52388 Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

EPA–R06–OAR–2010–0846; 

FRL–9451–1 

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: Final rule. 

SUMMARY: EPA is disapproving a portion 

of the State Implementation Plan (SIP) 

revision received from the State of New 

Mexico on September 17, 2007, 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. In 

this action, EPA is disapproving 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. We have 

found that New Mexico sources, except 

the San Juan Generating Station, are 

sufficiently controlled to eliminate 

interference with the visibility programs 

of other states. EPA is promulgating a 

Federal Implementation Plan (FIP) to 

address this deficiency by implementing 

nitrogen oxides (NOX) and sulfur 

dioxide (SO2) emission limits necessary 

at the San Juan Generating Station 

(SJGS), to prevent such interference. 

EPA found in January 2009 that New 

Mexico had failed to submit a SIP 

addressing certain regional haze (RH) 

requirements, including the requirement 

for best available retrofit technology 

(BART). The Clean Air Act required 

EPA to promulgate a FIP to address RH 

requirements by January 2011. This FIP 

addresses the RH BART requirement for 

NOX for SJGS. In addition, EPA is 

implementing sulfuric acid (H2SO4) 

hourly emission limits at the SJGS, to 

minimize the contribution of this 

compound to visibility impairment. 

This action is being taken under section 

110 and part C of the CAA. 

DATES: This final rule is effective on: 

September 21, 2011. 

ADDRESSES: EPA has established a 

docket for this action under Docket ID 

No. EPA–R06–OAR–2010–0846. All 

documents in the docket are listed in 

the Federal eRulemaking portal index at 

http://www.regulations.gov and are 

available either electronically at http:// 

www.regulations.gov or in hard copy at 

EPA Region 6, 1445 Ross Ave., Dallas, 

TX 75202–2733. To inspect the hard 

copy materials, please schedule an 

appointment during normal business 

hours with the contact listed in the FOR

FURTHER INFORMATION CONTACT section. 

A reasonable fee may be charged for 

copies. 

FOR FURTHER INFORMATION CONTACT: Joe 

Kordzi, EPA Region 6, (214) 665–7186, 

kordzi.joe@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Throughout this document wherever 

‘‘we,’’ ‘‘us,’’ ‘‘our,’’ or ‘‘the Agency’’ is 

used, we mean the EPA. Unless 

otherwise specified, when we say the 

‘‘San Juan Generating Station,’’ or 

‘‘SJGS,’’ we mean units 1, 2, 3, and 4, 

inclusive. 

Overview 

The Clean Air Act requires states to 

prevent air pollution from sources 

within their borders from impairing air 

quality and visibility in other states. The 

Act also requires states to reduce 

pollution from significant sources 

whose emissions reduce visibility in the 

nation’s pristine and wilderness areas 

(such as the Grand Canyon), and 

contribute to regional haze. When a 

state has not adopted plans as required 

by these provisions, EPA must put such 

a plan in place, known as a Federal 

Implementation Plan (FIP). 

In this action, EPA is finalizing a FIP 

for New Mexico to address emissions 

from one source: the San Juan 

Generating Station coal-fired power 

plant. EPA is finding that the other New 

Mexico pollution sources are adequately 

controlled to eliminate interference with 

the clean air visibility programs of other 

states. This FIP can be replaced by a 

state plan that EPA finds meets the 

applicable Clean Air Act requirements. 

The federal plan will remain in effect no 

longer than necessary. 

In December 2010, EPA proposed to 

disapprove a portion of the New Mexico 

Interstate Transport State 

Implementation Plan (SIP), specifically 

the New Mexico Interference with 

Visibility SIP, and proposed a sourcespecific FIP to cut pollution from San 

Juan Generating Station to address 

adverse visibility impacts. 

The federal plan also addresses a 

portion of EPA’s 2-year obligation under 

the Clean Air Act’s Regional Haze Rule 

to implement a federal plan when the 

state failed to meet the January 2009 

deadline. This shortfall is being 

addressed by establishing emissions 

limits representing Best Available 

Retrofit Technology (BART) for nitrogen 

oxide (NOx) pollution at the San Juan 

Generating Station power plant. 

The federal plan will require the San 

Juan Generating Station to cut emissions 

to improve scenic views at 16 of our 

most treasured parks including the 

Grand Canyon, Mesa Verde and 

Bandelier National Monument. 

Pollution from this power plant impacts 

four states including Arizona, Utah, 

Colorado, and New Mexico. Improved 

air quality also results in public health 

benefits. 

Public Service Company of New 

Mexico (PNM) owns the San Juan 

Generating Station power plant. The 

power plant has four coal-fired 

generating units. It is located in San 

Juan County, 15 miles west of 

Farmington in northwest New Mexico. 

The thirty-year-old San Juan Generation 

Station power plant is one of the largest 

sources of NOx pollution in the United 

States. 

The federal plan requires the San Juan 

Generating Station coal-fired power 

plant to reduce nitrogen oxide and 

sulfur dioxide pollution to 0.05 pounds 

per million BTU and 0.15 pounds per 

million BTU respectively. 

By addressing nitrogen oxide 

pollution requirements of both Interstate 

Transport and the Regional Haze Rule, 

PNM will meet these two Clean Air Act 

requirements for NOx emission limits 

for the power plant with only one round 

of improvements. This regulatory 

certainty will help guide PNM’s 

business decisions regarding capital 

investments in pollution controls. 

EPA evaluated reliable and proven 

pollution technologies as part of its 

decision. EPA determined Selective 

Catalytic Reduction (SCR) to be the most 

cost-effective pollution control to 

achieve the emission reductions 

outlined in the federal plan. Evaluation 

of a less expensive alternative, Selective 

Non Catalytic Reduction (SNCR), 

showed that SNCR at the San Juan 

Generating Station coal-fired power 

plant achieves far less reduction in 

pollution and less visibility 

improvement, and does not fully meet 

the requirement of the Act for Best 

Available Retrofit Technology (BART). 

EPA held an extended public 

comment period on this action, an open 

house, and a public hearing. After 

careful review of information provided 

during the public comment period, EPA 

revised its calculation of the associated 

cost investment from $229 million to 

$345 million. Also, in consideration of 

comments about the time to comply 

with the new emissions limits, EPA 


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extended the time for compliance with 

the nitrogen oxide pollution emission 

limit from 3 years to 5 years, the 

maximum period allowed by the Clean 

Air Act. 

This investment will reduce the 

visibility impacts due to this facility by 

over 50% at each one of the 16 national 

parks and wilderness areas in the area, 

and promote local tourism by 

decreasing the number of days when 

pollution impairs scenic views. 

Although today’s action is taken to 

address visibility impairments, PNM 

will also reduce public health impacts 

by cutting NOX pollution by over 80% 

by installing reliable pollution-control 

technology on its four coal-fired power 

generation units over the next five years. 

EPA will review the regional haze 

plan that the State submitted in July 

2011, and if there is significant new 

information that changes our analysis, 

EPA will make appropriate revisions to 

today’s decision. 

Detailed Outline 

I. Summary of Our Proposal 

II. Final Decision 

A. Interstate Transport 

B. NOX BART Determination for the San 

Juan Generating Station (SJGS) 

C. Compliance Timeframe 

III. Analysis of Major Issues Raised by 

Commenters 

A. Comments on the Costs of the NOX

BART Determination 

B. Comments on our Proposed NOX BART 

Emission Limits 

C. Comments on our Proposed SO2

Emission Limit 

D. Comments on our Proposed H2SO4 and 

Ammonia Emission Limits and Other 

Pollutants 

E. Comments on the Emission Limit 

Compliance Schedule 

F. Comments on the Conversion of the 

SJGS to a Coal-to-Liquids Plant With 

Carbon Capture as a Means of Satisfying 

BART 

G. Comments on Health and Ecosystem 

Benefits, and Other Pollutants 

H. Miscellaneous Comments 

I. Comments in Favor of Our Proposal 

J. Comments Arguing Our Proposal Would 

Hurt the Economy and/or Raise 

Electricity Rates 

K. Comments Arguing Our Proposal Would 

Help the Economy 

L. Comments Requesting an Extension to 

the Public Comment Period 

M. Comments Requesting We Defer Action 

in Favor of a New Mexico SIP Submittal 

N. Comments Generally Against Our 

Proposal 

O. Comments on Legal Issues 

P. Modeling Comments 

IV. Statutory and Executive Order Reviews 

I. Summary of Our Proposal 

On January 5, 2011, we published the 

proposal on which we are now taking 

final action. 76 FR 491. We proposed to 

disapprove a portion of the SIP revision 

received from the State of New Mexico 

on September 17, 2007, 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. Having proposed to 

disapprove these provisions of the New 

Mexico SIP, we proposed a FIP to 

address the requirements of section 

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

visibility to ensure that emissions from 

sources in New Mexico do not interfere 

with the visibility programs of other 

states. We proposed to find that New 

Mexico’s sources, other than the San 

Juan Generating Station (SJGS), are 

sufficiently controlled to eliminate 

interference with the visibility programs 

of other states, and for the SJGS, we 

proposed specific SO2 and NOX

emissions limits that will eliminate 

such interstate interference. For SO2, we 

proposed to require the SJGS to meet an 

emission limit of 0.15 pounds per 

million British Thermal Units (lb/ 

MMBtu). For NOX, we proposed to 

implement a NOX emission limit of 0.05 

lbs/MMBtu, based on our BART 

determination, as discussed below. 

Separate from our proposal under 

Section 110 of the CAA, we 

simultaneously evaluated whether the 

SJGS met certain other related 

requirements under the Regional Haze 

(RH) program under Sections 169A and 

169B of the CAA. Regional Haze SIPs 

were due December 17, 2007. In January 

2009, we made a finding that New 

Mexico had failed to submit a RH SIP 

addressing the requirements of 40 CFR 

51.309(d)(4) and (g). 74 FR 2392 

(January 15, 2009). Under the CAA, we 

are required to promulgate a FIP within 

two years of the effective date of a 

finding that a State has failed to submit 

a SIP unless the State submits a SIP and 

we approve that SIP within the two year 

period. CAA § 110(c). At the time of the 

proposed FIP, New Mexico had not yet 

submitted a substantive RH SIP 

addressing, among other things, the 

requirement that certain stationary 

sources install BART for NOX. (On July 

5, 2011, New Mexico submitted a RH 

SIP, which we discuss later in this 

Notice.) Based on our evaluation of the 

RH BART requirements of section 40 

CFR 51.309(d)(4), we proposed to find 

that the SJGS is subject to BART under 

section 40 CFR 51.309(d)(4), and/or 

51.308(e). We proposed a FIP which 

contained NOX BART limits for the 

SJGS based on our proposed NOX BART 

determination. We proposed to require 

that the SJGS meet a NOX emission limit 

of 0.05 lb/MMBtu individually at Units 

1, 2, 3, and 4. We noted this NOX limit 

is achievable by installing and operating 

Selective Catalytic Reduction (SCR). 

We proposed that both the NOX and 

SO2 emission limits be measured on the 

basis of a 30 day rolling average. We 

also proposed hourly average emission 

limits of 1.06 × 10¥4 lb/MMBtu for 

H2SO4 and 2.0 parts per million volume 

dry (ppmvd) ammonia adjusted to 6 

percent oxygen, to minimize the 

contribution of these compounds to 

visibility impairment. We solicited 

comments on a range of 2–6 ppmvd for 

ammonia, and 1.06 × 10¥4 to 7.87 × 

10¥4 lb/MMBtu for H2SO4. 

Additionally, we proposed monitoring, 

record-keeping and reporting 

requirements to ensure compliance with 

these emission limitations. 

Lastly, we proposed that compliance 

with the emission limits must be within 

three (3) years of the effective date of 

our final rule. We solicited comments 

on alternative timeframes, up to five (5) 

years from the effective date our final 

rule. In our proposal, we did not 

address whether the state had met other 

requirements of the RH program, which 

we will address in later actions. Please 

see our proposal for more details. 

II. Final Decision 

A. Interstate Transport 

We are disapproving the portion of 

the SIP revision received from the State 

of New Mexico on September 17, 2007, 

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. The 2007 SIP 

submission by New Mexico anticipated 

that the State would submit a 

substantive RH SIP to meet the 

requirements of section 

110(a)(2)(D)(i)(II). 

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

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.’’ States were required 

to submit a SIP by December 2007 with 

measures to address regional haze— 

visibility impairment that is caused by 

the emissions of air pollutants from 

numerous sources located over a wide 

geographic area. Under the RH program, 

each State with a Class I area must 

submit a SIP with reasonable progress 

goals for each such area that provides 

for an improvement in visibility for the 


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1CAA 42 U.S.C. 7472(a). The list of mandatory 

class I federal areas where visibility is an important 

value is codified at 40 CFR part 81 subpart D. 2See 74 FR 2392. 

3A State Regional Haze SIP was due under the 

CAA by Dec. 17, 2007, and EPA was obligated to 

either approve an RH SIP or promulgate a FIP by 

January 15, 2011. See CAA Section 110(c)(1)(B). 

most impaired days and ensures no 

degradation of the best days. (The 

‘‘Class I’’ federal areas 1 affected by the 

SJGS include 16 of our most treasured 

parks, such as the Grand Canyon, Mesa 

Verde, and Bandelier National 

Monument. Emissions from this power 

plant impact four states including 

Arizona, Utah, Colorado, and New 

Mexico.) 

Because of the often significant 

impacts on visibility from the interstate 

transport of pollutants, we interpret the 

‘‘good neighbor’’ provisions of section 

110 of the CAA 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. This is consistent with 

the requirements in the RH program 

which explicitly require each State to 

address its share of the emission 

reductions needed to meet the 

reasonable progress goals for 

surrounding Class I areas. 64 FR 35714, 

35735 (July 1, 1999). 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, including New 

Mexico, worked through a regional 

planning organization, the Western 

Regional Air Partnership (WRAP), to 

develop strategies to address regional 

haze. To help the State in establishing 

reasonable progress goals, the WRAP 

modeled future visibility conditions. 

The WRAP modeling assumed 

emissions reductions from each State, 

based on extensive consultation among 

the States as to appropriate strategies for 

addressing haze. In setting reasonable 

progress goals, States in the West 

generally relied on this modeling. As 

explained in the notice of proposed 

rulemaking, 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). 

As a result of our disapproval of New 

Mexico’s SIP, submitted to meet the 

requirements of section 

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

visibility, we are promulgating a FIP to 

ensure that emissions from New Mexico 

sources do not interfere with the 

visibility programs of other states. We 

find that New Mexico sources, other 

than the SJGS, are sufficiently 

controlled to eliminate interference with 

the visibility programs of other states 

because the federally enforceable 

emission limits for these sources are 

consistent with those relied upon in the 

WRAP modeling. The SO2 and NOX

emissions relied upon in the WRAP 

modeling for the SJGS, however, are not 

federally enforceable. Therefore, we are 

establishing federally enforceable SO2

emissions limits that will address these 

discrepancies and eliminate interstate 

interference based on current emissions 

that satisfy the assumptions in the 

WRAP modeling. We are finalizing our 

proposal to require the SJGS to meet an 

SO2 emission limit of 0.15 lb/MMBtu, 

the rate assumed in the WRAP 

modeling. We proposed a 30 day rolling 

average for units 1, 2, 3, and 4 of the 

SJGS. However, in response to a 

comment we received, we are changing 

our proposed averaging period for these 

emission limits from a straight 30 day 

calendar average to one calculated on 

the basis of a Boiler Operating Day 

(BOD). 

Besides not being federally 

enforceable, the NOx emissions that 

were assumed in the WRAP modeling 

cannot be achieved without additional 

NOx controls for the SJGS to prevent 

interference with visibility pursuant to 

the requirements of section 

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

choosing, however, not to use the 

WRAP assumptions to make a 

determination on the enforceable NOx 

controls necessary to prevent visibility 

interference, as we are doing for the SO2

controls. Instead, we are addressing 

NOx control for the SJGS by fulfilling 

our duty under the BART provisions of 

the RH rule to promulgate a RH FIP for 

New Mexico to address, among other 

elements of the visibility program, the 

requirement for BART.2 We do not 

believe it is prudent to delay a NOx 

BART determination for the SJGS, 

because we have determined that the 

BART requirements are more stringent 

than the visibility transport 

requirements. Separating the visibility 

transport and BART rulemakings could 

result in near-term requirements for the 

utility to install one set of controls and 

capital expenditures, to only satisfy our 

obligation under section 

110(a)(2)(D)(i)(II), followed shortly 

thereafter by different requirements for 

controls and capital expenditures to 

satisfy our obligation under BART. This 

could result in unnecessary costs and 

confusion. 

We did receive a New Mexico RH SIP 

submittal on July 5, 2011, but it came 

several years after the statutory 

deadline, and after the close of the 

comment period on today’s action.3 In 

addition, because of the missed 

deadline for the visibility transport, we 

are under a court-supervised consent 

decree deadline with WildEarth 

Guardians of August 5, 2011, to have 

either approved the New Mexico SIP or 

to have implemented a FIP to address 

the 110(a)(2)(D)(i) provision. It would 

not have been possible to review the 

July 5, 2011 SIP submission, propose a 

rulemaking, and promulgate a final 

action by the dates required by the 

consent decree. Notwithstanding these 

facts, we did comment during the 

State’s public comment period for their 

proposed RH SIP in May 2011 and we 

did evaluate the technology advocated 

as BART in the State’s proposed RH SIP: 

SNCR, as discussed in further detail 

elsewhere in this Notice. 

