 

State did not submit a RH SIP or an 

alternative means of demonstrating that 

emissions from its sources would not 

interfere with the visibility programs of 

other States, we are proposing 

disapproval of the SIP received 

September 17, 2007, with respect to 

110(a)(2)(D)(i)(II) and visibility 

protection. Further, as described in 

subsequent sections, we are proposing 

that additional controls are necessary to 

prevent emissions from New Mexico 

from interfering with measures to 

protect visibility in other States. 

B. Federal Implementation Plan To 

Address Interstate Transport and 

Visibility and the BART Requirements 

for NOX

As an initial matter, we note that 

section 110(a)(2)(D)(i)(II) does not 

explicitly specify how we should 

ascertain whether a state’s SIP contains 

adequate provisions to prevent 

emissions from sources in that state 

from interfering with measures required 

in another state to protect visibility. 

Thus, the statute is ambiguous on its 

face, and we must interpret that 

provision. 

Our 2006 Guidance recommended 

that a state could meet the visibility 

prong of the transport requirements of 

section 110(a)(2)(D)(i)(II) of the CAA by 

submission of the RH SIP, due in 

December 2007. Our reasoning was that 

the development of the RH SIPs was 

intended to occur in a collaborative 

environment among the states. In fact, 

in developing their respective 

reasonable progress goals, WRAP states 

consulted with each other through the 

WRAP’s work groups.9 As a result of 

this process, the common understanding 

was that each State would take action to 

achieve the emissions reductions relied 

upon by other states in their reasonable 

progress demonstrations under the RHR. 

This effort included all states in the 

WRAP region contributing information 

to a Technical Support System (TSS) 

which provides an analysis of the 

causes of haze, and the levels of 

contribution from all sources within 

each state to the visibility degradation of 

each Class I area. The WRAP states 

consulted in the development of 

reasonable progress goals, using the 

products of this technical consultation 

process to co-develop their reasonable 

progress goals for the Western Class I 

areas. 

We believe that the analysis 

conducted by the WRAP provides an 

appropriate means for designing a FIP 

that will ensure that emissions from 

sources in New Mexico are not 

interfering with the visibility programs 

of other states, as contemplated in 

section 110(a)(2)(D)(i)(II). In developing 

their visibility projections using 

photochemical grid modeling, the 

WRAP states assumed a certain level of 

emissions from sources within New 

Mexico. Although we have not yet 

received all RH SIPs, we understand 

that the WRAP states used the visibility 

projection modeling to establish their 

own respective reasonable progress 

goals. Thus, we believe that an 

implementation plan that provides for 

emissions reductions consistent with 

the assumptions used in the WRAP 

modeling will ensure that emissions 

from New Mexico sources do not 


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10Consent Decree in The Grand Canyon Trust 

and Sierra Club, Plaintiffs, The State of New 

Mexico, Plaintiff-Intervenor, v. Public Service 

Company of New Mexico, Defendant, (CV 02–552 

BB/ACT (ACE)), lodged in the United States District 

Court, District of New Mexico, on March 10, 2005, 

at 15–16. 

11NOX limit of 0.30 lb/mmBtu on a 30-day rolling 

average for each of the four units; SO2 limit of 90% 

annual average control for each unit, with a shortterm limit not to exceed 0.250 lb/mmBtu for a 

seven-day block average. 

12New Mexico Environment Department Air 

Quality Bureau NSR Air Quality Permit No. 0063– 

M6R1 was issued on September 12, 2008 and 

superseded Permit No. 0063–M6. 

13Comments Received to-Date on the Draft 2018 

Base Case Projections, Version: December 21, 2005, 

available at http://www.wrapair.org/forums/ssjf/ 

documents/eictts/Projections/ 

Summary%20of%20Comments_122105_final.pdf, 

pdf pagination 20. 

14See Finding of Failure to Submit SIPs for 

Interstate Transport for the 8-hour Ozone and PM2.5

NAAQS. 70 FR 21147 (April 25, 2005); see also 

Finding of Failure To Submit State Implementation 

Plans Required by the 1999 Regional Haze Rule. 74 

FR 2392 (January 15, 2009). 

interfere with the measures designed to 

protect visibility in other states. 

Accordingly, we have reviewed the 

WRAP photochemical modeling 

emission projections used in the 

demonstration of reasonable progress 

towards natural visibility conditions 

and compared them to current emission 

levels from sources in New Mexico. We 

have concluded that all of the sources 

in New Mexico are achieving the 

emission levels assumed by the WRAP 

in its modeling except for the SJGS. The 

WRAP modeling assumed the SJGS’s 

NOX emissions would be 0.27 lbs/ 

MMBtu for units 1 and 3, and 0.28 lbs/ 

MMBtu for units 2 and 4, in 2018. The 

WRAP modeling also assumed SO2

emissions would be 0.15 lbs/MMBtu in 

2018 for the four SJGS units. 

The SJGS consists of four (4) coalfired generating units and associated 

support facilities. Each coal-fired unit 

burns pulverized coal and No. 2 diesel 

oil (for startup) in a boiler, and produces 

high-pressure steam which powers a 

steam turbine coupled with an electric 

generator. Electric power produced by 

the units is supplied to the electric 

power grid for sale. Coal for the units is 

supplied by the adjacent San Juan Mine 

and is delivered to the facility by 

conveyor. Units 1 and 2 have a unit 

capacity of 350 and 360 MW, 

respectively. Units 3 and 4 each have a 

unit capacity of 544 MW. 

In 2005, the operator of the SJGS, 

Public Service Company of New Mexico 

(PNM), entered into a consent decree 

with the Grand Canyon Trust, Sierra 

Club, and the New Mexico Environment 

Department (NMED) to reduce 

emissions of NOX, SO2, particulate 

matter and mercury.10 The consent 

decree imposed emissions restrictions, 

including the following: 

• NOX: 0.30 lb/mmBtu on a 30-day 

rolling average. 

• SO2: 90% annual average control, 

not to exceed 0.250 lb/mmBtu for a 

seven-day block average. 

In a permit modification to the 

construction permit for SJGS, NMED 

issued a revised construction permit 

(NSR Air Quality Permit No. 0063–M6) 

on April 22, 2008 to incorporate some 

of the conditions from the consent 

decree. The construction permit was 

issued by the Air Quality Bureau of the 

NMED to SJGS pursuant to the New 

Mexico Air Quality Control Act and 

regulations and is considered a federally 

enforceable permit. We were not a party 

to the consent decree, but the inclusion 

of limits from the consent decree that 

have been included in the construction 

permit for the facility were issued 

pursuant to the federally approved 

construction permitting program of the 

New Mexico SIP. Specifically, the 

construction permit includes the NOX

and SO2 limits from the consent decree 

that are identified above.11 Therefore, 

these NOX and SO2 emissions 

restrictions are federally enforceable. 

This permit has since been superseded 

by a further construction permit 

modification that also includes the 

consent decree limits on NOX and SO2

emissions and is federally enforceable.12

Although the SJGS is subject to a 

federally enforceable permit, the 

permit’s 30-day rolling average NOX

emission limit of 0.30 lb/mmBtu for all 

units is less restrictive than the 

emission rates modeled by the WRAP of 

0.27 lbs/MMBtu for units 1 and 3, and 

0.28 lbs/MMBtu for units 2 and 4 in 

assessing the daily visibility impacts. 

We also note the WRAP photochemical 

modeling utilized an SO2 emission rate 

of 0.15 lbs/MMBtu on a continuous 

basis for all four units. In previous 

communications to New Mexico and the 

WRAP, PNM indicated that the 90% 

annual average control specified in the 

permit would be expected to yield 

roughly an annual average emission rate 

of 0.195 lb/mmBtu of SO2,13 which is 

much higher than the 0.15 lb/mmBtu 

emission rate utilized in the WRAP’s 

photochemical modeling for assessing 

daily level impacts. Also, the 90% SO2

control restriction specified in the 

permit is an annual average, which 

allows for short term fluctuations. It also 

is not directly translatable to an 

emission limit (e.g., lbs/MMBtu), and 

requires knowledge of the sulfur content 

of the coal being burned. Therefore, this 

limit can further fluctuate depending 

upon the annual average sulfur content 

of the coal. This presents an 

unnecessary enforcement complication. 

The permit also specifies a 0.250 lb/ 

mmBtu on a 7-day block average for 

each unit, which is much less restrictive 

than the 0.15 lb/mmBtu emission rate 

that was used within the WRAP’s 

photochemical modeling. 

Therefore, the permit does not 

provide the necessary emission limits 

and enforceable mechanisms to ensure 

the NOX and SO2 emissions used in the 

WRAP photochemical modeling for the 

SJGS units will be met. In the absence 

of an approvable RH SIP, we do not 

have an enforceable mechanism for 

ensuring that sources in New Mexico do 

not impact visibility in other states. 

Other WRAP states are relying on levels 

modeled for the SJGS units, developed 

in consultation, in their demonstration 

of reasonable progress towards natural 

visibility conditions. Therefore, any 

discrepancies between what was 

included in the WRAP photochemical 

modeling and what is presently 

enforceable, is a concern. We have 

evaluated these discrepancies and 

determined they are significant due to 

the changes in visibility projections in 

the modeling. We have concluded that 

it is appropriate to establish federally 

enforceable limits for pollutants that 

impact visibility projections within the 

WRAP photochemical modeling. 

As discussed in II.A, we are proposing 

to disapprove New Mexico Interstate 

Transport SIP provisions that address 

the requirement of section 

110(a)(2)(D)(i)(II) that emissions from 

New Mexico sources do not interfere 

with measures required in the SIP of 

any other state under part C of the CAA 

to protect visibility. In addition, since 

New Mexico has not submitted a 

complete RH SIP that should have, 

among other things, included a review 

of BART for NOX at the SJGS, and for 

both of these requirements we have 

made a finding of failure to submit,14

giving us the authority and 

responsibility to issue a FIP to address 

the deficiencies in the State’s plan, we 

are also proposing to find that New 

Mexico sources, except the SJGS, are 

sufficiently controlled to eliminate 

interference with the visibility programs 

of other states. For the SJGS we are 

proposing to impose specific emissions 

limits that will eliminate such interstate 

interference based on current emissions 

that satisfies the assumptions in the 

WRAP modeling. 

The following sections outline our 

proposal for addressing the BART 

requirements for NOX at SJGS and for 

ensuring that the SJGS has the controls 

necessary to prevent emissions from 


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15http://camddataandmaps.epa.gov/gdm/ 

index.cfm. 

16New Mexico Environment Department, Air 

Quality Bureau, BART Determination, Public 

Service Company of New Mexico, San Juan 

Generating Station, Units 1–4, June 21, 2010, 

available at http://www.nmenv.state.nm.us/aqb/

reghaz/documents/AppxA_NM_SJGS_NOxBART

Determination_06212010.pdf. 

17http://camddataandmaps.epa.gov/gdm/ 

index.cfm. 

18 40 FR 39161 (July 6, 2005). 

New Mexico from interfering with the 

reasonable progress goals in other states. 

1. Additional SO2 Emission Limits for 

the SJGS 

As we discuss above, there are no 

federally enforceable limits that restrict 

the SJGS’s SO2 emissions at 0.15 lbs/ 

MMBtu, the rate assumed by the WRAP 

in its modeling. Therefore, as part of 

this action, we are proposing to impose 

an SO2 emission rate of 0.15 lbs/MMBtu 

on a 30 day rolling average for units 1, 

2, 3, and 4 of the SJGS. By imposing this 

limit through this action, we will insure 

that SO2 emissions from this source are 

not interfering with the visibility 

programs of other states. We note an 

examination of the SJGS’s actual 

emission rates based on emissions 

reported by our Clean Air Markets 

Division 15 indicates units 1, 2, 3, and 4 

of the SJGS are already meeting these 

SO2 emission limits. 

We are not making a finding that this 

SO2 emission limit satisfies BART for 

SO2. NMED has indicated they will 

submit a RH SIP under 40 CFR 51.309, 

thus SO2 BART for the SJGS will be 

addressed through New Mexico’s 

participation in an SO2 trading program, 

under 40 CFR 51.309(d)(4). Should 

NMED instead submit a RH SIP under 

40 CFR 51.308, the SJGS would be 

subject to an SO2 BART analysis under 

40 CFR 51.308(e). 

2. Need for Additional NOX Controls 

As we discuss above, the WRAP 

assumed in its modeling that the SJGS 

would achieve NOX emission rates of 

0.27 lbs/MMBtu for units 1 and 3, and 

0.28 lbs/MMBtu for units 2 and 4 in its 

evaluation of daily impacts in 

photochemical modeling. Based on our 

approach of relying on the assumptions 

in the WRAP modeling, additional 

control would, therefore, be necessary to 

ensure that emissions from New Mexico 

sources do not interfere with efforts to 

protect visibility in other states 

pursuant to the requirements of section 

110(a)(2)(D)(i)(II) of the CAA. 

Unlike the case for SO2, the SJGS will 

have to install controls and therefore 

make capital investments to achieve 

these additional NOX reductions. As we 

note above, on January 15, 2009, we 

published a ‘‘Finding of Failure to 

Submit State Implementation Plans 

Required by the 1999 regional haze 

rule.’’ 74 FR 2392. This finding included 

the plan element required by 40 CFR 

51.309(d)(4), which requires BART for 

stationary source emissions of NOX and 

PM under either 40 CFR 51.308(e)(1) or 

51.308(e)(2). Therefore, rather than 

making an initial determination to 

require the controls needed to prevent 

interference with the visibility programs 

of other states based on the assumptions 

in the WRAP photochemical modeling 

to meet section 110(a)(2)(D)(i)(II) 

requirements, followed soon thereafter 

by a separate NOX BART evaluation, we 

find it is appropriate to perform that 

BART evaluation at this time. 

Addressing both outstanding obligations 

at this time will be more efficient and 

will provide greater certainty to the 

source as to the appropriate NOX

controls needed to meet these two 

separate but related requirements. Our 

evaluation of BART for NOX follows. 

3. NOX BART Evaluation 

In June, 2007, PNM submitted its 

BART evaluation to NMED. That 

evaluation was revised multiple times to 

incorporate additional visibility 

modeling analyses, control technology 

considerations, and cost analyses. 

Although not officially submitted to us, 

NMED completed a NOX and PM BART 

determination for the SJGS (referred to 

herein as the ‘‘NMED BART 

evaluation’’), which we have found to be 

thorough and comprehensive.16 In 

making our NOX BART determination 

for the SJGS, we drew heavily upon the 

NOX BART portion of that document, 

and used it to help inform our NOX

BART determination for the SJGS. We 

have incorporated it into our Technical 

Support Document (TSD) found in the 

electronic docket for this action. The 

electronic docket can be found at the 

Web site http://www.regulations.gov 

(docket number EPA–R06–OAR–2010– 

0846). 

We have determined, as outlined 

below, that the SJGS is subject to BART 

and are proposing to require that units 

1, 2, 3, and 4 meet an emission limit for 

NOX of 0.05 lbs/MMBtu. This limit is 

based on the installation of SCR on each 

of the units. The following steps outline 

how we came to this determination. For 

more detail, please see the TSD. Any 

BART determinations for other 

pollutants that may be warranted under 

the RHR will be addressed in future 

rulemakings. 

a. The SJGS Is a BART-Eligible Source 

The first step of a BART evaluation is 

to determine whether a source meets the 

definition of a ‘‘BART-eligible source’’ in 

40 CFR 51.301. BART-eligible sources 

are those sources which have the 

potential to emit 250 tons or more of a 

visibility-impairing air pollutant, were 

put in place between August 7, 1962 

and August 7, 1977, and whose 

operations fall within one or more of 26 

specifically listed source categories. We 

find, based on emissions reported by 

our Clean Air Markets Division,17 that 

units 1, 2, 3, and 4 of the SJGS each 

have historically emitted much more 

than 250 tons of NOX. Also, according 

to the NMED SJGS Title V Statement of 

Basis, units 1, 2, 3, and 4 of the SJGS 

meet the requirement of being ‘‘in 

existence’’ on August 7, 1977 but not ‘‘in 

operation’’ before August 7, 1962. Lastly, 

we find that units 1, 2, 3, and 4 of the 

SJGS fall under category 1 of the 26 

listed BART categories, which is fossilfuel fired steam electric plants of more 

than 250 million British thermal units 

(BTU) per hour heat input. Therefore, 

we propose to find that units 1, 2, 3, and 

4 of the SJGS are BART-eligible. 

b. The SJGS Is Subject to BART 

Section III of the BART Guidelines 

outlines several approaches for 

identifying sources that are subject to 

BART. This entails making a 

determination of whether the units of 

the SJGS cause or contribute to visibility 

impairment in nearby Class I areas. 

Among the options we recommended 

was the use of dispersion modeling for 

assessing the impacts of a single source. 

As we note in the BART Guidelines, one 

of the first steps in this approach to 

determining whether a source causes or 

contributes to visibility impairment is to 

establish a threshold (measured in 

deciviews). A single source that is 

responsible for a 1.0 deciview change or 

more should be considered to ‘‘cause’’ 

visibility impairment; a source that 

causes less than a 1.0 deciview change 

may still contribute to visibility 

impairment and thus be subject to 

BART. We note in the BART Guidelines 

that states (and by extension EPA when 

promulgating a FIP) have flexibility in 

determining an appropriate threshold 

for determining whether a source 

‘‘contributes to any visibility 

impairment’’ for the purposes of BART. 

However, this threshold should not be 

higher than 0.5 deciviews.18 In the case 

of the SJGS, this establishment of a 

precise threshold for contribution is 

moot, since visibility modeling 

indicates that even using the upper 

bound contribution threshold of 0.5 

deciviews, the SJGS contributes to 


srobinson on DSKHWCL6B1PROD with PROPOSALS
Federal Register / Vol. 76, No. 3 / Wednesday, January 5, 2011 / Proposed Rules 499 

19 ‘‘CALMET/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 at http://pah.cert.ucr.edu/aqm/308/ 

bart/WRAP_RMC_BART_Protocol_Aug15_2006.pdf. 