B. NOx BART Determination for the San 

Juan Generating Station (SJGS) 

We find that the SJGS is subject to 

BART under sections 40 CFR 

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

action, we are adopting a FIP that 

partially addresses the BART 

requirements of the RH program for 

New Mexico. We are finalizing our 

proposal to require the SJGS to meet a 

NOx emission limit of 0.05 lb/MMBtu 

individually at Units 1, 2, 3, and 4. As 

we discuss elsewhere in our response to 

comments, we find there is ample 

support for this decision. However, in 

response to a comment we received, we 

are changing our proposed averaging 

period for these emission limits from a 

straight 30 day calendar average to one 

calculated on the basis of a boiler 

operating day (BOD). We also received 

a comment requesting we revise our 

proposed unit-by-unit NOx limitation, 

and replace it with a plant wide average 

NOx limitation. As we note in our 

response to this comment, although we 

are open to combining the BOD and 

plant wide averaging schemes, this 

presents a significant technical 

challenge in having a verifiable, 

workable, and enforceable algorithm for 

calculating such an average. Due to our 

obligation to ensure the enforceability of 

the emission limits we are imposing in 

our FIP, we leave it to New Mexico to 

take up this matter in a future SIP 

revision, should they deem it worth 

pursuing. We are confident this issue 


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4 76 FR 491, 504. 

5See San Juan Generating Station Site Visit, 5/23/ 

11, which is viewable in the docket. As explained 

in a letter, dated May 17, 2011, the visit was solely 

for the purpose of reviewing and responding to 

comments. It was not an opportunity to introduce 

additional comments, and we did not receive any 

comments as a result of this visit. 

6 76 FR 12305. 

7 76 FR 1578. 

can be addressed prior to the 

installation of the emission controls 

required to satisfy our FIP. 

We are also finalizing our proposal 

requiring the SJGS to meet an H2SO4

emission limit of 2.6 × 10¥4 lb/MMBtu 

to minimize its contribution to visibility 

impairment. We are promulgating 

monitoring, record-keeping and 

reporting requirements to ensure 

compliance with this emission limit. As 

discussed in our response to comments, 

after careful consideration of the 

comments we received concerning our 

proposal to require the SJGS to meet an 

hourly average emission limit of 2.0 

parts ppmvd for ammonia, we have 

determined that neither an ammonia 

limit, nor ammonia monitoring is 

warranted, and we are not finalizing 

ammonia limits or monitoring 

requirements. 

C. Compliance Timeframe 

We originally proposed a compliance 

schedule of 3 years for SJGS for the 

NOX, SO2, ammonia, and H2SO4

emission limits, and solicited comments 

on alternative timeframes of less than 3 

years and up to 5 years (the maximum 

allowed under the statute).4 As noted 

above, we are no longer requiring an 

ammonia emission limit. Also, as 

discussed in our response to comments, 

we carefully considered comments 

urging a longer compliance schedule 

due to site-specific issues such as the 

congestion of existing equipment 

(which could slow the retrofit process), 

historical information on SCR 

installation times, and our own 

observation of the site conditions,5 and 

we now conclude that a longer 

compliance schedule is more 

appropriate. Consequently, compliance 

with the NOX, SO2, and H2SO4 emission 

limits will now be required within 5 

years—rather than 3 years—of the 

effective date of our final rule. (This 

issue is discussed in further detail in 

Section III.E., below.) 

III. Analysis of Major Issues Raised by 

Commenters 

Our January 5, 2011 proposal 

included a 60 day public comment 

period, which ended on March 7, 2011. 

We subsequently extended that 

comment period until April 4, 2011.6

We also held an open house and a 

public hearing in Farmington, NM, on 

February 17, 2011.7 We received in 

excess of 13,000 comments. 

In light of the very large number of 

comments received and the significant 

overlap between many comments, we 

have grouped some comments together. 

We have summarized and provided 

responses to each significant argument, 

assertion, and question contained 

within the totality of the comments. Full 

responses to comments can be found in 

our Complete Response to Comments 

for NM Regional Haze/Visibility 

Transport FIP. 

A. Comments on the Costs of the NOX

BART Determination 

We received many comments related 

to various aspects of our cost analysis 

that fell into four major categories. First, 

we received general comments opining 

on the appropriateness of our cost 

analysis. Second, we received 

comments that were technical and 

related to specific line items in the cost 

analysis (e.g., additional steel, SCR 

bypass, sorbent injection, etc.). Third, 

we received comments that expressed 

general concern that the costs of the 

controls would be passed to the SJGS’s 

customer base in the form of electricity 

rate increases. Fourth, we received 

comments that opined on the use of the 

Regional Haze Rule’s (RHR) reliance on 

the EPA Air Pollution Control Cost 

Manual (the Cost Manual) to estimate 

the cost of the SCR installations. We 

address the more significant comments 

within these categories individually 

below. 

1. General Cost Comments 

Comment: The National Park Service 

(NPS) and the U.S. Forest Service 

(USFS) separately presented a great deal 

of information in support of their 

opinions that Public Service Company 

of New Mexico’s (PNM) contractor, 

Black &Veatch (B&V) overestimated the 

cost of installing SCR on the units of the 

SJGS. PNM is a part owner and the 

operator of the SJGS. The following is a 

combined summary of their separate 

comments. 

The NPS and the USFS cited a large 

number of well-documented recent 

industry studies or surveys, which they 

use to conclude that PNM has 

overestimated its SCR costs, expressed 

in dollars per kilowatt. They stated that 

PNM has not provided valid 

information to justify their higher cost 

estimates for SCR installation at the 

SJGS. Additionally, the USFS stated 

PNM’s contractors went against our 

guidance which recommends using the 

Cost Manual to ensure a transparent and 

consistent means to conduct cost 

analyses across the nation. The USFS 

took issue with PNM’s estimation of 

indirect (soft) costs which include: 

engineering costs; construction and field 

expenses (e.g., costs for construction 

supervisory personnel, office personnel, 

rental of temporary offices, etc.); 

contractor fees; and start-up and 

performance test costs. Also, the NPS 

stated that B&V’s improperly escalated 

costs and its calculations did not 

consider the weakening of labor markets 

that has occurred since they set up their 

spreadsheets in 2007. 

Response: We found that PNM raised 

some legitimate points about costs, and 

as discussed elsewhere in this notice, 

we have adjusted several of our cost 

estimates upward based on those points. 

However, in large part, we agree with 

the NPS that PNM’s estimated costs for 

installing SCR on the units of the SJGS 

are higher than justified. Please see our 

other responses to comments for more 

details on how we have adjusted our 

cost estimates. The following table 

illustrates our revised costs in terms of 

$/kW. These costs agree with the ranges 

presented by the NPS and the USFS in 

their comments, which can be viewed in 

our Complete Response to Comments 

for NM Regional Haze/Visibility 

Transport FIP document: 

TABLE 1—EPA REVISED ESTIMATED COSTS OF INSTALLING SCR ON THE UNITS OF THE SJGS 

Unit 1 Unit 2 Unit 3 Unit 4 

Proposed ($/kW) .............................................................................................................................. $144 $155 $116 $110 

Final ($/kW) ..................................................................................................................................... 211 234 179 165 


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8Revised BART Cost Effectiveness Analysis for 

Selective Catalytic Reduction at the Public Service 

Company of New Mexico San Juan Generating 

Station, November 2010, pp. 28–29. 

9Comments submitted by United States 

Department of Interior, National Park Service, dated 

3/31/11. 

10New Mexico Environment Department, 

Appendix A, NMED, Air Quality Bureau, BART 

Determination, Public Service Company of New 

Mexico, San Juan Generating Station, Units 1–4, 6/ 

21/10. 

11See Exhibit 1, RTC Revised Cost Analysis. 

12Please see our Complete Response to 

Comments for NM Regional Haze/Visibility 

Transport FIP document. 

13 70 FR at 39168 (July 6, 2005). 

We note, that as required by the BART 

Guidelines, ‘‘[i]n order to maintain and 

improve consistency, cost estimates 

should be based on the OAQPS Control 

Cost Manual, [now renamed ‘‘EPA Air 

Pollution Control Cost Manual, Sixth 

Edition, EPA/452/B–02–001, January 

2002] where possible.’’ 70 FR at 39166 

(July 6, 2005). As explained more fully 

in our Complete Response to Comments 

for NM Regional Haze/Visibility 

Transport FIP document, we also agree 

with the USFS that owner’s costs are not 

an appropriate cost item to include in a 

BART cost estimate, as owners costs are 

not included in the Cost Manual. 

Comment: PNM and its consultants 

estimated the cost of retrofitting SJGS 

with SCRs to be between $194 million 

and $261 million per unit (depending 

on the unit) with a total cost of $908 

million for all four units. EPA maintains 

that SCRs can be purchased and 

installed for much less—between $52 

million and $63 million per unit for a 

total of about $229 million. EPA’s 

estimates of annual operating costs for 

the SCRs are also much lower than 

PNM’s estimate. PNM’s analysis 

indicates annual operating costs for all 

four SCRs would be approximately $114 

million per year, whereas EPA expects 

PNM to be capable of operating the 

SCRs for only about $28 million per 

year. In short, EPA believes that SCRs 

cost $679 million less, or one quarter of 

the amount estimated by PNM. The 

commenter calls our cost estimate into 

question, since the disparity between 

these two estimates is large. 

Response: B&V estimated it would 

cost between $446/kW and $559/kW to 

retrofit SCR on the SJGS units. Five 

industry studies conducted between 

2002 and 2007 have reported the 

installed unit capital cost of SCRs to be 

$79/kW to $316/kW, where the upper 

end of the range is for very complex 

retrofits that are severely site 

constrained.8 Others have noted the 

anomalously high costs reported for 

SJGS.9 10 We revised our cost estimates 

based on some comments highlighted in 

comments, but even with those changes, 

our revised costs for SCR are from $165/ 

kW to $234/kW,11 still well within the 

accepted range of expected costs for 

such controls.12

B&V’s SJGS costs are unusually high 

for four principal reasons: (1) Using a 

methodology (e.g., Allowance for Funds 

Used During Construction (AFUDC)) 

that has been disallowed under EPA’’s 

Cost Manual methodology and 

specifically disallowed for SCR (see 

discussion at footnote 28); (2) 

consistently using assumptions at the 

upper end of the range for key SCR 

components (e.g., SCR backpressure; 

stiffening design pressure); (3) including 

costs for equipment that is not necessary 

for a SCR (e.g., balanced draft 

conversion, sorbent injection, SCR 

bypass); and (4) using excessive 

contingencies. The BART Guidelines 

require that ‘‘documentation’’ be 

provided for ‘‘any unusual 

circumstances that exist for the source 

that would lead to cost-effectiveness 

estimates that would exceed that for 

recent retrofits.’’ 13 The B&V analysis 

does not support its unusually high cost 

estimates. 

Further, much of the information that 

could have supported a claim that site 

specific issues at SJGS result in costs 

that are outside of the normal range is 

missing. Specifically, the B&V analysis 

lacked information such as project 

schedules, general arrangement site 

plans showing SCR and duct layout, 

requests for proposal (RFPs), vendor 

proposals, and a complete description of 

existing facilities. 

Instead of preparing a site-specific 

SCR design, B&V in most circumstances 

made a worst case, upper bound 

assumption that, taken together, result 

in overall costs that are significantly 

outside of the normal range for SCR. 

However, B&V provided no record 

support for their decision to choose the 

upper end of the range for nearly every 

aspect of the cost of SCRs. It is unlikely 

that so many upper bound assumptions 

could be justified, and if B&V believed 

that they were justified, they should 

have explored that proposition in a risk 

analysis. Therefore, we believe that our 

approach to considering site specific 

conditions that would lead to costs 

outside of the normal range, is justified. 

Comment: Private citizens submitted 

comments that the costs to PNM will be, 

alternatively, $250, $500, or $750 

million dollars, and that PNM’s 

estimates are overstated, and that any 

investment in the plant is an investment 

in the future, and that the plant and its 

jobs will not be threatened by the 

proposed emission reductions. 

Response: As we discuss elsewhere in 

our response to comments, we agree that 

the cost of installing SCR on the four 

units of the SJGS is considerably lower 

than PNM estimated. 

Comment: The CAA visibility 

provisions, EPA’s own RH regulations, 

and the preambles to those rules all 

envision a ‘‘source-by-source’’ approach 

to BART, which by its nature must 

account for site-specific challenges at 

each facility. However, despite the 

significant amount of information 

provided by PNM in its original BART 

analysis, in subsequent exchanges with 

the New Mexico Environment 

Department (NMED) and EPA, and in 

meetings between EPA and PNM 

specifically to discuss the site-specific 

challenges at SJGS, EPA did not to take 

into account many of the most 

significant costs that are essential in 

calculating an accurate cost estimate of 

installing SCRs at SJGS. 

Response: We agree that a source-bysource analysis is appropriate, but we 

do not believe that B&V provided an 

acceptable analysis. First, the B&V costs 

were extrapolated from other facilities, 

based on confidential information that 

was not provided in response to our 

requests. Second, the B&V costs were 

estimated using worst-case upper 

bounds in lieu of making a site-specific 

estimate, as discussed above. Third, 

their costs included components that 

are not required at this site, and further 

assumed contingency factors beyond 

those normally expected. Therefore, we 

believe, with the exception of certain 

issues related to site congestion that are 

addressed separately in other 

comments, site-specific conditions were 

properly considered. 

Comment: To justify the approach 

based entirely on the median of 

different control technologies, EPA 

downplays the complicated process of 

designing and constructing an SCR, 

thereby not only ignoring the 

technology itself, but also the site 

specific-factors that must be considered 

at SJGS. SCRs at SJGS would have to be 

constructed so that each SCR can be 

positioned at the proper point in the 

flue gas stream, which will significantly 

complicate the foundation and supports 

that will be needed, resulting in 

additional costs of $35,630,000 that EPA 

failed to recognize or consider. 

Response: All SCRs have to be 

constructed so that each SCR can be 

positioned at the proper point in the 

flue gas stream, with proper foundation 

and supports; this is not unique to the 

SJGS. Over 300 retrofit SCRs have been 

installed since the early 1990s in the 


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Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 52393 

14 J.A. Hines and others, Design for 

Constructability—A Method for Reducing SCR 

Project Costs, Mega, 2001, available at: http:// 

www.babcock.com/library/pdf/br-1720.pdf; see also 

Institute of Clean Air Companies (ICAC), White 

Paper, Selective Catalytic Reduction (SCR) Control 

of NOX Emissions from Fossil Fuel-Fired Electric 

Power Plants, May 2009, EPA–R09–OAR–2009– 

0598–0032 and Walter Nischt and others, Update of 

Selective Catalytic Reduction Retrofit on a 675 MW 

Boiler at AES Somerset, ASME International Joint 

Power Generation Conference, July 24–25, 2000, 

available at: http://www.babcock.com/library/pdf/ 

br-1703.pdf. 

15Revised BART Cost Effectiveness Analysis for 

Selective Catalytic Reduction at the Public Service 

Company of New Mexico San Juan Generating 

Station, November 2010, p. 5. 

16 ‘‘You are expected to identify potentially 

applicable retrofit control technologies that 

represent the full range of demonstrated 

alternatives.’’ 70 FR at 39164. 17 76 FR at 499. 

United States. Accordingly, 

constructability issues are well 

understood. Standard design and 

construction management methods have 

been developed from these 300+ 

existing installations.14 This experience 

would inform the design and 

construction of the SJGS SCR, resulting 

in significant economies compared to 

the estimates presented by B&V based 

on a very rough preliminary design that 

has not been optimized for 

constructability. The record does not 

identify any unusual site-specific 

conditions that would result in direct 

installation costs for SJGS that are 

substantially higher than upper bound 

direct installation costs reported by 

other SCR design firms for similarly 

complex sites. In fact, B&V has provided 

no support in the record for its 

assumptions. Finally, the design costs 

are not a direct installation cost, but 

rather indirect costs discussed 

elsewhere in our response to comments. 

Comment: EPA suggests that the 

engineering needed to design four SCRs 

can be completed all at the same time, 

thus saving time and money. While 

some economies may arise with a 

multiple SCR installation, as lessons 

learned in designing and installing one 

SCR are applied to the next, a three-year 

deadline would require PNM to design 

all four SCRs at the same time. 

Designing all four SCRs at once would 

require four separate design and 

construction teams, which would 

eliminate the opportunity to apply any 

experience gained. As a result, the costs 

associated with designing the SCRs will 

be much higher on a shorter timeframe, 

not lower as EPA appears to suggest. 

The short, three-year deadline also 

allows no time for additional design 

work that may be needed to address 

unforeseen engineering challenges that 

are likely to arise at each unit. 

Response: We disagree with this 

comment and believe it 

mischaracterizes our analysis. In our 

proposal, we simply noted that 

‘‘multiple unit discounts may apply to 

much of this equipment.’’ 15 Multiple 

unit discounts were not assumed in our 

revised cost analysis. It is well 

established that economies arise from 

constructing multiple units at a single 

site. Economies will arise, for example, 

from common equipment that would 

serve all four units, such as the 

ammonia injection system and the 

control system. Economies arise from 

shop and material discounts based on 

quantity. Our cost analysis, however, 

did not assume any discount for 

multiple unit discounts. Regardless, for 

other reasons as stated elsewhere in our 

response to comments, we are finalizing 

a schedule which calls for compliance 

with the emission limits within 5 

years—rather than 3 years—of the 

effective date of our final rule. 

Comment: The proposed FIP costs do 

not acknowledge, or take into account, 

the $330 million incurred in the past 

five years implementing a 

comprehensive emission control plan at 

SJGS. EPA’s proposed BART 

determination for the SJGS is too 

expensive and EPA should accept the 

recently installed pollution control 

equipment at the SJGS as BART. 