20Public Service Company of New Mexico, San 

Juan Generating Station, Best Available Retrofit 

Technology Analysis, June 6, 2007. 

PNM San Juan Generating Station, BART 

Analysis of SNCR, May 30, 2008. 

PNM San Juan Generating Station, BART 

Analysis of Nalco Mobotec NOX Control 

Technologies, August 29, 2008. 

visibility impairment at a number of 

Class I areas. 

The WRAP performed the initial 

BART screening modeling for the state 

of New Mexico. The procedures used 

are outlined in the WRAP Regional 

Modeling Center (RMC) BART Modeling 

Protocol.19 The WRAP screening 

modeling evaluated sources that were 

identified as BART-eligible and 

determined the only sources that did 

not screen out were the SJGS units. The 

results of this analysis indicated that 

SJGS, on a facility-wide basis, causes 

visibility impairment at all 16 Class I 

areas within 300 km of the facility. 

However, this modeling was based on 

the installed control technology at the 

time and does not reflect emission 

reductions due to the installation of 

consent decree controls. Revised 

modeling performed by NMED and by 

us, including controls required by the 

consent decree and currently installed, 

further confirmed that SJGS still 

‘‘causes’’ visibility impairment at more 

than half of the Class I areas in the 

vicinity of the facility and contributes 

(above 0.5 deciviews) to visibility 

impairment at the remaining areas on a 

facility-wide basis. On an individual 

unit basis, all units ‘‘cause’’ visibility 

impairment at Mesa Verde National 

Park, and cause or contribute to 

visibility impairment at a number of 

other Class I areas. Our modeling 

indicates that the visibility impairment 

is primarily dominated by nitrate 

particulates. Therefore, as the WRAP 

screening modeling has previously 

concluded and further New Mexico and 

our modeling confirms that even with 

post-consent decree control levels on 

SJGS units, the SJGS units 1, 2, 3, and 

4 still have a significant impact at 

surrounding Class I areas. Consequently, 

we propose to find that units 1, 2, 3, and 

4 of the SJGS are subject to BART. More 

details on this determination can be 

found in the TSD. 

c. The SJGS NOX BART Determination 

Having established that units 1, 2, 3, 

and 4 of the SJGS are subject to BART, 

the next requirement is to perform the 

BART Analysis. 40 CFR 51.308(e)(1)(ii); 

see also BART Guidelines, Section IV. 

The BART analysis identifies the best 

system of continuous emission 

reduction and, as laid out in the BART 

Guidelines, consists of the following 

five basic steps: 

• Step 1: Identify All Available 

Retrofit Control Technologies; 

• Step 2: Eliminate Technically 

Infeasible Options; 

• Step 3: Evaluate Control 

Effectiveness of Remaining Control 

Technologies; 

• Step 4: Evaluate Impacts and 

Document the Results; and 

• Step 5: Evaluate Visibility Impacts. 

As we stated above, for our BART 

analysis we have heavily drawn upon 

the NMED BART Evaluation. Except for 

the following points, we agree with 

NMED’s conclusions regarding Steps 

1–5: 

• PNM’s cost estimate. NMED 

questioned PNM’s cost estimate for the 

installation of SCR but accepted it as 

being cost effective. We too questioned 

PNM’s cost estimate for SCR, and hired 

a consultant to undertake an accurate 

assessment of the cost of SCR and the 

emission limits that SCR is capable of 

attaining. (For more information, please 

see the TSD). 

• BART for NOX. NMED evaluated 

the visibility benefits of SCR at the SJGS 

based on an emission limit of 0.07 lbs/ 

MMBtu, but noted the potential for 

greater control at rates as low as 0.03 

lbs/MMBtu. As discussed further below, 

we have concluded that a NOX emission 

limit of 0.05 lbs/MMBtu is BART for the 

SJGS, and performed our visibility 

modeling on that basis. (Additional 

information is provided in the TSD). 

• SO2 to SO3 Conversion. NMED 

concluded BART for the SJGS was SCR 

plus sorbent injection to remove sulfur 

trioxide (SO3) in the flue gas by reaction 

with an alkaline material. As discussed 

further below, we have concluded that 

sorbent injection is not necessary, as the 

SJGS burns a low sulfur coal, and 

catalysts are available with a low SO2 to 

SO3 conversion rate. (Please see the TSD 

for further information). 

The following is a summary of our 

BART analysis. In general, our analysis 

is the same as NMED’s analysis of Steps 

1–5, as modified to incorporate the areas 

discussed above in which we differ with 

NMED. 

i. Identification of All Available Retrofit 

Emission Control Technologies 

To address step 1, NMED reviewed a 

number of potential retrofittable NOX

control technologies, including: 

Selective Non Catalytic Reduction 

(SNCR), SCR, SNCR/SCR Hybrid, 

Natural Gas Reburn, Nalco Mobotec 

ROFA and Rotamix, NOxStar, 

ECOTUBE, PowerSpan ECO, Phenix 

Clean Combustion, and e-SCRUB. We 

drew upon PNM’s June, 2007 BART 

submission to NMED and its subsequent 

revisions in our evaluation, and agree 

that the potential technologies for NOX

controls that have been identified. 

ii. Elimination of Technically Infeasible 

Options 

For step 2, again drawing upon the 

NMED analysis, we have determined the 

following potentially retrofittable NOX

control technologies are not technically 

feasible, or have not been thoroughly 

demonstrated on similar size and type 

units: Natural Gas Reburn, NOxStar, 

ECOTUBE, PowerSpan ECO, Phenix 

Clean Combustion, and e-SCRUB. In 

determining BART, we have considered 

the remaining technologies, SCR, SNCR, 

SNCR/SCR Hybrid, and the Nalco 

Mobotec ROFA and Rotamix to be 

technically feasible. 

iii. Evaluation of Control Effectiveness 

of Remaining Control Technologies 

Step 3 involves evaluating the control 

effectiveness of all the technically 

feasible control alternatives identified in 

Step 2. Two key issues in this process 

include: (1) Ensuring the degree of 

control is expressed using a metric that 

ensures a level comparison of emissions 

performance levels among options; and 

(2) giving appropriate treatment and 

consideration of control techniques that 

can operate over a wide range of 

emission performance levels. With the 

exception of SCR, Table 1 represents the 

control efficiencies and control 

emission rates PNM reported as part of 

its BART analyses 20 to NMED for the 

NOX controls that were found to be 

technically feasible. In our own SCR 

cost analysis, which we present later in 

this section, we have revised the control 

efficiency for SCR from 0.07 lbs/MMBtu 

to 0.05 lbs/MMBtu. 


srobinson on DSKHWCL6B1PROD with PROPOSALS
500 Federal Register / Vol. 76, No. 3 / Wednesday, January 5, 2011 / Proposed Rules 

21Tables 2–5 were constructed to incorporate 

costs due to sorbent injection, as a means of SO3

control in conjunction with SCR. This was done by 

PNM in response to a request by NMED. As NMED 

notes in its BART analysis, it understands there are 

SCR catalysts now on the market that are capable 

of a much smaller SO2 to SO3 conversion. In our 

own analysis, we have concurred with this finding 

and hence do not consider sorbent injection. 

TABLE 1—PROJECTED NOX CONTROL EFFECTIVENESS FOR UNITS 1–4 

Control technology Control efficiency 

(%) 

Controlled 

emission rate 

(lb/MMbtu) 

ROFA ........................................................................................................................................................... 13–15 0.26 

Rotamix (SNCR) .......................................................................................................................................... 23–25 0.23 

ROFA/Rotamix ............................................................................................................................................. 33–35 0.20 

SCR/SNCR Hybrid ....................................................................................................................................... 40–41 0.18 

SCR ............................................................................................................................................................. 77 0.07 

iv. Evaluation of Impacts and 

Documentation of Results 

Under step 4 of the BART 

determination process, we conducted 

the following analysis of the possible 

impacts due to the installation of the 

technically feasible NOX control 

options: 

• Costs of Compliance. 

• Energy Impacts. 

• Non-Air Quality Environmental 

Impacts. 

• Remaining Useful Life. 

When performing BART analyses on 

each of the technically feasible NOX

control options, PNM considered the 

energy impacts, non-air quality 

environmental impacts, and the 

remaining useful life. PNM accounted 

for the additional cost of certain energy 

impacts in the cost impacts analysis. It 

did not note any other energy impacts 

as being significant. With regard to nonair quality environmental impacts, PNM 

did not identify any significant or 

unusual environmental impacts 

associated with the control alternatives 

that had the potential to affect the 

selection or elimination of that control 

alternative. For SCR and SCR/SNCR 

Hybrid technologies, the non-air quality 

environmental impacts included the 

consideration of water usage and waste 

generated from each control technology. 

Lastly, the remaining useful life was 

defined by PNM as 20 years. Therefore, 

no additional cost adjustments for a 

short remaining useful boiler life were 

claimed by PNM. 

PNM calculated the costs of each of 

the technically feasible NOX control 

options 21. This information was 

assessed by NMED in its BART analysis. 

We checked that information and 

present it below in Tables 2–5 (with a 

few minor corrections). It summarizes 

our evaluation of the impacts of the 

BART analyses, including updated cost 

data for the SCR option: 

TABLE 2—IMPACT ANALYSIS AND COST EFFECTIVENESS OF NOX CONTROL TECHNOLOGIES FOR UNIT 1 

Control technology Emission limit NOX

emissions 

NOX

reduction 

Total capital 

investment 

Total 

annualized 

cost 

(TAC) 

Cost 

effectiveness 

Incremental 

cost 

effectiveness 

Energy 

impacts 

Non-air 

impacts 

(lbs/MMBtu) (tpy) (tpy) (TCI) 

(1,000$) 

(1,000$) ($/ton) ($/ton) (1,000$) (1,000$) 

SCR + sorbent ........ 0.07 966 3,174 164,732 21,998 6,931 3,815 1,569 1 NA 

SNCR/SCR Hybrid .. 0.18 2,484 1,656 104,436 16,207 9,787 34,221 706 1,762 

ROFA/Rotamix ........ 0.20 2,760 1,380 29 6,762 4,900 7,766 1,413 3 

Rotamix (SNCR) ..... 0.23 3,174 966 11,306 3,547 3,672 222 51 4 

ROFA ...................... 0.26 3,588 552 18,293 3,455 6,259 ¥2,896 1,363 1 NA 

Consent Decree ...... 0.30 4,140 1,254 14,580 1,422 1,134 NA 1 NA 1 NA 

TABLE 3—IMPACT ANALYSIS AND COST EFFECTIVENESS OF NOX CONTROL TECHNOLOGIES FOR UNIT 2 

Control technology Emission limit NOX

emissions 

NOX

reduction 

Total capital 

investment 

(TCI) 

Total 

annualized 

cost 

(TAC) 

Cost 

effectivness 

Incremental 

cost 

effectiveness 

Energy 

impacts 

Non-air 

impacts 

(lbs/MMBtu) (tpy) (tpy) (1,000$) (1,000$) ($/ton) ($/ton) (1,000$) (1,000$) 

SCR + sorbent ........ 0.07 961 3,158 177,178 23,364 7,399 4,432 1,565 1 NA 

SNCR/SCR Hybrid .. 0.18 2,471 1,648 108,628 16,670 10,118 36,082 346 1,762 

ROFA/Rotamix ........ 0.20 2,746 1,373 29,350 6,762 4,925 7,805 1,413 3 

Rotamix (SNCR) ..... 0.23 3,158 961 11,306 3,547 3,691 223 51 4 

ROFA ...................... 0.26 3,570 549 18,293 3,455 6,291 ¥1,375 1,363 1 NA 

Consent Decree ...... 0.30 4,119 2,060 14,126 1,378 669 NA 1 NA 1 NA 

TABLE 4—IMPACT ANALYSIS AND COST EFFECTIVENESS OF NOX CONTROL TECHNOLOGIES FOR UNIT 3 

Control technology Emission limit NOX

emissions 

NO3

reduction 

Total capital 

investment 

(TCI) 

Total 

annualized 

cost 

(TAC) 

Cost 

effectiveness 

Incremental 

cost 

effectiveness 

Energy 

impacts 

Non-air 

impacts 

(lbs/MMBtu) (tpy) (tpy) (1,000$) (1,000$) ($/ton) ($/ton) (1,000$) (1,000$) 

SCR + sorbent ........ 0.07 1,501 4,930 227,774 30,527 6,192 2,087 2,267 1 NA 


srobinson on DSKHWCL6B1PROD with PROPOSALS
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22NMED performed some modeling as well as 

reviewed modeling protocols and results supplied 

by PNM and prepared by the contractor Black & 

Veatch found in: Public Service Company of New 

Mexico BART Technology Analysis for the San Juan 

Generating Station (June 6, 2007 and submittal 

updates). When we say ‘‘NMED modeling’’ or 

‘‘NMED modeled’’ we are referring to the modeling 

performed or reviewed by NMED. 

23 ‘‘CALMET/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 at http://pah.cert.ucr.edu/aqm/308/ 

bart/WRAP_RMC_BART_Protocol_Aug15_2006.pdf. 

TABLE 4—IMPACT ANALYSIS AND COST EFFECTIVENESS OF NOX CONTROL TECHNOLOGIES FOR UNIT 3—Continued 

Control technology Emission limit NOX

emissions 

NO3

reduction 

Total capital 

investment 

(TCI) 

Total 

annualized 

cost 

(TAC) 

Cost 

effectiveness 

Incremental 

cost 

effectiveness 

Energy 

impacts 

Non-air 

impacts 

(lbs/MMBtu) (tpy) (tpy) (1,000$) (1,000$) ($/ton) ($/ton) (1,000$) (1,000$) 

SNCR/SCR Hybrid .. 0.18 3,859 2,572 168,507 25,606 9,954 37,221 507 2,658 

ROFA/Rotamix ........ 0.20 4,287 2,144 34,070 9,648 4,501 7,338 2,810 5 

Rotamix (SNCR) ..... 0.23 4,930 1,501 13,316 4,929 3,285 ¥303 84 5 

ROFA ...................... 0.26 5,574 857 20,983 5,124 5,976 ¥2,264 2,725 1 NA 

Consent Decree ...... 0.30 6,431 2,573 12,715 1,240 482 NA 1 NA 1 NA 

TABLE 5—IMPACT ANALYSIS AND COST EFFECTIVENESS OF NOX CONTROL TECHNOLOGIES FOR UNIT 4 

Control technology Emission limit NOX

emissions 

NOX

reduction 

Total capital 

investment 

(TCI) 

Total 

annualized 

cost 

(TAC) 

Cost 

effectiveness 

Incremental 

cost 

effectiveness 

Energy 

impacts 

Non-air 

impacts 

(lbs/MMBtu) (tpy) (tpy) (1,000$) (1,000$) ($/ton) ($/ton) (1,000$) (1,000$) 

SCR + sorbent ........ 0.07 1,472 4,837 211,764 28,760 5,946 1,691 2,288 1 NA 

SNCR/SCR Hybrid .. 0.18 3,785 2,524 161,572 24,849 9,847 36,141 507 2,658 

ROFA/Rotamix ........ 0.20 4,206 2,103 34,070 9,648 4,588 7,480 2,810 5 

Rotamix (SNCR) ..... 0.23 4,837 1,472 13,316 4,929 3,348 ¥309 84 5 

ROFA ...................... 0.26 5,468 841 20,983 5,124 6,091 ¥2,299 2,275 1 NA 

Consent Decree ...... 0.30 6,309 2,524 12,870 1,256 498 NA 1 NA 1 NA 

1PNM performed an impact analysis for these technologies and incorporated any monetized energy or non-air environmental impacts into the cost analysis 

We find that the energy impacts, nonair quality environmental impacts, and 

the remaining useful life do not present 

sufficient reason to disqualify any of the 

technically feasible NOX control 

technologies. 

v. Evaluation of Visibility Impacts and 

Cost Analysis 

Under step 5 of the BART Guidelines, 

we evaluate the visibility improvement 

for each feasible control technology. 

NMED modeled 22 the visibility benefits 

of each of the NOX control technologies 

listed in Tables 2–5, above, on 16 Class 

I areas. NMED used the CALPUFF 

modeling system, which consists of a 

meteorological data pre-processor 

(CALMET), an air dispersion model 

(CALPUFF), and post-processor 

programs (POSTUTIL, CALSUM, 

CALPOST). The CALPUFF modeling 

system is the recommended model for 

conducting BART visibility analysis. 

First, the model was run using the preBART, consent decree conditions to 

establish a baseline. The model was 

then run for each of the control 

technologies identified for each unit 

during the BART engineering analysis. 

These visibility impacts were then 

compared to the baseline to evaluate the 

visibility benefit of each control. NMED 

modeled the visibility impacts of each 

of the control scenarios individually for 

each of the SJGS units, as well as 

calculated visibility impacts on a 

facility-wide basis. The NMED modeling 

used the original IMPROVE equation 

within CALPOST to estimate visibility 

impairment from the modeled pollutant 

concentrations. Table 6, below, 

summarizes the results of the latter 

exercise, for the maximum impacts of 

the 98th percentile delta-dv impacts 

from 2001–2003. 

All of the WRAP and NMED refined 

modeling was conducted with the 

version of the CALPUFF system 

recommended by the WRAP BART 

modeling protocol 23 and followed the 

WRAP protocol for source-specific 

applications. As we note in the TSD, 

NMED and the WRAP utilized CALMET 

version 6.211 to create the necessary 

meteorological database for input into 

the CALPUFF model. Some technical 

concerns have been identified with this 

non-regulatory version of the model. 

The concerns are discussed in the 

technical support document. Our 

regulatory version of the model is 

CALMET 5.8, which we used in our 

modeling. Two pollutants must be given 

special consideration when estimating 

the impact of various control 

technologies on visibility improvement: 

Background ammonia (NH3) and 

sulfuric acid (H2SO4) emissions. NMED 

utilized a variable monthly background 

NH3 concentration rather than using the 

default recommended value. As 

discussed later, we utilized both 

approaches for background NH3 in our 

modeling so as to be able to compare the 

results. For estimating H2SO4 emissions, 

NMED estimated the fraction of 

particulate matter (PM) emissions that 

are classified as inorganic condensable 

PM and assumed that 100% of this 

fraction is H2SO4. Additional H2SO4 due 

to SCR operation was calculated 

assuming 1% conversion of SO2 to SO3.