Response: We did, as part of our NOX

BART evaluation, consider the controls 

previously installed by PNM as a result 

of its March 10, 2005 consent decree 

with the Grand Canyon Trust, Sierra 

Club, and NMED. These controls 

included the installation of low-NOX

burners with overfire air ports, a neural 

network system, and a pulse jet fabric 

filter. However, when making the NOX

BART determination, we are obligated 

by the RHR to examine additional 

retrofit technologies.16 In so doing, we 

have determined that SCR is cost 

effective and results in significant 

visibility improvements at a number of 

Class I areas, over and above the 

existing pollution controls currently 

installed. 

Comment: EPA proposes to conclude 

that, because the SJGS currently is 

subject to a federally enforceable permit 

limit of 0.30 lb/MMBtu for NOX, which 

is less restrictive than the WRAP 

modeling’s assumed NOX rates for those 

units (as characterized by EPA), 

additional NOX emission controls are 

required. EPA, however, proposes on 

this basis to determine that the BART 

emission limit for units 1 through 4 at 

SJGS is not 0.27 (or 0.28) lb/MMBtu but 

is instead 0.05 lb/MMBtu based on the 

application of SCR technology. As a 

result, EPA discontinues its evaluation 

of other technologies before fully 

assessing their relative costeffectiveness and other factors 

mandated by section 169A(g)(2) of the 

CAA. EPA’s analytical approach is in 

conflict with its own BART rules and is 

inconsistent with a logical approach to 

assessing relative cost-effectiveness of 

various technology options. 

Response: We disagree with this 

commenter’s characterization of our 

analysis. As discussed in our proposal 

(76 FR 491), once we established that 

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

subject to BART, we conducted a full 

five factor BART analysis (40 CFR 

51.308(e)(1)(ii)(A)), rather than relying 

on the WRAP modeling. In conducting 

the BART analysis, we identified all 

available retrofit control technologies, 

including Selective Non Catalytic 

Reduction (SNCR), considering the 

technology available, the costs of 

compliance, the energy and non-air 

quality environmental impacts of 

compliance, any pollution control 

equipment in use at the source, the 

remaining useful life of the source, and 

the degree of improvement in visibility 

which may reasonably be anticipated to 

result from the use of such technology. 

In so doing, we did assess other NOX

control technologies.17

Comment: Several commenters stated 

EPA should follow its own promulgated 

RHR and follow New Mexico’s 

recommendation for BART 

determinations These commenters are 

referring to the proposal that was sent 

to New Mexico’s Environmental 

Improvement Board on February 11, 

2011 (later formally submitted to EPA 

on July 5, 2011). The proposed revision 

to the SIP finds that BART for SJGS is 

SNCR—not SCR. One commenter 

believed that the application of the 2005 

BART Guidelines supports a NOX

emission rate for the SJGS of between 

0.23 to 0.39 lb/MMBtu, as opposed to 

our proposed FIP of 0.05 lb/MMBtu, 

which requires costly SCR technology. 

One commenter stated the presumptive 

limits should be required ‘‘unless you 

[the BART-determining authority] 

determine that an alternative control 

level is justified based on consideration 

of the statutory factors.’’ 70 FR at 39171. 

Except for cyclone boilers (which are 

not present at SJGS), this commenter 

noted, our presumptive NOX BART 

limits are not based on application of 

SCR; as noted above, they are instead 

based on the use of combustion 

controls. Further, EPA determined that 

when current combustion control 

technology would be insufficient to 

meet the presumptive limits, it would 


jlentini on DSK4TPTVN1PROD with RULES2
52394 Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 

18 70 FR at 39158. 

19 70 FR at 39131. 

20 76 FR 491, 499. 

be appropriate to ‘‘consider whether 

advanced combustion control 

technologies such as rotating opposed 

fire air should be used to meet these 

[presumptive] limits.’’ Id. at 39172. 

Another commenter asserted that a 

proper BART assessment would take the 

presumptive limits into account by 

beginning with the assumption that the 

established presumptive limit for these 

units is appropriate, and then would 

proceed with an analysis of whether the 

least stringent control options could 

achieve that limit. A five-factor BART 

analysis of increasingly stringent control 

options could then properly assess 

incremental costs (and costeffectiveness) and any benefits of 

requiring more stringent controls. 

Response: We note the RHR states: 

For each source subject to BART, 40 CFR 

51.308(e)(1)(ii)(A) requires that States 

identify the level of control representing 

BART after considering the factors set out in 

CAA section 169A(g), as follows: 

States must identify the best system of 

continuous emission control technology for 

each source subject to BART taking into 

account the technology available, the costs of 

compliance, the energy and non-air quality 

environmental impacts of compliance, any 

pollution control equipment in use at the 

source, the remaining useful life of the 

source, and the degree of visibility 

improvement that may be expected from 

available control technology.18

The RHR also states: 

States, as a general matter, must require 

owners and operators of greater than 750 MW 

power plants to meet these BART emission 

limits. We are establishing these 

requirements based on the consideration of 

certain factors discussed below. Although we 

believe that these requirements are extremely 

likely to be appropriate for all greater than 

750 MW power plants subject to BART, a 

State may establish different requirements if 

the State can demonstrate that an alternative 

determination is justified based on a 

consideration of the five statutory factors.19

We followed the five statutory factors 

when assessing NOX BART at the SJGS, 

in determining that a different level of 

BART control was warranted.20 This 

analysis included an examination of 

whether other technologies should be 

BART for the SJGS. We also performed 

our BART evaluation on the basis of 

increasingly stringent levels of control 

and assessed incremental costs and cost 

effectiveness. Thus, we do not believe 

we improperly truncated the NOX BART 

assessment for the SJGS. 

We received a New Mexico RH SIP on 

July 5, 2011. This SIP does contain a 

revised BART analysis that concludes 

that NOX BART for the SJGS should be 

SNCR and an emission rate of 0.23 lb/ 

MMBtu on a 30-day rolling average. We 

will review the State RH SIP submittal, 

and if there is significant new 

information that changes our analysis, 

we will make appropriate revisions to 

today’s decision. However, the State RH 

SIP recommends SNCR as BART, and 

we have considered that technology in 

the context of responding to other 

comments in this notice. For the reasons 

discussed in our proposal (76 FR 491), 

and in other responses to comments, we 

have concluded that BART for the SJGS 

is an emission limit of 0.05 lbs/MMBtu, 

based on a 30 BOD average, more 

stringent than the levels achievable by 

the SNCR technology recommended by 

the State. 

Comment: To meet a three-year 

deadline, PNM would have to 

prefabricate as much of the SCRs as 

possible. In addition, a three-year 

deadline would also require significant 

overtime hours, expedited material 

costs, double ‘‘heavy long-lift’’ crane 

costs, and a larger construction 

workforce overall. Because these costs 

would never be incurred in the normal 

course of installing SCRs, PNM did not 

include these costs in its analysis, but 

they would be unavoidable in the event 

a three-year deadline is required. Such 

a short construction deadline would 

also exacerbate the shortage of skilled 

labor caused by the significant number 

of similar projects that are either 

ongoing or planned for the near future 

in the region. The failure to account for 

the additional labor costs associated 

with such a short timeframe, 

particularly given other factors affecting 

the market for skilled labor, renders 

both the three-year deadline and the 

cost estimate prepared by EPA 

unrealistic. 

Response: The information in the 

record does not demonstrate a shortage 

of labor necessary to complete the 

installation of SCRs at the SJGS. 

However, as stated elsewhere in our 

response to comments, we have 

modified the schedule for compliance 

with the emission limits to now require 

compliance within 5 years—rather than 

3 years—from the effective date of our 

final rule. We believe this compliance 

schedule will provide adequate time to 

schedule the necessary labor resources 

for the installation of controls at the 

SJGS. 

Comment: The NPS recommends that 

in addition to the $/ton metric, we 

evaluate the visibility metric $/deciview 

as an additional tool to report the 

benefits of emissions controls. The NPS 

contends that BART is not necessarily 

the most cost-effective solution. Instead, 

it represents a broad consideration of 

technical, economic, energy, and 

environmental (including visibility 

improvement) factors. The NPS notes 

that one of the options suggested by the 

BART Guidelines to evaluate costeffectiveness is $/deciview. The NPS 

believes that visibility improvement 

must be a critical factor in any program 

designed to improve visibility. The NPS 

goes on to provide several examples of 

$/deciview calculations. 

Two other comments recommend we 

employ the $/deciview metric. One 

commenter states EPA has not 

appropriately considered the costs of 

compliance for any proposed BART for 

the SJGS because it relies on a $/ton 

metric. The commenter maintains that 

cost should be related to the amount of 

visibility improvement that it is 

projected to achieve and proposes the 

$/dv as the means for making a rational 

comparison of the relative costeffectiveness of control measures. 

This commenter also states that a 

method that aggregates projected 

visibility improvement in each affected 

class I area is not appropriate for several 

reasons. That approach masks the fact 

that it is cumulative over time and space 

and does not represent actual change at 

any one class I area. That approach also 

ensures an artificially low measure of 

cost-effectiveness simply by allowing 

the control cost to be divided by a larger 

value. The commenter suggests that a 

$/dv metric expressed as a range of the 

values for each affected class I area 

would be an appropriate means for 

comparing cost-effectiveness of different 

controls. The commenter states that 

EPA’s current measure of costeffectiveness in terms of $/ton is 

virtually meaningless in the context of 

the RH program. Thus, EPA’s 

assessment of the $/ton costs of BART 

candidates for the SJGS is flawed 

because the premise for its use is faulty, 

i.e., a change in emissions is not a 

suitable surrogate to represent a change 

in visibility. 

Another commenter believes that a 

dollar per deciview of visibility 

improvement metric would be more in 

line with the overall goal of the RH 

program, namely to improve visibility in 

national parks and wilderness areas. To 

properly gauge cost-effectiveness, EPA 

must consider the fact that installing 

SCRs at San Juan will cost between $78 

million and $336 million per deciview, 

depending on the Class I area. 

Response: The BART Guidelines 

require that cost effectiveness be 

calculated in terms of annualized 

dollars per ton of pollutant removed, or 


jlentini on DSK4TPTVN1PROD with RULES2
Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 52395 

21 70 FR 39167. 

22B&V 10/22/10 Cost Analysis, Sec. 3.0 and 

11/4/10 Norem E-mail to Kordzi, Re: Questions on 

PNM’s Revised Cost Estimate for the SJGS SCR 

Project, Response to Question 3, Table 3 of 

attachment 1. 

$/ton.21 The commenters are correct in 

that the BART Guidelines list the $/ 

deciview ratio as an additional cost 

effectiveness measure that can be 

employed along with $/ton for use in a 

BART evaluation. However, the use of 

this metric further implies that 

additional thresholds of acceptability, 

separate from the $/ton metric, be 

developed for BART determinations for 

both single and multiple Class I 

analyses. We have not used this metric 

because (1) We believe it is unnecessary 

in judging the cost effectiveness of 

BART, (2) it complicates the BART 

analysis, and (3) it is difficult to judge. 

We conclude it is sufficient to analyze 

the cost effectiveness of potential BART 

controls using $/ton, in conjunction 

with the modeled visibility benefit of 

the BART control. We have addressed 

the commenter’s statement that we 

should not aggregate visibility 

improvement over Class I areas 

elsewhere in our response to comments. 

2. Comments on Specific Cost Line 

Items 

The comments that follow have been 

summarized to capture each one’s main 

points and most of the references have 

been removed. The reader is encouraged 

to refer to our Complete Response to 

Comments for NM Regional Haze/ 

Visibility Transport FIP for more details 

and references. 

Comment: The NPS stated that PNM 

has improperly rejected use of the Cost 

Manual in favor of methods not allowed 

by EPA. The NPS states the SCR cost 

estimates submitted by PNM are 

severely lacking in the types of specific 

information needed to give them 

credibility. The NPS goes on to provide 

a great deal of detailed information that 

supports their opinion that specific cost 

items were overestimated. This 

information includes the following cost 

item categories: 

• Appropriateness of using the Cost 

Manual. 

• Problems in B&V’s scaling of cost 

items from another project. 

• Ductwork and ammonia grid costs. 

• Reactor box and breaching. 

• Expansion joints. 

• Sonic horns. 

• Elevator. 

• Structural steel. 

• SCR bypass. 

• Catalyst. 

• NOX monitoring. 

• Auxiliary electrical system 

upgrades. 

• Instrumentation and control 

systems. 

• Air preheaters. 

• Balanced draft conversion. 

• Contingencies. 

• Operating Labor. 

• Reagent. 

• Auxiliary power demand. 

• Catalyst life. 

• Interest rate. 

• Effect on cost of PNM’s assumption 

of an emission rate of 0.07 lbs/MMBtu. 

The NPS concluded their critique of 

PNM’s cost estimate with their own 

estimate of an average cost of $2,600/ton 

for the four units of the SJGS. 

Response: We agree with the general 

contention that many individual cost 

items for the installation of SCR on the 

units of the SJGS were overestimated by 

PNM. Please see elsewhere in our 

response to comments for our opinion 

regarding the appropriate estimated 

costs for these and other cost items. We 

note that the NPS estimate of an average 

cost of $2,600/ton for the four units of 

the SJGS closely agrees with our own 

revised estimate. 

Comment: EPA failed to account for 

the costs associated with ensuring 

sufficient auxiliary power to operate 

SCRs at SJGS. EPA discounted by nearly 

80 percent the estimated cost of the 

auxiliary power upgrades needed to 

power the SCRs. The theory behind this 

sharply discounted cost estimate is that 

the SCRs will only be responsible for 

approximately 20 percent of the total 

draft pressure of the units and that 

therefore the cost of the auxiliary power 

upgrades should be allocated in similar 

fashion. Without SCRs, no additional 

auxiliary power would be needed. As 

such, those costs must be included in 

the cost of the SCRs, as they represent 

one of the site-specific concerns that 

could make the installation of SCR at 

SJGS more difficult than other units. 

The decision by EPA to exclude these 

costs underestimates the cost of SCRs 

for SJGS by $73,175,000. 

Response: We disagree that installing 

SCRs would by itself trigger the need to 

upgrade the auxiliary power system, 

especially to the extent proposed by 

PNM. The upgrade benefits the entire 

auxiliary power system. The 

modifications, for example, include new 

transformers, switchgear, and motor 

control centers that will serve the entire 

fan auxiliary loads of both the Consent 

Decree projects and the SCR.22 The 

modifications also include replacing the 

existing fans with upgraded units. These 

fans will service more than just the 

SCRs. 

This comment advocates attributing 

100% of the cost of the auxiliary power 

system upgrade, recognized after the 

fact, to the last project to be 

implemented, the SCR. We did not 

‘‘discount’’ the cost of the auxiliary 

power system by 80%, but rather 

distributed it among the control projects 

planned around the same time that 

triggered its need according to each 

control’s contribution to draft pressure 

lost. This recognizes that the upgrade 

provides benefits to the entire system 

and includes elements that are more 

than strictly necessary because of the 

installation of the SCR. Therefore, it is 

not appropriate to attribute the entire 

cost of the upgrade to the SCR project. 

We believe our approach is consistent 

with standard engineering practices. 

Comment: EPA failed to account for 

additional costs associated with 

protecting the air preheater following an 

SCR Installation. Ammonia reacts with 

sulfur in the flue gas downstream of the 

SCR forming ammonium bisulfate 

(ABS), which condenses in the air 

preheater. ABS is an acidic substance 

that forms a sticky deposit on heat 

transfer surfaces, resulting in both 

corrosion of the equipment and the 

collection of fly ash that plug passages, 

which ultimately impairs the efficiency 

and reliability of the unit. As such, the 

installation of a retrofit SCR generally 

requires a modification to the air 

preheater to allow for easier cleaning of 

the basket surfaces in order to protect 

the heat transfer elements against the 

potential damage that might otherwise 

result from ABS. EPA deleted the costs 

of protecting the air preheater in its SCR 

cost analysis, ‘‘pending compelling 

justification that they are required for 

the SCR.’’ EPA’s cost analysis 

recognizes that modifications to the air 

preheater are generally required for 

‘‘units that burn high sulfur coal,’’ but 

EPA assumes that such modifications 

are not necessary ‘‘for a properly 

designed SCR on a boiler that burns low 

sulfur coal.’’ EPA is correct that, in spite 

of the quoted discussion above, Sargent 

& Lundy did not recommend air 

preheater modifications in the SCR cost 

analysis for the Navajo Generating 

Station. However, that recommendation 

was based on the specific emission 

characteristics at Navajo Generating 

Station, which differ significantly from 

those at SJGS. 

Response: This comment attempts to 

distinguish the emission characteristics 

of Navajo Generating Station and the 

SJGS by pointing to differences in the 

coal quality to support air preheater 

modifications at SJGS but not at Navajo. 

We obtained and analyzed the Navajo 

design basis coal quality. The 


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52396 Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 

differences in coal quality are either not 

material (sulfur, heat content) or 

mitigate the potential impacts of 

ammonium bisulfate plugging (higher 

ash at SJGS). The key factors that 

determine whether ammonium bisulfate 

plugging will occur are not coal quality, 

but rather the amount of sulfur trioxide 

(SO3) and ammonia in the exhaust gases 

that reach the air preheater and the air 

preheater temperature regime. The 

formation of ammonium bisulfate 

depends on the relative amounts of 

ammonia and SO3 in the exhaust gases. 

When the molar ratio is more than 2:1, 

ammonium sulfate (not ammonium 

bisulfate) is preferentially formed. The 

average molar ratio for both SJGS and 

Navajo over the catalyst lifetime is 

much higher than 2:1. Thus, ammonium 

sulfate would be preferentially formed. 