As noted in the TSD and briefly 

described below, our approach to these 

two factors differed from the NMED 

approach. The results provided by 

NMED, and included in Table 6 below, 

demonstrate that SCR is by far the most 

advantageous approach to NOX control. 

The differences in our and New 

Mexico’s approaches should not change 

the relative advantage that SCR has over 

other control methods in improving 

visibility since these concerns are 

present in all the NMED modeling and 

would have similar impacts on the 

modeling results. 


srobinson on DSKHWCL6B1PROD with PROPOSALS
502 Federal Register / Vol. 76, No. 3 / Wednesday, January 5, 2011 / Proposed Rules 

24U.S. EPA, EPA Air Pollution Control Cost 

Manual, Report EPA/452/B–02–001, 6th Ed., 

January 2002 (‘‘Cost Manual’’), The EPA Air 

Pollution Control Cost Manual is the current name 

for what was previously known as the OAQPS 

Control Cost Manual, the name for the Cost Manual 

in previous (pre-2002) editions of the Cost Manual. 

25 In order to maintain and improve consistency, 

cost estimates should be based on the OAQPS 

Control Cost Manual, where possible. 70 FR 39104, 

39166 (2005). 

TABLE 6—NMED MODELED MAXIMUM IMPACTS OF THE 98TH PERCENTILE DELTA-dv IMPACTS FROM 2001–2003 

Class I area 

Distance 

to SJGS 

(km) 

Consent 

decree 

baseline 

SCR + 

Sorbent 

SCR/ 

SNCR 

Hybrid 

ROFA/ 

Rotamix Rotamix ROFA 

Arches ...................................................... 222 1.69 1.10 1.58 1.58 1.61 1.63 

Bandelier Wilderness ............................... 210 1.56 0.80 1.33 1.28 1.35 1.41 

Black Canyon of the Gunnison Wilderness ...................................................... 203 1.15 0.63 0.94 0.93 0.98 1.04 

Canyonlands ............................................ 170 2.26 1.59 2.17 2.10 2.13 2.17 

Capitol Reef ............................................. 232 1.81 1.08 1.64 1.55 1.62 1.68 

Grand Canyon .......................................... 285 0.97 0.53 0.80 0.79 0.84 0.88 

Great Sand Dunes National Monument .. 269 0.71 0.40 0.64 0.60 0.61 0.65 

La Garita Wilderness ............................... 169 0.94 0.45 0.78 0.74 0.79 0.83 

Maroon Bells Snowmass Wilderness ...... 271 0.56 0.28 0.48 0.47 0.50 0.52 

Mesa Verde .............................................. 40 3.80 2.46 4.42 3.58 3.58 3.59 

Pecos Wilderness .................................... 248 1.09 0.66 0.90 0.88 0.92 0.97 

Petrified Forest ......................................... 213 0.82 0.48 0.73 0.73 0.77 0.78 

San Pedro Parks Wilderness ................... 155 2.01 1.13 1.80 1.67 1.77 1.86 

West Elk Wilderness ................................ 216 0.91 0.43 0.73 0.71 0.76 0.80 

Weminuche Wilderness ........................... 98 1.48 0.90 1.33 1.24 1.32 1.36 

Wheeler Peak Wilderness ....................... 258 0.89 0.50 0.72 0.70 0.75 0.79 

Total .................................................. .................... 22.65 13.42 20.99 19.55 20.30 20.96 

We note NMED’s modeling indicated 

there was little difference between the 

SCR/SNCR hybrid, ROFA/Rotamix, and 

ROFA NOX control technologies. 

However, as Tables 2–5 indicate, there 

is a significant difference in the cost of 

those controls, with the SNCR/SCR 

hybrid being more than twice as 

expensive as the ROFA/Rotamix, and 

approximately five times as expensive 

as both the Rotamix (SNCR) and the 

ROFA options. None of these NOX

control technologies was capable of 

significantly improving the visibility at 

any of the 16 Class I areas; therefore, we 

did not further evaluate them. However, 

we note that SCR was capable of 

uniformly improving the visibility at all 

of the 16 Class I areas, but at a higher 

cost. 

The costs of the controls in Tables 2– 

5, were calculated by PNM. Because we 

found the costs projected by PNM to be 

high in comparison to other SCR 

retrofits we have reviewed, we refined 

the cost of retrofitting the SJGS with 

SCR (see the TSD for more information), 

and the NOX emission level SCR was 

capable of achieving when retrofitted to 

the SJGS. This analysis indicated that 

the cost of SCR at this source would be 

considerably lower than calculated by 

PNM. We believe that PNM 

overestimated the cost of SCR due to 

several basic errors that PNM made in 

constructing its SCR cost analysis: 

• PNM did not follow the EPA Air 

Pollution Control Cost Manual, where 

possible,24 as directed by the BART 

Guidelines.25

• PNM scaled many of the cost items 

from another project that has significant 

design differences when compared to 

the SJGS. We made changes in many of 

these items to adjust them from 

budgetary to final contract; to exclude 

equipment and modifications not 

required for the SJGS SCR installations; 

to correct errors; and to factor out 

installation, freight, and other costs that 

were included in the contract awards 

and double counted elsewhere in PNM’s 

cost estimate. We have concluded that 

these adjustments are correct, and 

provide a more accurate estimate of the 

costs at SJGS. 

• PNM performed their SCR cost 

estimate on the basis of a NOX control 

rate of 0.07 lbs/MMBtu. We concluded 

that SCR could reliably achieve NOX

control at a rate of 0.05 lbs/MMBtu on 

a 30-day rolling average basis, for each 

of the four units of the SJGS. Because 

this did not require a change in the 

capital cost of the SCR unit, and only 

necessitated the purchase of additional 

reagent, this had the effect of improving 

the cost effectiveness. We have 

concluded that the analysis concerning 

the achievability of the emissions limit, 

and the cost of achieving those limits, 

is more accurate. 

The results of that analysis are 

presented as Table 7: 

TABLE 7—EPA DETERMINED COST EFFECTIVENESS OF SCR FOR THE SJGS 

Unit 

Emission 

limit 

(lbs/MMBtu) 

NOX

emissions 

(tpy) 

NOX

reduction 

(tpy) 

Total 

capital 

investment 

Total 

annualized 

cost 

Cost 

effectiveness 

($/ton) 

1 ............................................................... 0.05 690 3,450 $53,230,469 $6,373,573 1,847 

2 ............................................................... 0.05 686 3,433 55,664,049 6,591,720 1,920 

3 ............................................................... 0.05 1,071 5,360 70,464,306 8,631,234 1,610 

4 ............................................................... 0.05 1,051 5,258 67,223,223 8,304,143 1,579 


srobinson on DSKHWCL6B1PROD with PROPOSALS
Federal Register / Vol. 76, No. 3 / Wednesday, January 5, 2011 / Proposed Rules 503 

26Electric Power Research Institute, Estimating 

Total Sulfuric Acid Emissions from Stationary 

Power Plants, 1016384 Technical Update, March 

2008. 

27Emails between Anita Lee, EPA Region 9 and 

Anthony C. Favale P.E., Director—SCR Products, 

Hitachi Power Systems America, Ltd. Favale: 

‘‘Catalyst development has progressed over the last 

few years to the point that an initial SO2 conversion 

rate of 0.5% can be guaranteed with 80 to 90% NOX

reduction.’’ 

28See 70 FR at 39,121. 

Based on our refined cost and control 

effectiveness analysis, we conclude that 

SCR is cost effective for all units of the 

SJGS. 

Although we generally regard the 

visibility modeling analyses performed 

by NMED to be of high quality, we 

noted some minor issues we wished to 

rectify in order to address consistency 

with modeling guidance we have 

provided to the states. We remodeled 

the visibility impacts of the SJGS using 

revised emission estimates and 

meteorology results from the regulatory 

version of the CALPUFF and CALMET 

models. As detailed in the TSD, we 

utilized a different approach based on 

the best current information from the 

Electric Power Research Institute 

(EPRI) 26 to estimate the sulfuric acid 

released from combustion in the boiler 

for all scenarios and for operation of the 

SCR, assuming a 0.5% SO2 to SO3

conversion efficiency 27 of the SCR 

catalyst (compared to a 1% conversion 

assumed by NMED). We determined 

that the SCR could achieve an emission 

rate of 0.05 lb NOX/MMBtu and 

included this emission rate in modeling 

the SCR control scenario (compared to 

0.07 lb NOX/MMBtu assumed by 

NMED). We modeled a revised baseline 

with the SO2 emissions lowered to the 

BART presumptive limit of 0.15 lb/ 

MMBtu that was assumed by the WRAP 

for regional photochemical visibility 

modeling to demonstrate reasonable 

progress towards natural visibility 

conditions. Finally, modeling was 

performed utilizing both the monthly 

variable background NH3 concentration 

used by NMED and the default 

background NH3 concentration of 1.0 

ppb to evaluate the sensitivity of the 

results to these assumptions. Visibility 

impairment from our modeled pollutant 

concentrations were calculated using 

both the original IMPROVE equation 

(Method 6) used by NMED and the 

revised IMPROVE equation (Method 8) 

to calculate visibility impairment from 

the modeled pollutant concentrations. 

As Table 8 indicates, in considering 

the visibility impacts associated with 

the use of SCR, we focused on the 98th 

percentile of modeled results to avoid 

giving undue weight to any extreme 

results.28 The results are presented as 

the visibility impacts from SJGS and the 

associated changes in visibility at each 

Class I area within 300 kilometers of the 

facility resulting from the use of SCR. 

These results employ our revised 

baseline, a 1 ppb background NH3

concentration assumption, our revised 

SO2 to SO3 conversion calculation, and 

the new IMPROVE equation (Method 8). 

The other methods that we utilized in 

our sensitivity modeling approaches 

using Method 6 and/or the variable NH3

are documented in the TSD. 

TABLE 8—EPA MODELED MAXIMUM IMPACTS OF THE 98TH PERCENTILE DELTA-dv IMPACTS FROM 2001–2003 

Class I area 

Distance 

to SJGS 

(km) 

Baseline 

visibility 

impact 

(Ddv) 

Visibility 

impact 

with 

SCR 

(Ddv) 

Visibility 

improvement 

with 

SCR 

(Ddv) 

Arches .............................................................................................................. 222 3.50 1.12 2.38 

Bandelier Wilderness ....................................................................................... 210 1.39 0.48 0.91 

Black Canyon of the Gunnison Wilderness ..................................................... 203 1.41 0.42 0.99 

Canyonlands .................................................................................................... 170 4.64 1.53 3.11 

Capitol Reef ..................................................................................................... 232 2.38 0.82 1.56 

Grand Canyon ................................................................................................. 285 0.93 0.33 0.60

Great Sand Dunes National Monument .......................................................... 269 1.53 0.49 1.04 

La Garita Wilderness ....................................................................................... 169 1.93 0.57 1.36 

Maroon Bells Snowmass Wilderness .............................................................. 271 0.70 0.28 0.42 

Mesa Verde ..................................................................................................... 40 5.15 2.27 2.88 

Pecos Wilderness ............................................................................................ 248 1.27 0.47 0.80 

Petrified Forest ................................................................................................ 213 0.52 0.21 0.31 

San Pedro Parks Wilderness ........................................................................... 155 2.20 0.74 1.46 

West Elk Wilderness ........................................................................................ 216 1.59 0.45 1.14 

Weminuche Wilderness ................................................................................... 98 2.92 0.87 2.05 

Wheeler Peak Wilderness ............................................................................... 258 1.12 0.44 0.68 

Total Delta dv ........................................................................................... ........................ 33.18 11.48 21.69 

As can be seen from Table 8, our 

visibility modeling indicates that SCR 

NOX control offers visibility 

improvement at every one of the 16 

Class I areas and significant visibility 

improvement at the overwhelming 

majority of areas. Therefore, after having 

identified all available retrofittable NOX

control technologies, eliminated those 

that were not technically feasible, 

evaluated the NOX control effectiveness 

of those remaining, evaluated the 

impacts and having documented the 

results, we propose that NOX BART for 

all the units of the SJGS is SCR with a 

30 day rolling average of 0.05 lbs/ 

MMBtu. 

In addition, our visibility analysis 

relied in part on estimates of H2SO4 mist 

emissions. The amount of H2SO4

emissions depends, in part, on proper 

design and operation of the SCR unit. 

Therefore, we believe it is appropriate to 

set emission limits for H2SO4. We 

believe that our estimates of these 

emissions are appropriate based on the 

use of low reactivity catalyst that will 

reduce the rate of SO2 to SO3

conversion. To ensure these levels are 

met, we are proposing that emissions of 

H2SO4 be limited to 1.06 x 10¥4 lb/ 

MMBtu for each unit. These emission 

limits are based on the most current 

information from the Electric Power 

Research Institute (EPRI), information 

on the sulfur content of the coal, and 

assuming a maximum of 0.5% SO2 to 

SO3 conversion efficiency of the SCR 

catalyst. We note that there is some 

potential variation in the methodologies 


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29Upper range value is based on information from 

PNM’s Toxics Release Inventory report and 

previous PNM calculations of the amount of 

additional H2SO4 from the installation and 

operation of SCR. For details on the derivation of 

this upper bound value, see the TSD. 

30http://www.epa.gov/ttn/emc/ctm/ctm-013.pdf. 

31PNM materials previously indicated that a 2 

ppm ammonia slip limit would be appropriate for 

SCR at the Public Service Company of New Mexico 

Black and Veatch report titled: ‘‘San Juan 

Generating Station Best Available Retrofit 

Technology Analysis’’ Issue Date and Revision June 

6, 2007, Final; Appendix B, page B–3. 

32Typical Installation Timelines for NOx 

Emissions Control Technologies on Industrial 

Sources, Institute of Clean Air Companies, 

December 4, 2006, available at http://www.icac.7

com/files/public/ICAC_NOx_Control_Installation_

Timing_120406.pdf; see also Engineering and 

Economic Factors Affecting the Installation of 

Control Technologies for Multipollutant Strategies, 

EPA–600/R–02/073, October 2002, available at 

http://www.epa.gov/clearskies/pdfs/ 

multi102902.pdf. 

33 Id. 

and the assumptions used method for 

calculating H2SO4 emissions. The 

assumptions associated with our 

calculation are discussed further in the 

TSD. We are soliciting comment on 

setting the emission limit in the range 

between our proposed limit of 1.06 x 

10¥4 lb/MMBtu and an upper range of 

sulfuric acid mist emissions of 7.87 x 

10¥4 lb/MMBtu.29 Comments on our 

proposed H2SO4 limit and alternative 

limits should include consideration of 

the use of a low conversion rate SCR 

catalyst and be sufficiently justified. 

As there are no continuous emission 

monitoring techniques for H2SO4 mist, 

we are proposing that compliance be 

based on an hourly average, confirmed 

by annual stack testing using EPA Test 

Method 8A (CTM–013).30 We note that 

our proposed limits challenge the 

detection limits of the test method. We 

solicit comment on this issue, including 

suggestions for test methods that will 

better measure these low concentrations 

and other approaches to determine 

continuous compliance. 

Similarly, our visibility analysis also 

relied in part on estimates of ammonia 

(NH3) slip, emissions of NH3 that pass 

through the SCR. NH3 contribute to 

visibility impairment. Limiting NH3

emissions depends on proper design 

and operation of the SCR. Therefore, we 

are proposing to set a limit to minimize 

the contribution of NH3 to visibility 

impairment. We are proposing that 

emissions of NH3 be limited to 2.0 parts 

per million volume dry (ppmvd), 

adjusted to 6 percent oxygen for each of 

the four SJGS units.31 We are also 

soliciting comment on setting this limit 

in the range of 2–6 ppmvd, adjusted to 

6 percent oxygen. Comments on our 

proposed limit and alternative limits 

should consider visibility impairment. 

Compliance will be based on an hourly 

average confirmed by an initial 

performance test using EPA Conditional 

Test Method 27 (40 CFR 51, Appendix 

M). We are also proposing that a CEM 

for NH3 be installed and operated. We 

solicit comment on other approaches to 

determine continuous compliance. 

As we note above in section II.B.3, the 

RHR requires that BART controls must 

be installed and in operation as 

expeditiously as practicable, but no later 

than five (5) years after the date of our 

approval of the RH SIP. 40 CFR 

51.308(e)(1)(iv). Based on the retrofit of 

other SCR installations we have 

reviewed, we find that three (3) years 

from the date our final determination 

becomes effective is a conservative and 

adequate estimate of time for the 

planning, engineering, installation, and 

start-up of these controls.32 Many 

installations have been completed in 

much shorter times.33 We solicit 

comment on alternative timeframes, up 

to five (5) years from the date our final 

determination becomes effective. 

IV. Proposed Action 

We are proposing to disapprove a 

portion of the SIP revision submitted by 

the State of New Mexico for the purpose 

of addressing the ‘‘good neighbor’’ 

provisions of the CAA section 

110(a)(2)(D)(i) for the 1997 8-hour ozone 

NAAQS and the PM2.5 NAAQS. We are 

proposing to disapprove the New 

Mexico Interstate Transport SIP 

provisions that address the requirement 

of section 110(a)(2)(D)(i)(II) that 

emissions from New Mexico sources do 

not interfere with measures required in 

the SIP of any other state under part C 

of the CAA to protect visibility. As a 

result of the proposed disapproval, we 

are also proposing a FIP to address the 

requirements of section 

110(a)(2)(D)(i)(II) with respect to 

visibility. With regard to whether 

emissions from New Mexico sources 

interfere with the visibility programs of 

other states, we are proposing to find 

that New Mexico sources, except the 

SJGS, are sufficiently controlled to 

eliminate interference with the visibility 

programs of other states, and for the 

SJGS source we are proposing to impose 

specific SO2 and NOX emissions limits 

that will eliminate such interstate 

interference. In addition, EPA is 

proposing the FIP to address the 

requirement for BART for NOX for the 

SJGS. 