Ammonium sulfate is a dry powder at 

all air preheater operating temperatures 

and does not create a fouling problem. 

Thus, consistent with Sargent & Lundy’s 

conclusion for the nearby Navajo 

Station, which burns a similar coal, 

ammonium bisulfate fouling would not 

be expected and we do not believe that 

upgrades are justified for the air 

preheaters due to SCR installation. 

Comment: The installation of SCR at 

SJGS would increase the resistance in 

the flue gas path for the units. To 

overcome that additional resistance, 

PNM would need to install new higher 

capacity fan rotors and motors because 

the SCRs will add an additional 

pressure drop in the system of 10 inches 

of water gauge (w.g.). This change in 

pressure and higher fan pressure ratings 

would increase the potential risk of a 

boiler implosion during transient (upset 

or malfunction) conditions. The analysis 

prepared by B&V of the expected cost of 

an SCR retrofit includes the costs to 

mitigate the implosion risk by 

converting to balanced draft and 

stiffening the boiler and associated flue 

gas path. EPA concludes that additional 

boiler stiffening would not be required, 

stating simply that ‘‘a balance draft 

conversion with the proposed stiffening 

is not part of an SCR project.’’ 

Response: The basis for selecting 10 

in. w.g. for a 77% NOX removal SCR is 

not explained or documented in the 

record. The overall SCR system pressure 

drop consists of losses from the SCR 

catalyst, static mixers, and duct work. 

Determining the pressure drop due to 

the SCR requires a more advanced 

design than presented in the B&V BART 

analysis. Instead, B&V appears to have 

assumed that the pressure drop due to 

the SCR would be 10 in. w.g., which is 

at the upper end of the usual range of 

3 to 10 in. w.g. The B&V record, for 

example, contains no duct arrangement 

drawings; no catalyst vendor quotes; 

does not identify the type of catalyst, 

e.g., honeycomb or plate; does not 

specify the catalyst pitch; and is silent 

as to static mixers, all important factors 

in determining the pressure drop due to 

the SCR. Thus, we do not believe there 

is a basis for the 10 in. w.g. used to cost 

boiler stiffening and to justify balanced 

draft conversion. This pressure drop 

likely has not been optimized and could 

be significantly reduced by catalyst 

selection (e.g., by using honeycomb 

with large pitch) and ductwork design. 

Therefore, we do not concur that the 

record supports a pressure drop of 10 in 

w.g. for the SCR. 

Comment: Installation of SCR’s at 

SJGS will increase boiler and duct 

implosion potential due to increased 

draft system requirements and fan 

pressure ratings. SCRs will trigger the 

need to choose between either designing 

to the general standard of +/¥ 35 inches 

w.g. (which is typical for a newly 

designed power plant) or performing a 

‘‘more complete and rigorous analysis’’ 

to determine whether PNM will qualify 

for an exception from the generallyapplicable implosion protection 

standard through the use of alternative 

methods. To date, neither PNM nor its 

consultants have fully determined 

whether an alternative to the +/¥ 35 

inches w.g. standard would suffice 

following installation of an SCR, due to 

the significant amount of time and 

expense that would be associated with 

that analysis. Therefore, B&V included 

the cost of stiffening the boilers to +/¥ 

35 inches w.g. in its analysis. EPA’s 

failure to properly account for the boiler 

stiffening costs underestimates the cost 

of the SCR retrofits for SJGS by 

$55,718,000 in capital costs for boiler 

stiffening and properly sized fans and 

motors. 

Response: This comment 

acknowledges that the boiler stiffening 

costs represent a worst case estimate. 

The magnitude of these costs is unusual. 

The BART Guidelines require that 

unusual costs be documented in the 

record. These costs are stated without 

providing the underlying engineering 

calculations. PNM states that the boilers 

were stiffened to negative pressure 

differentials of 18 in. w.g. during the 

Consent Decree projects. The 10 in. w.g. 

estimate is a worst-case upper bound 

that is not supported by vendor quotes 

and SCR design. We agree some cost for 

code compliance is warranted. 

However, the worst case used in B&V’s 

analysis is unreasonable and 

unsupported, given the SCR’s potential 

upper bound contribution of 10 in. w.g. 

Absent the ‘‘more complete and rigorous 

analysis’’ to support upper bounds for 

both an SCR pressure differential and 

stiffening to +/¥ 35 in w.g., we feel 

stiffening costs should have been based 

on no more than the SCR’s contribution 

to the increase from current conditions 

of 18 in. w.g. to 35 in. w.g. Thus, we 

modified our cost analysis to estimate 

the stiffening cost based on the SCR’s 

maximum contribution to the increase 

from 18 in. w.g. to 35 in. w.g. or by 

59%. This increased our estimate of the 

capital cost to install SCRs by 

$19,258,318. 

Comment: EPA failed to account for 

the cost of installing the initial layers in 

the SCR. The cost analysis prepared by 

B&V included the cost of the initial 

layers of catalyst in the capital cost and 

including the replacement layers in the 

annual operating cost calculation. EPA, 

however, appears to have 

misunderstood the analysis and 

assumed that the initial catalyst layers 

were double-counted. As a result, it 

subtracted the initial catalyst cost from 

the capital cost calculation, without 

adding it to the annual cost calculation. 

As such, EPA’s failure to include the 

cost of the initial layers of catalyst in its 

analysis underestimates the cost of 

installing SCRs at SJGS by $33,556,000. 

Response: We agree with this 

comment. We have revised our cost 

analysis to include the initial catalyst 

charge. 

Comment: Sorbent injection will be 

needed if PNM must install SCRs at 

SJGS, and the EPA cost analysis should 

reflect those costs. Sorbent injection 

systems are often used at 

coal-fired power plants equipped with 

SCRs to help reduce emissions of 

sulfuric acid mist that are an 

unavoidable byproduct of the chemical 

reactions that occur in an SCR. Sulfuric 

acid mist resulting from SCR operation 

has been known to cause a visible 

plume at some units in the industry. 

Although the installation of SCRs may 

not result in such a plume at SJGS, the 

sorbent injection system would be 

needed to ensure a visible plume does 

not materialize. The failure to address 

the sulfuric acid mist created by the 

SCR can reduce any visibility benefits 

associated with an SCR. 

Response: We disagree with this 

comment. B&V updated its cost analysis 

in October 2010. This is the most recent 

version of B&V’s cost analysis, which 

was critiqued in our Technical Support 

Document (TSD) in our proposal. This 

analysis did not include any costs for 

sorbent injection. In its June 21, 2010 

BART Determination, NMED concluded 

that BART for SJGS was SCR plus 

sorbent injection to remove SO3 and 

requested a sorbent injection cost 

analysis from PNM. However, we 


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disagreed and concluded that sorbent 

injection was not required due to the 

low sulfur content of the coal, 

availability of low conversion SCR 

catalyst, and our calculations. We see no 

reason to change that view. The reasons 

advanced in this comment for requiring 

sorbent injection to control sulfuric acid 

mist (SAM) are not applicable to the 

SJGS SCR. Visible plume issues have 

only been experienced at units that burn 

high sulfur coal, containing greater than 

2+% sulfur and typically over 3% 

sulfur, e.g., Gavin, Ghent. The coal 

burned at SJGS contains 0.77% sulfur, 

much lower than the amount of sulfur 

that has resulted in visible plume issues 

elsewhere and is considered to be low 

sulfur. No explanation is provided for 

why the commenter believes a plume 

may ‘‘materialize’’ on installing SCR. If 

the SCR is properly designed to address 

SJGS’s coal, a plume should not 

materialize. Low conversion catalysts 

capable of achieving an SO2 conversion 

as low as 0.1% per layer of catalyst in 

the high dust, hot (>650 F) position and 

0.5% across the entire SCR reactor are 

common in higher sulfur and other 

applications. Even lower levels can be 

achieved if the catalyst is regenerated. 

Comment: EPA’s calculation of 

sulfuric acid emissions is incorrect. EPA 

estimated sulfuric acid mist emission 

levels based on a document prepared by 

the Electric Power Research Institute 

(EPRI), which describes a formula used 

by many utilities to estimate sulfuric 

acid emissions. However, in applying 

that formula, EPA assumed an ammonia 

slip value of 2.0 parts per million (ppm), 

even though actual ammonia slip varies 

over the life of a catalyst layer from very 

low values up to 2.0 ppm as the catalyst 

ages. A more appropriate assumption for 

ammonia slip is the 0.75 ppm value 

recommended by the EPRI formula, 

which better represents the expected 

ammonia slip over the life of a catalyst. 

Using that assumption, the sulfuric acid 

emissions from SJGS are calculated to 

be twice that assumed by EPA. As a 

result, EPA’s attempt to justify its 

decision to delete the costs of sorbent 

injection based on minimal sulfuric acid 

mist emissions is incorrect. 

Response: The commenter is correct 

in that the EPRI report does suggest that 

a value of 0.75 ppm should be used. We 

note that the ammonia slip of an SCR is 

minimal when the catalyst is new and 

increases as the catalyst ages. In order 

to be conservative, we recalculated the 

sulfuric acid emission rate, based on 

zero ammonia slip, to be 2.6 X10¥4 lb/ 

MMBtu, compared to our original value 

of 1.06 X10¥4 lb/MMBtu at 2ppm 

ammonia slip. The 2.0 ppm we selected 

in our proposed visibility modeling was 

based on the maximum slip from PNM’s 

design specifications. This revised 

sulfuric acid emission rate remains 

significantly lower than that estimated 

by NMED and is a minimal level of 

sulfuric acid emissions. We continue to 

conclude that sorbent injection is not 

required due to the low sulfur content 

of the coal, availability of low 

conversion SCR catalysts, removal by 

existing control equipment and our 

revised calculations. 

Comment: The EPA also cites to the 

results of a stack test performed at the 

Navajo Generating Station in November 

2009 to conclude that actual sulfuric 

acid mist emissions are lower than 

would be estimated using the EPRI 

Method. However, the air quality 

control industry generally considers 

sulfuric acid testing to be very prone to 

inaccuracy because the test methods 

used are susceptible to bias. Also, 

sulfuric acid emissions vary 

significantly from unit to unit because 

emissions removal is dependent on 

many variables including temperature, 

moisture, process operation, air quality 

control equipment, ambient conditions, 

and the quality of the testing. As 

mentioned above, SJGS and the Navajo 

Generating Station differ significantly in 

many of these respects. Therefore, it is 

not appropriate to use test results from 

Navajo Generating Station to make 

assumptions about SJGS. 

Response: We believe this comment 

mischaracterizes our analysis. We did 

not use test results from the Navajo 

Generating Station to make assumptions 

about the SJGS. Rather, we compared 

sulfuric acid mist emissions calculated 

for Navajo using the EPRI procedure 

with a stack test at Navajo in accordance 

with EPA Method 8A procedures. Thus, 

we compared Navajo EPRI estimates 

with Navajo test data to judge the 

accuracy of the EPRI procedure. This 

comparison suggests that the EPRI 

method may overestimate sulfuric acid 

mist emissions when firing a similar 

coal if PNM’s assumptions are used. 

This analysis supports the conclusion 

that the EPRI method and parameters 

we used provide a better estimation of 

sulfuric acid emissions than the 

methodology and parameters utilized by 

PNM and NMED in their analysis, 

which overestimates these emissions. 

We also note that PNM estimates for 

sulfuric acid emissions that were 

reported to the Toxic Release Inventory 

in recent years are much lower than 

those estimated by PNM for their BART 

analysis. 

Comment: It is appropriate to include 

sorbent injection costs in the SCR cost 

analysis because sorbent injection may 

be required by law. The Prevention of 

Significant Deterioration (PSD) program 

under the CAA requires major sources 

to install additional controls to address 

any significant net emissions increases 

resulting from a physical change to an 

emissions unit. Because the SCR will 

constitute a physical change to the SJGS 

emission units, and could have the 

potential to result in a significant net 

emissions increase in sulfuric acid mist, 

additional controls could be required by 

the PSD program. If triggered, the PSD 

program would require the installation 

of ‘‘best available control technology,’’ 

which for sulfuric acid mist emission 

increases would likely include a sorbent 

injection system. Although there 

remains some uncertainty as to whether 

the SCR would trigger PSD permitting 

requirements, PNM believes it is 

appropriate to include the cost of the 

system in the SCR cost analysis, and the 

failure to include those costs 

underestimates the cost of the SCRs by 

$12,118,000. 

Response: For the reasons outlined 

elsewhere in our response to comments, 

we believe the level of sulfuric acid 

generated at the SJGS will be so low that 

sorbent injection will not be needed. 

However, it is possible that the 

installation of SCR on all four units of 

the SJGS could generate enough 

additional sulfuric acid that a PSD 

review could be triggered. EPA is not 

the permitting authority for sources in 

New Mexico but we believe it is 

reasonable to anticipate that a 

subsequent BACT analysis for sulfuric 

acid emissions at the SJGS will 

determine that no additional controls 

are required because despite the 

projected increase in sulfuric acid 

emissions, emissions are expected to 

remain low. In considering SCR for 

controlling NOx, EPA specifically 

considered the issues of sulfuric acid 

formation. In our review, we believe 

that the emission limits for NOx can be 

achieved through the use of lower 

reactivity catalyst, thus mitigating the 

formation of sulfuric acid across the 

catalyst bed. We have set an emission 

limit for emissions of sulfuric acid that 

restricts the increase of sulfuric acid. 

According to the two most recent Toxic 

Release Inventory (TRI) reports 

submitted by SJGS, the total sulfuric 

acid emissions are very low (17.77 TPY 

for 2009, and 27.5 TPY for 2008). Based 

on our calculations, we believe the 

current emissions of sulfuric acid to be 

significantly lower than these reported 

values due to the low sulfur content of 

the coal and the removal of sulfuric acid 

in the installed control equipment, 

including wet scrubbers and fabric 

filters. We project, with the 


jlentini on DSK4TPTVN1PROD with RULES2
52398 Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 

23Based on our emission limit of 2.6×10¥4 lb/ 

MMBtu and conservatively assuming each unit 

operates 100% of the year (8760 hr/yr). 

24See San Juan Generating Station Site Visit, 

5/23/11. 

25S.M. Cho and S.Z. Dubow, Design of a Selective 

Catalytic Reduction System for NOX Abatement in 

a Coal-Fired Cogeneration Plant, Proceedings of the 

American Power Conference, April 13–15, 1992, pp. 

717–722. 

26 10/22/10 B&V Cost Analysis Update, Appendix 

B; 6/7/07 B&V San Juan BART Analysis, p. B–3. 

implementation of SCR using a low 

reactivity catalyst that total emissions of 

sulfuric acid will remain below 22 

tons/year.23 In this particular case, 

sorbent injection technology is unlikely 

to be cost-effective on a cost per ton 

basis of sulfuric acid mist removed. 

Again, we note that the New Mexico 

Environmental Department is the 

permitting authority and has the 

primary responsibility to implement the 

New Source Review program which 

includes the PSD permitting process, 

and the issuance of the applicable 

permit. NMED will be responsible for 

determining if PSD will be triggered for 

increases in sulfuric acid emissions or 

other NAAQS pollutants and in 

determining the BACT for such 

increases. 

Comment: EPA failed to account for 

the additional steel that will be needed 

due to site congestion at the SJGS. EPA 

assumed that the ‘‘complexity factor’’ 

applied to the structural steel cost in 

PNM’s cost analysis was a ‘‘contingency 

factor.’’ As such, EPA assumed that 

PNM had double-counted contingency 

costs by using both the ‘‘complexity 

factor’’ for structural steel and a more 

general ‘‘contingency factor’’ overall. 

PNM asks EPA to reconsider the 

analysis provided by B&V, given that 

the engineers at B&V made several site 

visits to SJGS and designed the SCRs for 

the St. John’s River Power Park (SJRPP). 

The pictures of SJRPP and SJGS 

provided by B&V illustrate the 

differences in site congestion. EPA 

underestimated the cost of its BART 

proposal by $35,087,000 by failing to 

accurately account for site congestion. 

Response: A complexity factor is a 

subset of a contingency factor as it 

estimates unknown costs. PNM applied 

a complexity factor of 1.2 for Units 1 

and 4 and 1.5 for Units 3 and 4. We 

regard these factors as rough estimates 

that cannot be fully determined until 

the SCR is designed. We visited the 

SJGS plant on May 19, 2011.24 This visit 

confirmed that the site is congested. 

However, this does not confirm that the 

cost of structural steel for Units 1 and 

4 would be 1.2 times higher than at 

SJRPP, and 1.5 times higher for Units 2 

and 3, as this comment contends. The 

materials provided by PNM do not 

contain any plot plans or design 

drawing for SJRPP (or SJGS) that would 

allow one to conclude anything about 

the cost of structural steel at one facility 

compared to the other. Photographs 

attached to the PNM comments indicate 

more room for crane access at SJRPP 

than at SJGS, but this does not address 

the capital cost of the structural steel 

framework, only the cost of constructing 

it. 

The BART Guidelines require that 

‘‘documentation’’ be provided for ‘‘any 

unusual circumstances that exist for the 

source that would lead to costeffectiveness estimates that would 

exceed that for recent retrofits.’’ We 

specifically asked PNM to identify any 

retrofit constraints and support them 

with engineering calculations, drawings, 

and photographs. PNM has not provided 

specific documentation that supports 

the use of their chosen structural steel 

complexity factors. Nevertheless, based 

on the information that was provided, 

we have modified our cost analysis to 

use B&V’s estimate for structural steel, 

which includes the ‘‘complexity 

factors’’ cited in this comment, as B&V 

produced designs for both facilities. 

Comment: EPA failed to account for 

the SCR bypass that will be necessary to 

protect the SCR during startup on oil. 

EPA assumed that SJGS could initiate 

startup of its units on oil without 

fouling the catalyst in the SCR. EPA’s 

justification for the removal of this cost 

line item was that fuel oil is efficiently 

burned in modern low NOx burners 

with oil igniters, citing two coal-fired 

units that have shown the ability to 

startup on oil without a bypass and two 

oil-fired boilers with SCRs that do not 

have a bypass. Based on these 

references, EPA concluded that SJGS 

will be able to startup on oil without 

risking catalyst fouling resulting from a 

coating of incompletely combusted fuel 

oil. The failure to account for the 

needed SCR bypass system 

underestimates the cost of installing 

SCR at SJGS by $126,484,000. 

Response: We disagree with this 

comment. The removal of SCR bypass 

costs was based on several factors. First, 

a noted air pollution handbook 

concluded (before U.S. ozone season 

trading programs made them routine): 

‘‘most applications do not have SCR 

bypasses, since routines are used during 

startup and shutdown which preclude 

their need’’ (Cho and Dubow),25 and 

regulations sometimes prohibit their 

use. Also, experience in Japan and 

Germany has shown them to be costly 

and not required to prevent damage due 

to low-load oil firing, thermal gradients, 

and other conditions. We believe a 

bypass is not required in a properly 

designed and operated SCR system to 

prevent SCR catalyst fouling during 

startup or operation on oil. Two 

examples were cited in our TSD as part 

of our proposal to confirm this 

information. In addition, Sargent & 

Lundy, the consultant that prepared the 

design and cost estimate for SCR for the 

3 units at Navajo Generating Station, an 

existing facility of similar age and 

retrofit complexity that starts up on oil, 

did not recommend an SCR bypass in its 

BART analysis. 

Comment: The EPA cost estimate also 

does not properly estimate annual 

operating costs for auxiliary power 

consumption and catalyst replacement 

rate. B&V estimated the amount of 

auxiliary power needed to run the SCR 

to be 16,297 kW (for all four units) at a 

cost of $0.06095 per kWh, based on a 

site-specific analysis. Specifically, 

B&V’s calculation was based on the 

calculation of the additional fan energy 

(based on flue gas flow rate and 

estimated pressure drop from the SCR) 

and the power consumption for the 

auxiliary equipment (such as the 

ammonia system). EPA, on the other 

hand, simply assumed a cost of 5,400 

kW at $0.05 per kWh based on a 

percentage estimate for ‘‘typical’’ SCR 

installations. This error underestimates 

the cost of auxiliary power consumption 

when operating SCRs by $5,388,000. 

Response: EPA disagrees with the 

comment. First, the claimed ‘‘sitespecific analysis’’ was not submitted for 

inclusion in the record, and thus EPA 

and the public could not review it. 

Second, the values that would affect the 

cost analysis, e.g., duct length, catalyst 

pressure drop, would be estimates as the 

SCR system has not yet been designed. 

In fact, the record does not even contain 

an arrangement diagram, required to 

determine duct lengths. Third, the B&V 

estimate of the amount of auxiliary 

power needed to run the SCR (16,297 

kW) was initially rejected by us as it 

amounts to 0.9% of the total gross 

generating capacity of the station, which 

is high compared to other estimates 

known to us. An SCR typically uses 

about 0.3% of a plant’s electric output, 

which would be about 5,400 kW or 

three times less than assumed in the 

B&V cost analysis. The BART 

Guidelines require that unusual costs be 

documented in the record. PNM did not 

supply any additional information to 

support its unusually high estimate. 

Fourth, as discussed elsewhere in our 

response to comments, no support has 

been provided for PNM’s claim of a 10 

in. w.g.26 pressure drop due to the SCR, 


jlentini on DSK4TPTVN1PROD with RULES2
Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 52399 

27E-mail from Norem to Kordzi, October 21, 

2010, Re: PNM Responses to Follow-Up Questions 

from October 14, 2010 Conference Call Regarding 

BART Cost Estimate, October 21, 2010 (10/21/10 

Responses), Response to Question 9, pp. 3–4. 

28Sargent & Lundy, Sooner Units 1 & 2, Muskogee 

Units 4 & 5 Dry Flue Gas Desulfurization (FGD) 

BART Analysis Follow-Up Report, Prepared for 

Oklahoma Gas & Electric, December 28, 2009, 

Attach. C, pdf 109; (Gerald Gentleman—$45.65/ 

MWh; White Bluff—$47/MWh; Boardman/ 

Northeastern/Naughton—$50/MWh; Nebraska 

City—$30/MWh). 

which is at the upper end of the usual 

range of 3 to 10 in. w. g. Fifth, the unit 

cost of electricity used by B&V, 

$0.06095/kWh, is much higher than the 

auxiliary power cost commonly used in 

cost effectiveness analyses, and thus 

was not justified. Auxiliary power is the 

power required to run the plant, or 

power not sold. Cost effectiveness 

analyses are based on the cost to the 

owner to generate electricity, or the 

busbar cost, not market retail rates. The 

B&V estimate is based on the average 

forecasted cost of replacement power for 

2007 to 2012.27 Thus, even if this is the 

correct site specific cost, it is the wrong 

metric for a cost effectiveness analysis. 

We further note that the use of forecast 

cost is inconsistent with the BART 

methodology, which is based on current 

dollars. We conservatively used the 

upper end of the range of costs assumed 

in BART cost effectiveness analyses 

($0.03/kWh to $0.05/kWh) 28 or $0.050/ 

kWh. After our analysis was complete, 

PNM responded to a question from us 

that its average cost of production is 

$0.047/kWh ($47.83/MWh). This rounds 

up to 0.05/kWh, the number we used. 

Thus, we have made no changes to our 

estimate of auxiliary power demand. 

Comment: In its analysis, EPA 

recognized that the Cost Manual does 

provide factors to estimate certain 

‘‘direct installation costs,’’ namely 

foundation/supports, handling/erection, 

electrical, piping, insulation, painting, 

demolition, and relocation. However, 

the Control Cost Manual fails to provide 

factors to estimate these costs for SCR, 

as recognized in EPA’s analysis. EPA 

indiscriminately took the median of the 

factors for other control technologies, 

which vary significantly from SCRs. As 

a result, EPA’s analysis slashes in half 

the direct installation costs estimated by 

B&V. For example, the direct costs 

assumed by EPA for Unit 1 are 

$8,799,917, but that amount would only 

cover 159,998 man-hours, or 21 weeks 

of construction. EPA’s own schedule, 

even though insufficient itself, assumes 

38 weeks of construction, nearly double 

of the amount that EPA’s analysis could 

afford. Thus, EPA’s estimate is 

insufficient for its own estimated 

construction timeline, much less the 64 

to 72 weeks of construction that PNM’s 

experienced consultants predict. 

Response: We disagree with this 

comment. The B&V direct installation 

costs were calculated by multiplying 

total purchased equipment costs by 

various unsupported percentages, a 

rough estimating practice referred to as 

‘‘factoring.’’ B&V did not submit into the 

record the basis for the various factors 

that they used. The percentages that 

B&V used are demonstrably high. We 

compared each of B&V’s direct costs 

with those from a major SCR designer’s 

(Babcock Power) database and from 

similar SCR projects nationwide. 

Foundation and supports, costed by 

B&V as 30% of purchased equipment 

cost, for example, based on its estimate 

of purchased equipment cost, are two to 

three times higher than upper bound 

costs reported by Babcock Power for 

similar sized units ($8/MW compared 

with the B&V estimate of $18/MW to 

$29/MW for SJGS). Based on these 

comparisons the B&V’s costs were 

excessive. No documentation has been 

provided to justify the higher B&V costs. 

The Cost Manual estimating 

procedure for direct installation costs is 

based on the same factoring approach 

used by B&V. We tabulated the factors 

for total direct installation costs for all 

controls reported in the Manual. These 

ranged from 30% to 85% of the 

purchased equipment cost. In 

comparison, B&V assumed direct 

installation costs were 103% to 113% of 

total purchased equipment cost. 

We calculated direct installation costs 

for SJGS using the median of this range 

or 62% of purchased equipment cost. 

This is consistent with the upper bound 

Babcock Power estimate for actual 

retrofit SCR installations and estimates 

made by others. The B&V estimate is 

also high compared to direct installation 

costs that it reported for the SJRPP SCR, 

which was otherwise used to 

extrapolate equipment costs to SJGS. 

The direct installation costs for the 

SJRPP SCR were 95% of the total 

purchased cost. We have revised our 

cost estimate to use this percentage to 

conform to the balance of the B&V cost 

estimate. 

The B&V estimate assumes a 150-man 

crew for the entire 21 weeks, a 50-hour 

workweek for the duration, and a wage 

of $55/hour. This represents peak 

staffing and labor rates, even though the 

number of workers would vary over 

time. Thus, our estimate of direct 

installation costs corresponds to a 

longer duration than claimed. 

Regardless, it is important to note that 

this duration corresponds to 

construction of a much smaller project 

(less SCR bypass, preheater 

modifications, etc.) than proposed by 

B&V. Further, for our proposal, we did 

not estimate construction duration, but 

rather the length of time from the 

effective date of the final rulemaking to 

startup of the SCR or 36 months. We 

note that we have revised our proposal 

to allow 60 months from the effective 

date of the rule allowing additional 

flexibility in deploying workers. Thus, 

the basis of this comment’s starting 

point, an EPA estimate of 38 weeks, is 

incorrect. In addition, the B&V estimate 

does not contain a schedule, which is 

required to estimate the staffing and 

duration of construction. 

Comment: EPA asserts that ‘‘[t]he 

contingencies included in the B&V cost 

estimates are double-counted and 

excessive,’’ based on the misimpression 

that there are three contingencies 

‘‘imbedded’’ in the analysis. However, 

two of the three allowances are for 

known costs, and therefore are not 

‘‘contingencies.’’ Specifically, the 

complexity factor for structural steel 

costs of 1.2 (for Units 1 and 2) and 1.5 

(for Units 3 and 4) are known, expected 

costs, and therefore do not constitute a 

contingency factor, as noted previously. 

Also, the $2 million estimated for 

underground obstructions and the 

$500,000 estimated for on-site buildings 

are also known, and therefore do not 

represent a duplicative contingency 

factor. Thus, EPA’s claim that PNM 

double-counted its contingency costs is 

incorrect and underestimates the cost of 

SCRs at SJGS by $61,978,000. 

Response: This comment explains 

that the ‘‘complexity factor,’’ site 

unknowns, and general building 

requirements are not contingencies, but 

rather known factors. Based on this 

explanation and the information we 

have about the SJGS, we concur that 

these complexity factors, and the 

engineering estimates for underground 

obstructions and on-site buildings, are 

reasonable and we have modified our 

cost estimates to reflect B&V’s estimates. 

Comment: EPA also claims that the 

Interest During Construction included 

in the B&V cost estimates are not 

allowed by the Cost Manual. Therefore, 

this cost was eliminated from the cost 

analysis underlying the proposed FIP. 

However, this cost item is a real project 

cost, which will be incurred by PNM to 

finance the project and must by 

recovered from the SJGS customers. The 

rejection of costs associated with 

Interest During Construction 

underestimates the cost of the project by 

$78,300,000. 

Response: The B&V cost analysis 

include a charge for interest during 

construction of 7.41% of direct plus 

indirect costs. This charge is generally 


jlentini on DSK4TPTVN1PROD with RULES2
52400 Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 

29EPA Air Pollution Control Cost Manual, pdf 

486, Table 2.5, E (Allowance for Funds During 

Construction) = 0. 30 70 FR 39104, 39169. 

31E-mail from Larry Sorrels (OAQPS) to Don 

Shepherd (Park Service) with cc to Anita Lee (EPA 

known as the Allowance for Funds Used 

During Construction (AFUDC) and is 

specifically disallowed under the Cost 

Manual methodology and specifically 

disallowed for SCRs.29 A cost 

effectiveness analysis is a regulatory 

analysis that is based on current annual 

dollars without any inflation. AFUDC is 

an accounting method. Assets under 

construction do not provide service to 

current customers and thus associated 

interest and allowed return on equity 

are not charged to current customers. 

Instead, AFUDC capitalizes these costs 

and adds them to the rate base so that 

they can be recovered from future 

customers when the assets are used. 

Thus, these charges represent future 

cash income to the utility. In other 

words, AFUDC is the accumulated cost 

of carrying capital and holding it 

waiting to spend, so money can be made 

in the future by selling electricity. 

Future income should not be charged 

against the cost of a SCR in a BART 

cost-effectiveness analysis. These costs 

are not part of the constant dollar 

approach found in the Cost Manual and 

should not be included in BART costeffectiveness analyses. 

3. Concerns Over Possible Electricity 

Rate Increases 

Comment: Both the CAA and EPA 

BART regulations require consideration 

of the remaining useful life of a source. 

Requiring the imposition of possibly $1 

billion or more of control technology 

capital costs at SJGS, a nearly 40-year 

old plant, presents a likely scenario 

where the remaining useful life of SJGS 

is less than the time period needed for 

amortizing the costs of the control 

technologies. As such, it could make 

production at SJGS during its remaining 

useful life uneconomical in comparison 

with other existing or future plants. If, 

in light of SJGS’ estimated remaining 

useful life, it is determined that an 

investment of such magnitude does not 

make economic sense, owners of SJGS 

must evaluate alternate long-term 

options for meeting obligations to 

provide a cost-effective, reliable supply 

of electricity to customers. As such, the 

significant cost of requiring such SCR at 

SJGS will substantially increase the cost 

of electricity produced by SJGS. Over 

two million electric customers in New 

Mexico and other western states stand 

to be directly and adversely affected by 

the EPA proposal. PNM estimates that 

the average residential customer will 

experience a 10 percent increase in rates 

due solely to EPA’s proposed SCR 

technology. As a result of the Proposed 

Rule, PNM has indicated that possible 

sources of replacement power may be 

needed to ensure it can fulfill its 

obligation to provide electricity to the 

citizens of New Mexico. 

Response: The commenter is correct 

that the remaining useful life of a 

facility may impact the BART 

determination. As we note in the BART 

Guidelines, 

The ‘‘remaining useful life’’ of a source, if 

it represents a relatively short time period, 

may affect the annualized costs of retrofit 

controls. For example, the methods for 

calculating annualized costs in EPA’s 

OAQPS Control Cost Manual require the use 

of a specified time period for amortization 

that varies based upon the type of control. If 

the remaining useful life will clearly exceed 

this time period, the remaining useful life has 

essentially no effect on control costs and on 

the BART determination process. Where the 

remaining useful life is less than the time 

period for amortizing costs, you should use 

this shorter time period in your cost 

calculations.30

The BART Guidelines further clarify, 

‘‘[w]here this affects the BART 

determination, this date should be 

assured by a federally- or Stateenforceable restriction preventing 

further operation.’’ 

As part of our review of PNM’s BART 

determination for the SJGS, we met with 

representatives of PNM and its 

contractor several times, and 

communicated numerous times through 

e-mail and phone. At no point did PNM 

indicate that it wished to constrain the 

amortization period for financing BART 

controls based on the remaining useful 

life of the facility through the use of a 

federally enforceable restriction. 

Comment: Several local and county 

governments and municipal power 

systems expressed concern that the 

proposed FIP would require a major 

capital expenditure that could well 

exceed $750 million, according to PNM. 

Such significant costs will drastically 

increase the cost of power produced by 

the SJGS and have the potential to 

increase electricity rates in the 

communities served by the SJGS. 

Another commenter stated our NOX

BART proposal for the SJGS would cost 

New Mexico or Albuquerque ratepayers 

$10.20 more a year, or 85 cents a month, 

which is the price of a candy bar, so 

cleaning up this decades old air 

pollution is affordable and now is the 

time to do it. 

Response: As discussed in our 

proposal, we disagree with PNM’s cost 

estimate for installing SCR on the four 

units of the SJGS. Although PNM 

estimated the total cost to be in excess 

of $1 Billion, we estimated that cost to 

be approximately $250 Million. As 

discussed elsewhere in this notice, 

taking into consideration various 

comments, we have refined our estimate 

to be $344,542,604. In light of the 

visibility benefits we predict will occur, 

we consider this to be cost effective. We 

take our duty to estimate the cost of 

controls very seriously, and make every 

attempt to make a thoughtful and well 

informed determination. However, we 

do not consider a potential increase in 

electricity rates to be the most 

appropriate type of analysis for 

considering the costs of compliance in 

a BART determination. Nevertheless, we 

note that our cost estimate, being about 

1⁄3 that of PNM’s will result in 

significantly less costs being passed on 

to rate payers. 

4. Comments That Opined on Our 

Reliance on the EPA Air Pollution 

Control Cost Manual 

Comment: The rejection of PNM’s 

escalation factors is unrealistic. By 

relying too heavily on the Cost Manual, 

EPA’s analysis not only omits the 

specific line items, it also omits or alters 

various estimating factors utilized by 

B&V in PNM’s analysis. EPA relied on 

the Chemical Engineering Plant Cost 

Index (CEPCI) to escalate costs from the 

Cost Manual. However, although that 

index may be a reasonable tool for a 

chemical plant, it does not properly 

account for escalation of costs at power 

plants. In contrast, B&V developed an 

appropriate escalation factor with the 

help of an outside consulting firm 

specializing in financial analysis and 

forecasting, which incorporates the 

complete B&V database of ‘‘as-built’’ 

costs, the Bureau of Labor Statistics 

indices, and the consulting firm’s 

database of costs and indices, all 

tailored specifically to the power 

generation industry. 