Based on our evaluation we are 

proposing to find that the SJGS is 

subject to BART under section 40 CFR 

51.309(d)(4), and/or 51.308(e). Our 

proposed NOX controls for SJGS will 

partially address the BART 

requirements of the RH program. 

Specifically, we are proposing a FIP that 

imposes NOX BART limits for the SJGS. 

Together, the reduction in NOX from our 

proposed NOX BART determination, 

and the proposed SO2 emission limits 

will serve to ensure there are 

enforceable mechanisms in place to 

prevent New Mexico NOX and SO2

emissions from interfering with efforts 

to protect visibility in other states 

pursuant to the requirements of section 

110(a)(2)(D)(i)(II) of the CAA. 

For NOX emissions, we are proposing 

to require the SJGS to meet an emission 

limit of 0.05 pounds per million British 

Thermal Units (lb/MMBtu) individually 

at Units 1, 2, 3, and 4. This NOX limit 

is achievable by installing and operating 

SCR. For SO2, we are proposing to 

require the SJGS to meet an emission 

limit of 0.15 lb/MMBtu. Both of these 

emission limits would be measured on 

the basis of a 30 day rolling average. We 

are also proposing hourly average 

emission limits of 1.06 x 10¥4 lb/ 

MMBtu for H2SO4 and 2.0 ppmvd, for 

NH3, to minimize the contribution of 

these compounds to visibility 

impairment. Additionally, we are 

proposing monitoring, recordkeeping 

and reporting requirements to ensure 

compliance with emission limitations. 

We also propose that compliance with 

the emission limits be within three (3) 

years of the effective date of our final 

rule. We solicit comments on alternative 

timeframes, up to five (5) years from the 

effective date our final rule. 

V. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

This proposed action is not a 

‘‘significant regulatory action’’ under the 

terms of Executive Order (EO) 12866, 

(58 FR 51735, October 4, 1993), and is 

therefore not subject to review under the 

Executive Order. This action proposes a 

source-specific FIP for the San Juan 

Power Generating Station (SJGS) in New 

Mexico. 

B. Paperwork Reduction Act 

This proposed action does not impose 

an information collection burden under 

the provisions of the Paperwork 

Reduction Act, 44 U.S.C. 3501 et seq. 

Under the Paperwork Reduction Act, a 

‘‘collection of information’’ is defined as 

a requirement for ‘‘answers to * * * 

identical reporting or recordkeeping 

requirements imposed on ten or more 

persons * * *.’’ 44 U.S.C. 3502(3)(A). 

Because the proposed FIP applies to a 

single facility, (SJGS), the Paperwork 


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Reduction Act does not apply. See 5 

CFR 1320(c). 

Burden means the total time, effort, or 

financial resources expended by persons 

to generate, maintain, retain, or disclose 

or provide information to or for a 

Federal agency. This includes the time 

needed to review instructions; develop, 

acquire, install, and utilize technology 

and systems for the purposes of 

collecting, validating, and verifying 

information, processing and 

maintaining information, and disclosing 

and providing information; adjust the 

existing ways to comply with any 

previously applicable instructions and 

requirements; train personnel to be able 

to respond to a collection of 

information; search data sources; 

complete and review the collection of 

information; and transmit or otherwise 

disclose the information. 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for EPA’s regulations in 40 

CFR are listed in 40 CFR part 9. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of today’s proposed rule on small 

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

small business as defined by the Small 

Business Administration’s (SBA) 

regulations at 13 CFR 121.201; (2) a 

small governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

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

a small organization that is any not-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 FIP for 

SJGS being proposed today does not 

impose any new requirements on small 

entities. See Mid-Tex Electric 

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

(D.C. Cir. 1985). 

D. Unfunded Mandates Reform Act 

(UMRA) 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), Public 

Law 104–4, establishes requirements for 

Federal agencies to assess the effects of 

their regulatory actions on State, local, 

and Tribal governments and the private 

sector. Under section 202 of UMRA, 

EPA generally must prepare a written 

statement, including a cost-benefit 

analysis, for proposed and final rules 

with ‘‘Federal mandates’’ that may result 

in expenditures to State, local, and 

Tribal governments, in the aggregate, or 

to the private sector, of $100 million or 

more (adjusted to inflation) in any 1 

year. Before promulgating an EPA rule 

for which a written statement is needed, 

section 205 of UMRA generally requires 

EPA to identify and consider a 

reasonable number of regulatory 

alternatives and adopt the least costly, 

most cost-effective, or least burdensome 

alternative that achieves the objectives 

of the rule. The provisions of section 

205 of UMRA do not apply when they 

are inconsistent with applicable law. 

Moreover, section 205 of UMRA allows 

EPA to adopt an alternative other than 

the least costly, most cost-effective, or 

least burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. Before EPA establishes 

any regulatory requirements that may 

significantly or uniquely affect small 

governments, including Tribal 

governments, it must have developed 

under section 203 of UMRA a small 

government agency plan. The plan must 

provide for notifying potentially 

affected small governments, enabling 

officials of affected small governments 

to have meaningful and timely input in 

the development of EPA regulatory 

proposals with significant Federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

Under Title II of UMRA, EPA has 

determined that this proposed rule does 

not contain a Federal mandate that may 

result in expenditures that exceed the 

inflation-adjusted UMRA threshold of 

$100 million by State, local, or Tribal 

governments or the private sector in any 

1 year. In addition, this proposed rule 

does not contain a significant Federal 

intergovernmental mandate as described 

by section 203 of UMRA nor does it 

contain any regulatory requirements 

that might significantly or uniquely 

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 on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. This action 

merely prescribes EPA’s action to 

address the State not fully meeting its 

obligation to prohibit emissions from 

interfering with other states measures to 

protect visibility. Thus, Executive Order 

13132 does not apply to this action. In 

the spirit of Executive Order 13132, and 

consistent with EPA policy to promote 

communications between EPA and State 

and local governments, EPA specifically 

solicits comment on this proposed rule 

from State and local officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). It will not have substantial direct 

effects on tribal governments, on the 

relationship between the Federal 

government and Indian tribes, or on the 

distribution of power and 

responsibilities between the federal 

government and Indian tribes, as 

specified in Executive Order 13175. 

Thus, Executive Order 13175 does not 

apply to this proposed rule. 

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 limits 

emissions of pollutants from an existing 

single stationary source. Because this 

proposed action only applies to a single 

existing source and is not a proposed 

rule of general applicability, it is not 


srobinson on DSKHWCL6B1PROD with PROPOSALS
506 Federal Register / Vol. 76, No. 3 / Wednesday, January 5, 2011 / Proposed Rules 

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 limit emissions of NOX and 

SO2 the rule will have a beneficial effect 

on children’s health by reducing air 

pollution. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not subject to Executive 

Order 13211 (66 FR 28355 (May 22, 

2001)), because it is not a significant 

regulatory action under Executive Order 

12866. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (‘‘NTTAA’’), Public Law 

104–113, 12(d) (15 U.S.C. 272 note) 

directs EPA to use voluntary consensus 

standards in its regulatory activities 

unless to do so would be inconsistent 

with applicable law or otherwise 

impractical. Voluntary consensus 

standards are technical standards (e.g., 

materials specifications, test methods, 

sampling procedures, and business 

practices) that are developed or adopted 

by voluntary consensus standards 

bodies. NTTAA directs EPA to provide 

Congress, through OMB, explanations 

when the Agency decides not to use 

available and applicable voluntary 

consensus standards. This proposed 

rule would require all sources to meet 

the applicable monitoring requirements 

of 40 CFR part 75. Part 75 already 

incorporates a number of voluntary 

consensus standards. Consistent with 

the Agency’s Performance Based 

Measurement System (PBMS), part 75 

sets forth performance criteria that 

allow the use of alternative methods to 

the ones set forth in part 75. The PBMS 

approach is intended to be more flexible 

and cost effective for the regulated 

community; it is also intended to 

encourage innovation in analytical 

technology and improved data quality. 

At this time, EPA is not recommending 

any revisions to part 75; however, EPA 

periodically revises the test procedures 

set forth in part 75. When EPA revises 

the test procedures set forth in part 75 

in the future, EPA will address the use 

of any new voluntary consensus 

standards that are equivalent. Currently, 

even if a test procedure is not set forth 

in part 75, EPA is not precluding the use 

of any method, whether it constitutes a 

voluntary consensus standard or not, as 

long as it meets the performance criteria 

specified; however, any alternative 

methods must be approved through the 

petition process under 40 CFR 75.66 

before they are used. 

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 limits emissions of 

pollutants from a single stationary 

source, SJGS. 

List of Subjects in 40 CFR Part 52 

Environmental protection, Air 

pollution control, Intergovernmental 

relations, Nitrogen dioxide, Ozone, 

Particulate matter, Reporting and 

recordkeeping requirements, Sulfur 

dioxide, Visibility, Interstate transport 

of pollution, Regional haze, Best 

available control technology. 