Response: The CECPI, which is 

published monthly by the magazine, 

Chemical Engineering, has been used for 

decades in regulatory cost effectiveness 

analyses and is one of the factors that 

allows a comparison to be made 

between cost effectiveness analyses at 

different facilities. This method was 

selected by EPA’s Office of Air Quality 

Planning and Standards for use in 

regulatory cost effectiveness analyses 

because ‘‘this index specifically covers 

cost items that are pertinent to pollution 

control equipment (materials, 

construction labor, structural support, 

engineering & supervision, etc.).’’ 31 The 


jlentini on DSK4TPTVN1PROD with RULES2
Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 52401 

Region 9), dated 7/21/10, concerning the SRP 

Navajo Generating Station SCR cost estimate. 

32 70 FR 39104, 39166. 

33 Id. at 39168. 

34See San Juan Generating Station Site Visit, 5/ 

23/11. 

35Revised BART Cost Effectiveness Analysis for 

Selective Catalytic Reduction at the Public Service 

Company of New Mexico San Juan Generating 

Station, November 2010, pp. 28–29. 

36Bob Ellis, Standing on the Shoulder of Giants, 

Modern Power Systems, July 2002. 

37McIlvaine, NOX Market Update, August 2004. 

SCR was retrofit on Gibson Units 2–4 in 2002 and 

2003 at $179/kW. Assuming 2002 dollars, this 

escalates to ($179/kW)(550.7/395.6) = $249/kW. 

http://www.mcilvainecompany.com/ 

sampleupdates/NoxMarketUpdateSample.htm. 

38Bill Hoskins, Uniqueness of SCR Retrofits 

Translates into Broad Cost Variation, PowerGen 

Worldwide, May 2003. Available at: http:// 

www.power-eng.com/articles/print/volume-107/ 

issue-5/features/uniqueness-of-scr-retrofitstranslates-into-broad-cost-variations.html. 

39Escalated from $145/kW: ($145/kw) (560.3/ 

401.7)–$202/kW. Chemical Engineering, April 2011. 

B&V escalation index, on the other 

hand, is proprietary and not subject to 

public review. 

Comment: A commenter contends 

that EPA improperly rejected PNM’s 

cost estimates, because EPA thought 

them inconsistent with the Cost Manual. 

The commenter states EPA should 

consider site-specific costs, even when 

those costs are not included in the 

Manual. The commenter further states 

that EPA did not take ‘‘unusual 

circumstances’’ into proper account and 

expresses the view that EPA did not 

consider site-specific elements that 

would eliminate available control 

technologies from consideration. 

Response: We disagree with 

commenter’s view that our cost analysis 

is improper, but we agree that the Cost 

Manual is not the only source of 

information for the BART analysis. For 

instance, the reference to the Cost 

Manual in the BART Guidelines clearly 

recognizes the potential limitations of 

the Manual and the need to consider 

additional information sources: 

The basis for equipment cost estimates also 

should be documented, either with data 

supplied by an equipment vendor (i.e., 

budget estimates or bids) or by a referenced 

source (such as the OAQPS Control Cost 

Manual, Fifth Edition, February 1996, EPA 

453/B–96–001). In order to maintain and 

improve consistency, cost estimates should 

be based on the OAQPS Control Cost Manual, 

where possible. The Control Cost Manual 

addresses most control technologies in 

sufficient detail for a BART analysis. The 

cost analysis should also take into account 

any site-specific design or other conditions 

identified above that affect the cost of a 

particular BART technology option.32

The Cost Manual establishes a 

methodology for calculating cost 

effectiveness that allows comparison 

across multiple units. The regulatory 

cost is expressed in current real or 

constant dollars, less inflation. B&V did 

not follow the regulatory cost method. 

Instead, it used CUECost, a model that 

estimates control costs using the 

levelized cost method developed by the 

EPRI, which is not approved for BART 

determinations; extrapolation from 

several other projects; and its own 

proprietary and confidential databases 

not available for public review. 

As to unusual circumstances, the 

BART Guidelines call for 

‘‘documentation’’ to be provided for 

‘‘any unusual circumstances that exist 

for the source that would lead to costeffectiveness estimates that would 

exceed that for recent retrofits.’’ 33 PNM 

did not provide any documentation of 

unusual circumstances related to the 

BART determinations in any of its cost 

analysis. 

We subsequently toured the SJGS 

plant site on May 19, 2011.34 The SJGS 

site is congested, but not more so than 

other space-constrained sites where SCR 

has been retrofit for much less cost than 

estimated for SJGS.35 Gibson, a 

complex, space-constrained retrofit in 

which the SCR was built 230 feet above 

the power station using the largest crane 

in the world 36 only cost $249/kW in 

2010 dollars.37 Similarly, the Belews 

Creek SCR, one of the largest and most 

complex SCR retrofit projects in the 

U.S., involved installing the SCR 280 

feet above ground level above the boiler 

building. This retrofit only cost $202/ 

kW in 2010 dollars,38 39 compared to 

cost estimates of $423/kW to $567/kW 

for SJGS. B&V’s estimates of capital cost 

to retrofit SCR at SJGS ($446/kW–$599/ 

kW) are higher than actual installed cost 

for Gibson and many other existing 

retrofit SCRs, including those with 

extreme retrofit difficulty. The record 

including the information we have 

about the site does not document any 

unusual circumstances that would 

justify the unusually high costs claimed 

by B&V for SJGS. Thus, we do not 

believe that unusual circumstances are 

warranted. 

Comment: The exclusive use of the 

Cost Manual underestimates the 

expected costs for SCRs at SJGS for 

several reasons. First, the Manual was 

last updated in 2002 and Section 4.2, 

Chapter 2, Selective Catalytic 

Reduction, was actually written in 

October 2000. In addition, on page 2–40 

of the SCR section, the Manual indicates 

that the costs presented are based on 

1998 dollars. Therefore, the Manual 

does not reflect more recent experience 

with SCR installations, the cost of 

which has skyrocketed. Second, the 

2002 version of the Manual was the very 

first version to specifically address NOX

controls at all. According to the 

introduction to the Manual, EPA was at 

that time ‘‘entering new and uncharted 

territory for part of the Manual’’ because 

‘‘previous editions did not discuss NOX

or SO2 controls, and [the 2002] edition 

starts the process of correcting that 

oversight.’’ Finally, EPA also admits in 

the Manual that it had difficulty 

obtaining information on control costs 

because most of the information is 

proprietary—the very type of 

information to which B&V has ready 

access. 

Response: As discussed elsewhere in 

our response to comments, the Cost 

Manual contains two types of 

information, general cost analysis 

methodology and control-specific 

costing information. This comment 

addresses the latter. The information on 

SCR in Chapter 2 of the Cost Manual 

contains general information on SCR, 

design procedures, and some cost 

information. We agree that the cost 

information does not reflect current 

market costs. Thus, cost data should be 

escalated to current dollars using the 

CECPI before it is used or replaced with 

site-specific vendor quotes. We did not 

use any SCR costs data from this chapter 

in our analysis. 

Comment: The EPA cost estimate only 

differs from the Cost Manual where 

doing so would serve to reduce the 

amount of the cost estimate. For 

example, EPA applied an SCR life span 

of 30 years instead of the 20 year life 

span provided in the Cost Manual. The 

justification for choosing a different life 

span than provided for in the Manual is 

that other facilities have requested 30 

year life spans in requests for proposal 

and some unidentified SCRs in Europe 

have lasted that long. If such general, 

anecdotal information were sufficient to 

convince EPA to stray from the Cost 

Manual, the EPA analysis should be 

replete with variations from the 

outdated Cost Manual. The use of a 30- 

year lifespan underestimates the cost 

estimate of SCR by $15,268,000. 

Response: We disagree with this 

comment and we used the Cost Manual 

appropriately, as directed by the RHR. 

We used it for cost factors that for 

reasons expressed elsewhere in our 

response to comments, we feel were 

miscalculated by B&V, but were not 

otherwise available in the public 

domain. We did not use any actual cost 

data from the Cost Manual. In the case 

of SCR lifetime, the Cost Manual does 

not recommend a lifetime for an SCR, 

but rather sets out a calculation example 

that uses a lifetime of 20 years. In fact, 

this same calculation makes many other 


jlentini on DSK4TPTVN1PROD with RULES2
52402 Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 

40 Gretchen K. Hoffman and Glen E. Jones, Coal 

Availability Study—Fruitland Formation in the 

Fruitland and Navajo Fields, Northwest New 

Mexico, USGS Open-File 464, January 24, 2002, 

Available at: http://geoinfo.nmt.edu/publications/ 

openfile/downloads/ofr400-499/451-475/464/ 

ofr_464.pdf. 

41E-mail from O’Brien to Van Helvoirt, 

September 28, 2004, Re: Cost Impact, WPS–011904 

at WPS–011905. 

42 8/17/10 Salt River Project Navajo Generating 

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

Estimate Report (S&L Navajo Cost Analysis), 

Appendix A, p. 6, Sec. 1.7. 43 70 FR 49104, 39172. 44 Id. 

assumptions that we felt were not 

applicable to SJGS and if used anyway, 

would have resulted in lower cost 

estimates, but which were not used in 

our analysis. 

The lifetime of an SCR, which is a 

metal frame packed with catalyst 

modules, is equal to the lifetime of the 

boiler, which might easily be over 60 

years. The lifetime of a retrofit SCR is 

generally set equal to the remaining 

useful life of the facility. The record is 

silent on the remaining useful life of the 

SJGS units. Further, USGS studies of the 

coal reserves upon which the SJGS 

relies indicate that the local coal supply 

is adequate to support a remaining 

useful life of 30 years.40 Many utilities 

routinely specify 30+ year lifetimes in 

requests for proposal and to evaluate 

proposals. In fact, an analysis prepared 

by B&V for another facility assumed a 

40 year SCR lifetime.41 And finally, 

Sargent & Lundy assumed a design life 

of 30 years 42 for the nearby Navajo 

Generating Station which burns a 

similar coal. We conclude there is 

nothing in the record to support a 20 

year lifetime for the SCR and believe a 

30 year lifetime is justified. 

Comment: EPA also justifies its 

refusal to consider additional line items 

outside the scope of the Cost Manual on 

the grounds that ‘‘PNM had provided no 

documentation regarding unique 

circumstances related to the BART 

determinations.’’ That claim is 

incorrect. EPA’s own analysis cites the 

documentation PNM submitted to 

demonstrate the unique circumstances 

at SJGS, referred to by EPA as B&V’s 

‘‘Cost Analysis Manual Commentary.’’ 

That document was a response to the 

cost analysis that was initially prepared 

by NMED in March 2008 as a response 

to follow-up questions from NMED 

regarding the BART determination for 

SJGS. In addition, PNM also provided 

significant evidence of the site-specific 

challenges directly to EPA in response 

to its questions over the several months 

during which EPA prepared its BART 

determination for SJGS. Thus, the 

assertion by EPA that PNM has failed to 

sufficiently document the site-specific 

challenges at SJGS is incorrect. 

Response: The specific items in 

dispute are discussed elsewhere in our 

response to comments. The information 

provided in the ‘‘Cost Analysis Manual 

Commentary’’ and additionally 

provided to NMED and us explains how 

B&V extrapolated costs that it estimated 

from other facilities to apply to SJGS. 

The alleged unique, site-specific 

constraints at SJGS, that would justify 

extrapolating costs from these other 

facilities, the St. Johns River Power 

Project, which burns coke, and Harding 

Street, were never explained. The 

record, for example, does not contain 

any structural steel and duct layout 

drawings to justify this high 

contingency and other factors, nor does 

it contain vendor quotes specific to 

SJGS’s coal and site constraints. In fact, 

as noted elsewhere, we specifically 

asked PNM to document site specific 

constraints but they did not respond. 

B. Comments on Our Proposed NOX

BART Emission Limits 

We received a significant number of 

comments concerning our proposed 

NOX BART emission limit of 0.05 lbs/ 

MMBtu for the SJGS. We have 

summarized our responses to these 

comments, but refer the reader to our 

Complete Response to Comments for 

NM Regional Haze/Visibility Transport 

FIP document for more detail. 

Comment: PNM stated the BART limit 

should not be based on daily averages 

of thirty (30) calendar days, as we 

proposed, because it believes it would 

be inconsistent with the BART 

Guidelines. If calendar days are used, 

they argue, the average could include as 

little as one hour of operation if the unit 

is offline for an outage that lasts longer 

than thirty days because the first hour 

of operation would be the only data 

recorded in the last thirty calendar days. 

Instead, PNM requested that we 

consider changing ‘‘calendar days’’ to 

boiler operating days (BODs) which are 

days in which the unit ran for at least 

one hour. That approach would be 

consistent with the BART Guidelines, 

which include the following advice to 

states: 

For EGUS, specify an averaging time of a 

30-day rolling average, and contain a 

definition of ‘‘boiler operating day’’ that is 

consistent with the definition in the 

proposed revisions to the NSPS for utility 

boilers in 40 CFR part 60, subpart Da.43

The BOD would ensure that, when an 

outage occurs, the emissions following 

startup will be averaged with the 

emissions data from before the outage, 

rather than with the period of time 

during which the unit did not have any 

emissions at all because it was offline. 

Response: We agree with this 

comment that our proposed NOX

emission limit should be based on 

BODs, rather than a straight calendar 

average. In response to this comment, 

we have reanalyzed our proposed 

determination that the units of the SJGS 

can achieve a NOX emission limit of 

0.05 lbs/MMBtu on a continuous basis, 

using the BOD concept. We have done 

this because we believe the same metric 

should be used to both determine BART 

and to determine compliance with 

BART. The results of that analysis are 

presented in response to another 

comment. In summary, we continue to 

believe that NOX BART for the units of 

the SJGS is an emission limit of 0.05 

lbs/MMBtu. We have concluded that 

emission limit should be based on a 30- 

day BOD rolling average based on any 

operation in a given day counting 

toward the average. We believe that 

averaging scheme complies with the 

BART Guidelines, which defines a BOD 

to be ‘‘any 24-hour period between 

12:00 midnight and the following 

midnight during which any fuel is 

combusted at any time at the steam 

generating unit.’’ 44

Comment: The U.S. Forest Service 

(USFS) expressed its support of our 

NOX BART emission limit of 0.05 lb/ 

MMBtu. The USFS believe this emission 

limit is adequate and will improve 

visibility at Class I areas throughout the 

Four Corners region. Additionally, the 

USFS feels SCR has already been 

determined to be BART at several other 

coal-fired power plants across the 

United States. 

Response: We agree with the USFS. 

Comment: EPA predetermined the 

cost-effectiveness of SCR at SJGS 

‘‘assuming an outlet NOX of 0.05 lb/ 

MMBtu.’’ EPA then proposed that 

assumed rate as the BART emission 

limit for SJGS. EPA’s assumption is 

unfounded—the installation of SCRs at 

SJGS will not enable the units to 

achieve 0.05 lb/MMBtu on a continuous 

basis. As such, the proposed 0.05 lb/ 

MMBtu limit cannot be BART for SJGS. 

Response: We disagree with this 

comment. We initially estimated the 

cost effectiveness of SCR, assuming an 

outlet NOX of 0.07 lb/MMBtu, to 

provide a direct comparison with B&V’s 

analysis. Following this, we determined 

that a BART emission limit of 0.05 lb/ 

MMBtu was appropriate and then 

refined the cost effectiveness on that 

basis. The BART level of 0.05 lb/MMBtu 

was selected based on an examination of 

continuous emission monitoring 


jlentini on DSK4TPTVN1PROD with RULES2
Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 52403 

45 6/7/07 B&V BART Analysis, Table ES–2, Table 

2–3, Table 6–1, 7–1. 46 70 FR 39104, 39166. 47 Id. at 39172. 

systems (CEMS) data for existing units 

operating with retrofit SCRs, as we 

explain elsewhere in our response to 

comments. 

Comment: In contrast to EPA’s NOX

emission limit assumption of 0.05 lbs/ 

MMBtu, B&V, who has extensive 

practical experience in actually 

designing and installing retrofit SCRs 

determined that a retrofit SCR would 

only be capable of achieving 0.07 lb/ 

MMBtu on a continuous basis, 

particularly if required to use the lowoxidation catalyst assumed by EPA to 

minimize ancillary emission increases 

associated with SCR. 

Response: We do not believe the 

claim that B&V ‘‘determined that a 

retrofit SCR would only be capable of 

achieving 0.07 lb/MMBtu on a 

continuous basis * * *’’ is supported in 

the record by any calculations or 

arrangement drawings. Rather, the 0.07 

lb/MMBtu value is simply stated in the 

initial June 6, 2007 B&V BART analysis 

without any explanation as to how it 

was determined or why 0.07 lb/MMBtu 

satisfies BART rather than a lower 

limit.45 The basis for this limit has been 

questioned by NMED, the NPS and us 

since July 2007, but we do not believe 

that PNM has provided adequate 

supporting analysis. We do not view an 

unsupported statement, such as this, 

questioned on the record by many 

parties and inconsistent with retrofit 

SCR experience at numerous facilities, 

to be sufficient to support a BART 

determination of 0.07 lb/MMBtu. 

We note the NOX design basis was 

0.05 lbs/MMBtu for the SCR retrofit for 

the nearby Navajo Generating Station, a 

facility of a similar age that burns a 

similar coal, with a more constrained 

site. As explained elsewhere in our 

response to comments, we present data 

that demonstrates that retrofit SCR 

installations are capable of achieving a 

NOX limit of 0.05 lbs/MMBtu on a 

continuous basis. Therefore, we believe 

the statement that a retrofit SCR would 

only be capable of achieving 0.07 lb/ 

MMBtu on a continuous basis, is 

factually incorrect. 

Comment: Several commenters stated 

that our claim that many facilities are 

using SCR to actually achieve lower 

emission rates than 0.07 lb/MMBtu 

(including the Havana Unit 9, Amos 

Units 1 and 2, Chesterfield Unit 6, 

Cardinal Units 2 and 3, Colbert Unit 5, 

Ghent Units 3 and 4, and Mill Creek 

Unit 3) is incorrect. This commenter 

states that while these units have shown 

the ability to reach 0.05 lb/MMBtu or 

lower at times, those units are unable to 

do so on a continuous basis. Thus, the 

commenter claims, if the units cited by 

us were in fact subject to a 0.05 lb/ 

MMBtu emission limit, those limits 

would have been violated many times at 

each unit. 

Response: We disagree with this 

comment and continue to believe that 

the NOX emission limit we proposed for 

the four units of the SJGS, 0.05 lbs/ 

MMBtu, is achievable on a continuous 

basis. In reaching this conclusion, we 

followed the language in the BART 

Guidelines: 

It is important, however, that in analyzing 

the technology you take into account the 

most stringent emission control level that the 

technology is capable of achieving. You 

should consider recent regulatory decisions 

and performance data (e.g., manufacturer’s 

data, engineering estimates and the 

experience of other sources) when 

identifying an emissions performance level 

or levels to evaluate. 

In assessing the capability of the control 

alternative, latitude exists to consider special 

circumstances pertinent to the specific 

source under review, or regarding the prior 

application of the control alternative. 

However, you should explain the basis for 

choosing the alternate level (or range) of 

control in the BART analysis. Without a 

showing of differences between the source 

and other sources that have achieved more 

stringent emissions limits, you should 

conclude that the level being achieved by 

those other sources is representative of the 

achievable level for the source being 

analyzed.46

First, we examined ‘‘the most 

stringent emission control level that 

technology [SCR] is capable of 

achieving.’’ As demonstrated below, we 

concluded that SCR is capable of 

achieving a NOX emission limit of 0.05 

lbs/MMBtu. Second, we examined the 

record to determine if there existed 

‘‘special circumstances pertinent to the 

specific source under review’’ that 

would prevent the units of the SJGS 

from achieving this limit, and found 

none. Third, concluding there was no 

‘‘showing of differences between the 

source and other sources that have 

achieved more stringent emissions 

limits’’ that would preclude the 

application of this limit, we 

‘‘conclude[d] that the level being 

achieved by those other sources is 

representative of the achievable level for 

the source being analyzed.’’ The 

following discussion expands on these 

points. 

In our Complete Response to 

Comments for NM Regional Haze/ 

Visibility Transport FIP document, we 

provide a detailed discussion of why we 

believe the commenter, PNM, misquotes 

our cost evaluation report, which was 

incorporated into our proposal’s TSD. In 

summary, that report contained a 

previous study of SCR performance 

during the ozone season for the period 

2003–2006. This study showed that 

several units were achieving a NOX

emission limit of 0.05 lb/MMBtu at that 

time to meet NOX SIP Call regulations 

that were then in force. These SCRs only 

operated from May to October of each 

year, the ozone season. The SCRs were 

bypassed during the remainder of the 

year as they were not required to meet 

the NOX SIP Call. 

PNM presents graphs for each of the 

ozone season 2003–2006 units for the 

period January 2008 to November 2010. 

These graphs suggest that 0.05 lb/ 

MMBtu is exceeded on numerous 

occasions and imply this was due to a 

limitation of the equipment to maintain 

control. However, these graphs appear 

to be based on calendar operating days. 

This distinction is significant, as the 

BOD convention discussed by the BART 

Guidelines 47 smoothes out the 30-day 

rolling average outage spikes. Also, 

these charts include large blocks of time 

during which the SCRs were turned off 

because they were not required under 

the trading programs then in force. 

Lastly, these charts connect the dots 

across outage periods, when the SCRs 

are not in use and improperly include 

the zero hour days in the averages at 

elevated levels. 

To address this, we analyzed data 

from EPA’s Clean Air Markets Division 

(CAMD), which compiles CEMS data 

reported under various trading 

programs. We analyzed the NOX CEMS 

data for the period 2009–2010 to 

identify the best performing retrofit 

units that operate year-round. We 

ranked the annual average NOX

emissions for all units in the database 

for the years 2009 and 2010 from the 

lowest to the highest NOX emissions. 

We then selected those facilities that 

had at least one unit in the top 30 group 

in both years to identify retrofits 

achieving best performance. 

We then developed a spreadsheet 

program that used the CAMD data and 

calculated and graphed three types of 

30-day rolling averages for most of these 

best performing units, plus those 

additional units graphed by PNM for the 

period 2008–2010 for the Ozone 

Transport Assessment Group (OTAG) 

units and 2006–2010 for the Texas units 

(Parish 7, 8). All of the units we 

analyzed were retrofitted with SCR. 


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48Exhibit 2, Best Performing SCR Retrofit 

Installations, June 8, 2011. 

49 70 FR 39104, 39172. 

50We examine this data excerpt in detail in our 

Complete Response to Comments document. 

51Exhibit 2, 30 Day Rolling Averages for Selected 

Best Performing SCR Retrofit Installations. 

As Exhibit 2 shows,48 the averaging 

conventions we used are: (1) A 

conventional 30-day calendar rolling 

average; (2) a 30-day BOD rolling 

average based on any operation in a 

given day counting toward the average; 

and (3) a 30-day BOD rolling average 

based on only full 24-hour days. We 

believe that averaging scheme (2) 

complies with the BART Guidelines, 

which defines a BOD to be ‘‘any 24-hour 

period between 12:00 midnight and the 

following midnight during which any 

fuel is combusted at any time at the 

steam generating unit.’’ 49

The Havana Unit 9 data shows that it 

has operated under 0.05 lbs/MMBtu 

from mid-2009 to the end of 2010 on a 

continuous basis. In fact, this unit has 

operated under 0.035 lbs/MMBtu for 

much of that time. The Parish Unit 7 

data shows that it has operated under 

0.05 lbs/MMBtu from mid-2006 to mid 

2010 on a continuous basis. In fact, this 

unit has operated for months at 

approximately 0.035 lbs/MMBtu, and 

for approximately 2 years at 

approximately 0.04 lbs/MMBtu. The 

Parish Unit 8 data show that it has 

operated almost continuously under 

0.045 lbs/MMBtu since the beginning of 

2006. Other units’ data show months of 

continuous operation below 0.05 lbs/ 

MMBtu. We believe this data 

demonstrates that similar coal fired 

units that have been retrofitted with 

SCRs are capable of achieving NOX

emission limits of 0.05 lbs/MMBtu on a 

continuous basis. 

In addition, it is important to note 

that most of the NOX CEMS data in the 

CAMD database is generated under cap 

and trade programs, such as the Acid 

Rain Program, Clean Air Interstate Rule 

(CAIR), and the NOX SIP Call or to 

comply with elevated permit limits, 

such as from netting out of NSR review. 

Therefore, these reporting units are not 

subject to regulatory requirements that 

compel the continuous operation of 

SCRs to achieve best available NOX

reductions. Consequently, a simple 

examination of the raw data will not 

always by itself reveal the NOX

reduction these limits are capable of 

achieving. 

This is demonstrated by the Parish 

units in Texas, which are likely the best 

performing SCR units over the long 

term. The units operate to maintain a 

system wide cap, rather than to meet 

unit by unit limits. The Parish results 

may not, therefore, reflect the maximum 

capacity of the SCRs to reduce the 

plants’ NOX emissions. The Parish SCR 

acceptance tests indicate that they can 

operate at design levels, or 0.03 lb/ 

MMBtu. This is evidenced by 

examination of an excerpt from the 

hourly NOX data for Parish Unit 8, 

which typically operates at a 30-day 

rolling average of about 0.044 lb/MMBtu 

and was run for extended periods at 

0.03 lb/MMBtu from August 5, 2006 to 

September 20, 2009 and then at 0.035 

lb/MMBtu from September 21, 2006 to 

December 1, 2006 to demonstrate its 

capability.50 In other words, lower NOX

emissions are achievable from the 

existing fleet of SCR-equipped units 

than are reflected by a simple 

examination of the CAMD data. 

Comment: A commenter states that 

while the proposed NOX limit of 0.05 

lbs/MMBtu as BART for SJGS would 

significantly reduce NOX emissions 

from the SJGS and have a positive 

impact on visibility and public health, 

a lower NOX limit of 0.035 lbs/MMBtu 

is not only technically feasible, but 

legally-required for SJGS under the 

CAA. The commenter points to our 

proposal language that the State of New 

Mexico ‘‘noted the potential for greater 

control rates as low as 0.03 lbs/MMBtu’’ 

for SJGS. This commenter references our 

TSD for the proposed FIP, that SCR 

technologies ‘‘are routinely designed 

and have routinely achieved a NOX

control efficiency of 90%.’’ Therefore, 

assuming a 90% removal efficiency, 

based on SJGS’s current rate of 

emissions (under 0.30 lbs/MMBtu), the 

commenter concludes modern SCR 

technology would bring controlled 

emissions down to 0.03 lbs/MMBtu. The 

commenter proposed an emission limit 

of 0.035 lbs/MMBtu, based on a report 

performed by its own contractor. This 

report includes vendor guarantees for 

90% controls, and presents information 

that an emission limit of 0.035 lbs/ 

MMBtu is being achieved at other units. 

The commenter further states that we 

must present specific circumstances to 

preclude the application of this 

emission limit. Lastly, the commenter 

makes a case that, the feasibility of a 

lower NOX emission limit aside, the 

additional costs associated with 

achieving such a limit, weighed against 

the additional mass of NOX that would 

be removed, make such a limit cost 

effective. 

Response: We have reviewed the 

information presented in the 

commenter’s contractor’s report. As we 

discuss elsewhere in our response to 

comments, we agree there are SCR 

retrofits that are meeting NOX emission 

limits below 0.05 lbs/MMBtu. Our 

analysis also indicates there are a few 

SCR retrofits that have demonstrated the 

ability to do this on the basis of a 30 day 

BOD average. The commenter’s 

contractor has presented monthly 

emission data for a number of units 

which appear to indicate that some are 

occasionally able to meet monthly 

emission limits below 0.05 lbs/MMBtu. 

The Havana 9 unit is particularly 

highlighted, which appears to indicate 

that unit has even met such a limit for 

perhaps 4–5 months at a time. However, 

in our view, we conclude this is not 

enough time to demonstrate that the 

units of the SJGS are able to meet a NOX

limit of 0.035 lbs/MMBtu on the basis 

of a 30 day rolling average year round. 

We further agree that it may be 

technically feasible, considering both 

vendor performance guarantees, and the 

data discussed above, for some SCR 

retrofits to reliably meet an NOX limit of 

0.035 lbs/MMBtu on a 30 day rolling 

average (especially if figured on the 

basis of a BOD). However, we see no 

data, presented either by the commenter 

or from our own research,51 which we 

have discussed elsewhere in our 

response to comments, which would 

lead us to conclude that such a limit has 

been sufficiently demonstrated in 

practice. 

To our knowledge, there are no air 

permits in the U.S. that require that a 

NOX emission limit of 0.035 lbs/MMBtu 

be met for a coal-fired unit such as SJGS 

with retrofitted SCRs on the basis of a 

30 day rolling average. Furthermore, the 

existence of a permit limit is not the 

only indicator of the technical 

feasibility of achieving a particular 

emission limit. However, its absence, 

combined with no documented instance 

of an SCR retrofit achieving this level of 

control on a continuous basis, causes us 

to conclude that a 30 day rolling average 

NOX emission limit of 0.035 lbs/MMBtu 

for the units of the SJGS is not BART. 

Comment: The NPS and the USFS 

separately stated they believe PNM has 

underestimated the ability of SCR to 

reduce emissions. For example, the NPS 

states that B&V assumed that SCR could 

achieve 0.05 lbs/MMBtu (annual 

average) when evaluating retrofitting of 

SCR at the Craig power plant in 

Colorado. Both the NPS and the USFS 

stated that EPA’s Clean Air Markets 

data, and vendor guarantees show that 

SCR can typically meet 0.05 lb/MMBtu 

(or lower) on an annual average basis. 

The USFS stated NOX emissions can be 

reduced by 90% with SCR installed at 

0.05 lbs/MMBtu emission limit. The 

NPS included data it claims indicates 


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52 70 FR, 39104, 39172. 

that SCR can achieve year-round 

emissions of 0.05 lbs/MMBtu or lower at 

26 coal-fired EGUs, eleven of which are 

dry-bottom, wall-fired units like SJGS. 

The USFS also referenced this data. The 

NPS believes PNM has not provided any 

documentation or justification to 

support the higher values used in its 

analyses. They also present information 

from industry sources that supports 

their understanding that SCR can 

achieve 90% reduction and reduce 

emissions to 0.05 lb/MMBtu or lower on 

coal-fired boilers. 

Response: We agree with the NPS that 

PNM has underestimated the ability of 

SCR to reduce emissions. As discussed 

elsewhere in our response to comments, 

we are requiring that the units of the 

SJGS meet an emission limit of 0.05 lbs/ 

MMBtu on the basis of a 30 day rolling 

BOD average. 

Comment: PNM requested that we 

reevaluate the cost effectiveness of SCRs 

at SJGS because they feel that our 

proposed NOX emission limit of 0.05 

lbs/MMBtu on the basis of a 30 day 

rolling average is not achievable. They 

reason that we therefore overestimated 

the emission reductions that the SCRs 

would achieve, thus underestimating 

the cost per ton of pollutant removed. In 

addition, they requested we reevaluate 

the visibility improvement that it 

assumed the SCRs would provide. They 

reason that at a higher NOX emission 

limit, the SCRs would not achieve 

nearly the level of visibility 

improvement that we expect. 

Response: As explained elsewhere in 

our response to comments, we believe 

the units of the SJGS can achieve a NOX

emission limit of 0.05 lbs/MMBtu on the 

basis of a 30 day BOD average. 

Therefore, we do not believe there is 

any need to revise either the visibility 

modeling or the cost analysis on that 

basis. 

Comment: The USFS feels that PNM 

has underestimated the achievable 

emission limit that would result with 

Low-NOX burners with overfire air, 

combined with SCR. Based on data from 

EPA’s Clean Air Markets, SCR usually 

meets an annual average emission limit 

of 0.05 lbs/MMBtu or lower. Based on 

the same data, 26 electric generating 

units have met this emission limit, 

eleven of which are similar in design as 

the SJGS. NOX emissions can be 

reduced by 90% with SCR installed at 

0.05 lbs/MMBtu emission limit. Given 

the SJGS’s size and amount of NOX

emissions, a more stringent emission 

limit than PNM’s proposal is not only 

achievable, but it will provide for 

greater reduction in NOX emissions. 

Response: We agree with the USFS 

that PNM has underestimated the 

emissions reductions achievable with 

the addition of SCR. However, we draw 

a distinction between units that have 

met an emission limit of 0.05 lbs/ 

MMBtu and those that have reliably 

demonstrated the ability to 

continuously meet that emission limit. 

Therefore, although we agree there are 

many SCR installations that are capable 

of meeting an annual NOX emission 

limit of 0.05 lbs/MMBtu, we extended 

our analysis. As we discuss elsewhere 

in our response to comments, we also 

analyzed the ability of some of the better 

controlled SCR retrofits to meet this 

same limit on a 30 BOD average and 

found that it was feasible for the SJGS 

to do so. 

Comment: EPA proposes to require 

the SJGS to meet a NOX emission limit 

of 0.05 lbs/MMBtu individually at each 

of the plant’s four units. EPA’s own 

BART rules, however, expressly 

authorize application of BART emission 

limits on a plant wide basis, and the 

proposal offers no justification for 

deviating from that established and 

reasonable practice. Because it makes no 

difference, in terms of visibility impact 

or visibility improvement, as to which 

unit or units within a facility the 

emissions—or the emission 

reductions—occur at, there is no 

rational basis for the Agency to preclude 

the plant wide averaging that is 

contemplated in EPA’s own BART rules. 

Response: The commenter correctly 

notes that the BART Guidelines state 

that the BART determining authority 

‘‘should consider allowing sources to 

‘average’ emissions across any set of 

BART-eligible emission units within a 

fenceline, so long as the emission 

reductions from each pollutant being 

controlled for BART would be equal to 

those reductions that would be obtained 

by simply controlling each of the BARTeligible units that constitute BARTeligible source.’’ 52

As we discuss elsewhere in our 

response to comments, we received 

another comment requesting that we 

revise our proposed NOX BART limit, 

which was calculated on the basis of a 

rolling 30 day calendar average, and 

adopt instead a limit calculated on the 

basis of a rolling 30 day BOD average. 

We agree, and are finalizing our action 

in accordance with that request. 

Combining a plant wide average with a 

BOD average in which individual units 

may be on different 30 day periods, 

adds an additional level of complexity 

to the calculation of a plant wide 

average. We believe it is possible to 

integrate the 30 day BOD and plant 

wide averaging concepts, but due to our 

consent decree deadline, we do not have 

the time to construct the algorithm that 

could be used to guarantee practical 

enforceability. Therefore, as we discuss 

elsewhere in our response to comments, 

we condition the NOX limit for the units 

of the SJGS on the basis of a rolling 30 

day BOD average. We leave the issue of 

a plant wide average to a possible future 

SIP revision that includes a verifiable, 

workable and enforceable algorithm that 

ensures the resulting emissions are 

equal to those reductions that would be 

obtained by simply controlling each of 

the BART-eligible units that constitute 

BART-eligible source. 