Dated: December 20, 2010. 

Samuel J. Coleman, 

Acting Regional Administrator, Region 6. 

Title 40, chapter I, of the Code of 

Federal Regulations is proposed to be 

amended as follows: 

PART 52—[AMENDED] 

1. The authority citation for part 52 

continues to read as follows: 

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

2. Add § 52.1628 to read as follows: 

§ 52.1628 Interstate pollutant transport 

and regional haze provisions; What are the 

FIP requirements for San Juan Generating 

Station emissions affecting visibility? 

(a) Applicability. The provisions of 

this section shall apply to each owner 

or operator of the coal burning 

equipment designated as Units 1, 2, 3, 

or 4 at the San Juan Generating Station 

in San Juan County, New Mexico (the 

plant). 

(b) Compliance dates. Compliance 

with the requirements of this section is 

required upon the effective date of this 

rule unless otherwise indicated by 

compliance dates contained in specific 

provisions. 

(c) Definitions. All terms used in this 

part but not defined herein shall have 

the meaning given them in the Clean Air 

Act and in parts 51 and 60 of this 

chapter. For the purposes of this 

section: 

24-hour period means the period of 

time between 12:01 a.m. and 12 

midnight. 

Air pollution control equipment 

includes baghouses, particulate or 

gaseous scrubbers, and any other 

apparatus utilized to control emissions 

of regulated air contaminants which 

would be emitted to the atmosphere. 

Daily average means the arithmetic 

average of the hourly values measured 

in a 24-hour period. 

Heat input means heat derived from 

combustion of fuel in a Unit and does 

not include the heat input from 

preheated combustion air, recirculated 

flue gases, or exhaust gases from other 

sources. Heat input shall be calculated 

in accordance with 40 CFR part 75. 

Owner or Operator means any person 

who owns, leases, operates, controls, or 

supervises the plant or any of the coal 

burning equipment designated as Units 

1, 2, 3, or 4 at the plant. 

Oxides of nitrogen (NOX) means all 

oxides of nitrogen except nitrous oxide, 

as measured by test methods set forth in 

40 CFR part 60. 

Regional Administrator means the 

Regional Administrator of EPA Region 6 

or his/her authorized representative. 

(d) Emissions limitations and control 

measures. (1) Within 180 days of the 

effective date of this paragraph (d), the 

owner or operator shall submit a plan to 

the Regional Administrator that 

identifies the air pollution control 

equipment and schedule for complying 

with paragraph (d) of this section. The 

owner or operator shall submit 

amendments to the plan to the Regional 

Administrator as changes occur. The 

NOX and SO2 limits shall be effective no 

later than 3 years after the effective date 

of this rule. No owner or operator shall 

discharge or cause the discharge of NOX

or SO2 into the atmosphere from Units 

1, 2, 3 and 4 in excess of the limits for 

these pollutants. 

(2) NOX emission limit. The NOX limit 

for each unit in the plant, expressed as 

nitrogen dioxide (NO2), shall be 0.05 

pounds per million British thermal 


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units (lb/MMBtu) as averaged over a 

rolling 30 calendar day period. For each 

unit, NOX emissions for each calendar 

day shall be determined by summing 

the hourly emissions measured in 

pounds of NOX. For each unit, heat 

input for each calendar day shall be 

determined by adding together all 

hourly heat inputs, in millions of BTU. 

Each day the thirty-day rolling average 

for a unit shall be determined by adding 

together the pounds of NOX from that 

day and the preceding 29 days and 

dividing the total pounds of NOX by the 

sum of the heat input during the same 

30-day period. The result shall be the 

30-day rolling average in terms of lb/ 

MMBtu emissions of NOX. 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 of 

the 30-day rolling average for NOX. 

(3) SO2 emission limit. The sulfur 

dioxide emission limit for each unit 

shall be 0.15 lb/MMBtu as averaged over 

a rolling 30-calendar-day period. For 

each unit, SO2 emissions for each 

calendar day shall be determined by 

summing the hourly emissions 

measured in pounds of sulfur dioxide. 

For each unit, heat input for each 

calendar day shall be determined by 

adding together all hourly heat inputs, 

in millions of BTU. Each day the thirtyday rolling average shall be determined 

by adding together pounds of sulfur 

dioxide from that day and the preceding 

29 days and dividing the total pounds 

of sulfur dioxide by the sum of the heat 

input during the same 30-day period. 

The results shall be the 30-day rolling 

average for lb/MMBtu emissions of SO2. 

If a valid SO2 pounds per hour or heat 

input is not available for any hour for 

a unit, that heat input and SO2 pounds 

per hour shall not be used in the 

calculation of the 30-day rolling average 

for SO2. 

(4) H2SO4 emission limit: Emissions 

of H2SO4 from each unit shall be limited 

to 1.06 x 10¥4 lb/MMBtu on an hourly 

basis. 

(5) Ammonia emission limit: 

Emissions of ammonia (NH3) from each 

unit will be limited to 2.0 parts per 

million by volume, dry (ppmvd), 

adjusted to 6 percent oxygen, on an 

hourly average basis. 

(e) Testing and monitoring. (1) On and 

after the effective date of this regulation, 

the owner or operator shall install, 

calibrate, maintain and operate 

Continuous Emissions Monitoring 

Systems (CEMS) for NOX, SO2, and NH3

on Units 1, 2, 3, and 4 in accordance 

with 40 CFR 60.8 and 60.13(e), (f), and 

(h), and Appendix B of Part 60. The 

owner or operator shall comply with the 

quality assurance procedures for CEMS 

found in 40 CFR part 75. Compliance 

with the emission limits for NOX, SO2

and NH3 shall be determined by using 

data from a CEMS. 

(2) Continuous emissions monitoring 

shall apply during all periods of 

operation of the coal burning 

equipment, including periods of startup, 

shutdown, and malfunction, except for 

CEMS breakdowns, repairs, calibration 

checks, and zero and span adjustments. 

Continuous monitoring systems for 

measuring SO2, NOX, NH3 and diluent 

gas shall complete a minimum of one 

cycle of operation (sampling, analyzing, 

and data recording) for each successive 

15-minute period. Hourly averages shall 

be computed using at least one data 

point in each fifteen minute quadrant of 

an hour. Notwithstanding this 

requirement, an hourly average may be 

computed from at least two data points 

separated by a minimum of 15 minutes 

(where the unit operates for more than 

one quadrant in an hour) if data are 

unavailable as a result of performance of 

calibration, quality assurance, 

preventive maintenance activities, or 

backups of data from data acquisition 

and handling system, and recertification 

events. When valid SO2 pounds per 

hour, NOX pounds per hour, SO2

pounds per million Btu emission data, 

NOX pounds per million Btu emission 

data, or NH3 ppmvd data are not 

obtained because of continuous 

monitoring system breakdowns, repairs, 

calibration checks, or zero and span 

adjustments, emission data must be 

obtained by using other monitoring 

systems approved by the EPA to provide 

emission data for a minimum of 18 

hours in each 24 hour period and at 

least 22 out of 30 successive boiler 

operating days. 

(3) Emissions of H2SO4 shall be 

measured within 180 days of start up of 

the NOX control device and annually 

thereafter using EPA Test Method 8A 

(CTM–013). 

(4) Emissions of ammonia shall be 

measured within 180 days of startup of 

the NOX control device using EPA 

Conditional Test Method 27. 

(5) The facility shall install, calibrate, 

maintain, and operate a CEMS to 

measure and record the concentrations 

of NH3. 

(f) Reporting and recordkeeping 

requirements. Unless otherwise stated 

all requests, reports, submittals, 

notifications, and other communications 

to the Regional Administrator required 

by this section shall be submitted, 

unless instructed otherwise, to the 

Director, Multimedia Planning and 

Permitting Division, U.S. Environmental 

Protection Agency, Region 6, to the 

attention of Mail Code: 6PD, at 1445 

Ross Avenue, Suite 1200, Dallas, Texas 

75202–2733. For each unit subject to the 

emissions limitation in this section and 

upon completion of the installation of 

CEMS as required in this section, the 

owner or operator shall comply with the 

following requirements: 

(1) For each emissions limit in this 

section, comply with the notification 

and recordkeeping requirements for 

CEMS compliance monitoring in 40 CFR 

60.7(c) and (d). 

(2) For each day, provide the total 

NOX and SO2 emitted that day by each 

emission unit. For any hours on any 

unit where data for hourly pounds or 

heat input is missing, identify the unit 

number and monitoring device that did 

not produce valid data that caused the 

missing hour. 

(g) 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 

Plant 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 which may include, but 

is not limited to, monitoring results, 

review of operating and maintenance 

procedures, and inspection of the Plant. 

(h) Enforcement. (1) Notwithstanding 

any other provision in this 

implementation plan, any credible 

evidence or information relevant as to 

whether the Plant 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. 

(2) Emissions in excess of the level of 

the applicable emission limit or 

requirement that occur due to a 

malfunction shall constitute a violation 

of the applicable emission limit. 

[FR Doc. 2010–33106 Filed 1–4–11; 8:45 am] 

BILLING CODE 6560–50–P 


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