Comment: One commenter requested 

we exclude emissions occurring during 

startup, shutdown, and malfunctions 

events from having to comply with our 

proposed NOX limit of 0.05 lbs/MMBtu 

because post-combustion controls 

equipment such as SCRs cannot operate 

effectively during those events. 

Alternatively, this commenter requested 

we consider setting a different standard 

that is more representative of the 

emission characteristics of the units 

during those events or consider 

requiring work practice standards to 

minimize such emissions. Another 

commenter requested that we 

specifically include startups and 

shutdowns in this language, making 

clear that any emission in excess of an 

applicable emission limit during any 

such event constitutes a violation of the 

applicable emission limit. That 

commenter also requested that we 

clarify that this provision applies to all 

pollutants controlled by this FIP, 

including, NOX, SO2, H2SO4, ammonia, 

and particulate matter (PM). 

Response: As we have discussed in 

our response to other comments, we are 

changing the rolling averaging period 

for our proposed NOX emission limit of 

0.05 lbs/MMBtu from one based on 30 

calendar days, to one based on a 30 

BODs. The CEMS data indicate that our 

proposed NOX BART limit can be 

achieved without separately limiting 

startups, shutdowns, and malfunctions. 

Further, the startup, shutdown, and 

malfunction events cited in this 

comment are a characteristic of current 

SCR operating modes, i.e., under trading 

programs with no incentive to optimize 

design and operation to achieve a 

permit limit. These spikes result when 

flue gas temperatures fall below the 

operating temperature range of the SCR 

catalyst, or when the ammonia injection 

system malfunctions. We believe that 

startup and shutdown spikes are 

minimized by using the BOD metric, 

which we assume was why it was 

requested that we employ it. As there is 

no explicit provision for the exclusion 


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53 70 FR 39104, 39163. 

of start up, shut down, or malfunction 

events for NOX, SO2, and H2SO4, all data 

will be used in determining compliance 

with this limit. As explained elsewhere 

in our response to comments, we are not 

setting an emission for PM for the units 

of the SJGS at this time, and we have 

determined that neither an ammonia 

limit, nor ammonia monitoring is 

warranted. We do not see a need to 

further clarify that the limits we are 

finalizing must be continuously met. 

We also agree with the comment that 

work practice standards should be 

developed and used to minimize such 

emissions. These should include 

proactive measures such as SCR reactor 

preheating during a cold start; selecting 

catalyst to maximize ramp rates and 

NOX reduction at low temperatures; and 

use of both tunable ammonia injection 

grids (AIGs) and static mixers. We 

encourage PNM to develop and employ 

those measures. 

Comment: PNM contends our 

conclusions differ greatly from those 

that have been made in other states in 

determining NOX BART for other 

electric generating units. PNM 

submitted a table of the other NOX

BART determinations that have been 

made by 13 different states as they have 

developed the proposed RH SIPs that 

are awaiting EPA approval. PNM stated 

that in comparison to the 

determinations made by every other 

state, the EPA proposal concludes that 

SJGS must be required to install, (i) the 

most effective SCR in the nation, (ii) at 

the cheapest price, and (iii) in the 

shortest amount of time. PNM 

concludes that if our proposal is a true 

indication of our interpretation of the 

RH program, we will be faced with 

disapproving every other state RH 

implementation plan in the country and 

replacing those plans with FIPs. 

Response: As explained in our 

responses to other comments, we have 

made adjustments in our NOX BART 

determination for the SJGS that pertain 

to this comment. We have adjusted our 

cost basis for the installation of SCR on 

the units of the SJGS, which slightly 

increased the cost of the controls versus 

the tonnage of NOX removed. In 

addition, we have modified the 

schedule for compliance with the 

emission limits to now require 

compliance within 5 years—rather than 

3 years—from the effective date of our 

final rule. Also discussed in our 

responses to other comments, although 

we find that our proposed NOX BART 

emission limit should remain at 0.05 

lbs/MMBtu, we have modified the 

averaging time from a straight 30 day 

calendar rolling average, to a 30 day 

BOD average. 

We disagree with the statement that 

our conclusions regarding NOX BART 

for the SJGS are far different from those 

that have been made in other states in 

determining NOX BART for other 

electric generating units. As the 

commenter’s own table indicates, other 

states and EPA regions have made NOX

BART determinations that will be met 

or are proposed to be met with the 

addition of SCR, including the Four 

Corners Power Plant (EPA Region 9), 

Hayden Units 1 & 2 (CO), Otter Tail Big 

Stone 1 (although this is a cyclone 

boiler) (SD), and Naughton Unit 2. 

Also, we initially note two points 

regarding the costs of the controls, while 

accepting the values listed on the chart 

at face value. First, the cost effectiveness 

of all the BART controls, which 

depending on the facility range from 

combustion (e.g., OFA, LNB) to post 

combustion (e.g., SCR, SNCR), are 

frequently much worse (more 

expensive) than the cost effectiveness 

we calculated for SCR on the units of 

the SJGS. Second, the cost effectiveness 

values listed for SCR, are frequently 

similar to the cost effectiveness we 

calculated for SCR on the units of the 

SJGS (especially if compared to our 

revised cost effectiveness). 

Lastly, although we strive to ensure 

that the regulated community is treated 

equitably with regard to the RHR, the 

nature of the BART five factor analysis 

is designed to consider site-specific 

issues. For instance, we note that the 

chart does not contain any information, 

nor is any presented elsewhere, 

concerning a visibility impact analysis. 

As required by the BART Guidelines, 

this must be included in a BART 

analysis.53 Without such an analysis, 

there is no way to justify any control 

even if it has a very low cost. 

Conversely, even controls that have 

either a relatively high capital cost or 

cost effectiveness in terms of dollars per 

ton may be justified if they result in a 

significant visibility benefit. In the case 

of the SJGS, our BART FIP NOX

emission limit of 0.05 lbs/MMBtu is 

predicted to result in a combined 

visibility improvement on 16 Class I 

areas of 21.69 dv, which we consider 

very significant. 

C. Comments on Our Proposed SO2

Emission Limit 

Comment: One commenter stated an 

SO2 emission rate of 0.15 lbs/MMBtu on 

a 30 day rolling average is not 

appropriate and does not ensure that 

SO2 emissions from SJGS will not 

interfere with visibility in New Mexico 

or other states. This commenter believes 

an SO2 emission rate of 0.15 lbs/MMBtu 

does not reflect the level of emissions 

reductions achievable under BART for 

wet limestone scrubbers. This 

commenter also points out that the units 

of the SJGS are all currently achieving 

SO2 limits significantly under 0.15 lbs/ 

MMBtu on a 30 day rolling average and 

concludes we should not set SO2

emission rates in a Section 110 FIP that 

exceed the historic SO2 emission rates at 

SJGS. The commenter requests that if 

we do set a non-BART SO2 limit in our 

Section 110 FIP, we set unit-specific 

limits at least consistent with the recent 

historic SO2 emission identified in the 

table above, or issue formal SO2.BART 

determinations for each unit at SJGS 

under a Section 308 FIP. 

Response: We believe the SO2

emission rate of 0.15 lbs/MMBtu is 

appropriate to meet the requirements of 

section 110(a)(2)(D)(i)(II) to ensure that 

these emissions from SJGS will not 

interfere with visibility in other states. 

As discussed in our proposal, we 

believe that emissions reductions 

consistent with the assumptions used in 

the WRAP modeling will ensure that 

emissions from New Mexico sources do 

not interfere with the measures 

designed to protect visibility in other 

states. We are aware that the SO2

controls currently installed on the SJGS 

are in fact achieving greater control than 

would be evidenced by an emission 

limit of 0.15 lbs/MMBtu. The 

commenter’s observation of the SJGS’s 

current SO2 emissions simply means 

that the SO2 emissions from the SJGS 

are better controlled than what we 

require to prevent interference with 

visibility under section 

110(a)(2)(D)(i)(II). We agree with the 

commenter that the 0.15 lbs/MMBtu 

emission limit does not reflect the level 

of emissions reductions achievable 

through the use of a wet limestone 

scrubber and that a source specific 

BART determination for the SJGS might 

well result in a determination requiring 

the installation of scrubber to meet a 

more stringent limitation. We did not 

propose to address the BART 

requirements for SO2 from the SJGS in 

this action because SJGS will not be 

installing new control equipment to 

meet the 0.15 lbs/MMBtu emission 

limits. As a result, the issue of requiring 

different capital expenditures to meet 

the requirements of section 

110(a)(2)(D)(i)(II) as compared to those 

of the RH program’s BART requirement 

does not arise. Since we did not propose 

the SO2 emission rate under the RHR 

requirements, the comments concerning 

BART are outside the scope of this 

action. 


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54 76 FR 499. 

Comment: In declining to find that its 

asserted SO2 limits satisfy BART, EPA’s 

proposal improperly relies on a RH 

trading program under 40 CFR 51.309 

that does not yet exist. Putting aside 

EPA’s legal obligation to make a formal 

BART determination in its proposed FIP 

at this time, any emissions trading 

program that is proposed to replace a 

BART limit ‘‘must achieve greater 

reasonable progress than would be 

achieved through the installation and 

operation of BART.’’ 40 CFR 

51.308(e)(2). Because EPA cannot make 

the required demonstration that New 

Mexico’s future, theoretical trading 

program will be ‘‘better than BART,’’ 

EPA is illegally sidestepping its current 

BART obligations under 40 CFR 51.308 

(e)(2)(i). 

Response: We disagree with the 

commenter. In accordance with our 

proposal, we are finalizing SO2

limitations under section 

110(a)(2)(D)(i)(II), not under the RHR. 

We disagree with commenter’s view that 

we are sidestepping our BART 

obligations by not proposing to establish 

SO2 BART emission limits. Our 

rationale for not proposing BART 

requirements for SO2 in this action 

appears in our response just prior to this 

comment. Moreover, we note that the 

established SO2 limits do not rely upon 

a nonexistent trading program. We will 

address New Mexico’s obligation to 

address SO2 under the RHR in a future 

separate action. 

D. Comments on Our Proposed H2SO4

and Ammonia Emission Limits and 

Other Pollutants 

Comment: The League of Women 

Voters, Montezuma County, Colorado 

supports the EPA determination that 

SCR is cost-effective for all units of the 

SJGS. They defer to our judgment on the 

proposed final limit for sulfuric acid 

emissions. They request that we choose 

the lower limit of 2 ppmvd, adjusted to 

6 percent oxygen for the regulation of 

ammonia emissions. Their justification 

for this request is the deterioration in 

visibility at Class I areas such as Mesa 

Verde National Park, and the imperative 

to achieve improvements in visibility as 

rapidly as possible. 

Response: We appreciate the support 

of the League of Women Voters, 

Montezuma County, Colorado. As 

explained elsewhere, we have 

determined that neither an ammonia 

limit, nor ammonia monitoring is 

warranted. 

Comment: One commenter stated the 

same pollutants, including PM 2.5, 

NOX, and VOCs (contributing to ground 

level ozone) that contribute to visibility 

impairment also harm public health. 

This commenter also noted that ozone 

concentrations in parks in the Four 

Corners region approach the current 

health standards, and likely violate 

anticipated lower standards. In fact, 

ozone levels in many parts of New 

Mexico, Colorado, and Utah are already 

in the range of ozone levels deemed to 

be harmful to human health. 

Response: We agree that the same 

pollutants that contribute to visibility 

impairment can also harm public 

health. Although we note public health 

benefits, we did not rely on these 

benefits in establishing controls 

necessary to meet BART in today’s 

action. 

Comment: One commenter expressed 

support for our proposed H2SO4 and 

ammonia limits proposal for the SJGS, 

and the corresponding installation of 

CEMS. That commenter also urged us to 

set the H2SO4 emission rate at the 

lowest rate of 1.06 × 10¥4 lb/MMBtu for 

each unit at the SJGS, suggesting stack 

test monitoring for H2SO4 on a more 

frequent basis than annual monitoring. 

The commenter also supported our 

proposed ammonia emission limit at the 

lower range of 2.0 ppm, with CEMS. 

Further, this commenter requested we 

clarify these emission limits are 

required under the RH program as part 

of a BART determination for the facility 

and must be complied with within 3 

years of the date of the final rule. Lastly, 

we were requested to set a BART PM 

emission limit of 0.012 lb/MMBtu on a 

6-hour block average, and a 10% opacity 

limit at each unit at SJGS, also within 

3 years of the date of the final rule. 

Another commenter questioned our 

authority to regulate ammonia through 

the RH rule. 

Response: 

In our response to comments on the 

assumed ammonia slip level used to 

estimate sulfuric acid emissions, we 

have recalculated the expected sulfuric 

acid emissions rate with no ammonia 

slip. The sulfuric acid emission rate was 

recalculated to be 2.6 ×10¥4 lb/MMBtu 

based on an ammonia slip value of 0 

ppm, compared to our original value of 

1.06 ×10¥4 lb/MMBtu at 2ppm 

ammonia slip. The actual ammonia slip 

will vary over the life of a catalyst layer. 

We conclude an assumption of 

ammonia slip up to 2.0 ppm as the 

catalyst ages is reasonable for an SCR 

system that is designed to achieve a 

NOX emission limit of 0.05 lbs/MMBtu 

on a rolling 30 BOD basis, considering 

the coal the SJGS burns. We also note 

PNM assumed an ammonia slip of 2.0 

ppm in its SCR cost estimation. As the 

ammonia slip increases, the sulfuric 

acid emissions will decrease. This 

revised sulfuric acid emission rate 

remains significantly lower than that 

estimated by NMED and is a minimal 

level of sulfuric acid emissions. Based 

on these updated calculations and in 

response to comments, we are requiring 

the SJGS to meet an H2SO4 emission 

limit of 2.6 ×10¥4 lb/MMBtu. 

Our intention in our proposal 

regarding the regulation and monitoring 

of ammonia was, like H2SO4, to 

minimize the contribution of this 

compound to visibility impairment. 

After careful consideration of the 

comments we received concerning our 

proposal to require the SJGS to meet an 

hourly average emission limit of 2.0 

parts ppmvd for ammonia, we have 

determined that neither an ammonia 

limit, nor ammonia monitoring is 

appropriate. Instead, we will approach 

the issue of the impact of ammonia slip 

on visibility impairment though proper 

upfront design, rather than after-the-fact 

regulation. We are requiring that the NO 

control device (presumably, but not 

required to be SCR) must be designed to 

achieve a NOX emission limit of 0.05 

lbs/MMBtu on a rolling 30 BOD basis 

with an ammonia slip of 2.0 ppm. We 

believe this strikes the proper balance 

between the additional cost of ammonia 

monitoring and reporting and the need 

to have a reasonable expectation of the 

amount of ammonia emitted by the 

SJGS. 

The H2SO4 emission limit is being 

required under the RH program as part 

of a BART determination for the SJGS 

and must be complied with at the same 

time as the NOx limits for each unit. 

With regard to the commenter’s request 

that if emission monitors are truly 

unavailable for this pollutant, we 

should require stack test monitoring for 

H2SO4 on a more frequent basis than 

annual monitoring, we do not believe 

that an adequate continuous emissions 

monitor is available for H2SO4 and will 

continue to rely on stack testing. We do 

not agree that more frequent stack 

testing is appropriate, due to a 

consideration of the cost of that testing 

in comparison to the value of having a 

greater certainty of the H2SO4 emissions 

that may result. As we discussed in our 

proposal,54 we have concluded that the 

low sulfur coal burned at the SJGS 

generates very little sulfur trioxide 

(SO3), and hence H2SO4, which is 

formed when SO3 combines with water 

in the flue gas to form H2SO4. In 

addition, SCR catalysts are available 

with a low SO2 to SO3 conversion of 

0.5%, further limiting the production of 

H2SO4. Therefore, we conclude we have 

struck the right balance. 


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55ClearSkies: http://www.epa.gov/clearskies/ 

03technical_package_sectiong.pdf. 

56 ‘‘Implementation Schedule for Selective 

Catalytic Reduction (SCR) and Flue Gas 

Desulfurization (FGD) Process Equipment’’ October 

1, 2010, prepared by J. Edward Cichanowicz for the 

Utility Air Regulatory Group. 

57U.S., et al., v. Ohio Edison Company, et al., 

Opinion and Order, Case No. 2:99–CV–1181, In the 

U.S. District Court for the Southern District of Ohio, 

Eastern Division, available at: http:// 

www.4cleanair.org/OhioEdison.pdf. 

58U.S. v. Ohio Edison and Pennsylvania Power 

Company, Consent Decree, March 18, 2005, 

available at: http://www.epa.gov/compliance/ 

resources/decrees/civil/caa/ohioedison-cd.pdf. 

59Michael D. McElwain, Sammis Energy Plant 

Project Wins Award, Herald-Star, December 13, 

2010, available at: http://www.hsconnect.com/page/ 

content.detail/id/552039/Sammis-energy-plantproject-wins-award.html?nav=5010. 

E. Comments on the Emission Limit 

Compliance Schedule 

Comment: We received a number of 

comments both for and against our 

proposal to require compliance with our 

proposed emission limits within three 

years following the effective date of our 

final action. The League of Women 

Voters, Montezuma County, Colorado 

opposed extending the deadline to five 

years for achieving the proposed 

emission limits. They stated SCR was 

first patented in the U.S. in 1957 and 

has been an operational pollution 

control technology for over 30 years at 

large scale facilities like the SJGS. They 

believe allowing an extra two years may 

provide the opportunity for ambiguity 

and technological changes to enter into 

arguments about engineering solutions 

and controls, which potentially could 

feed appeals and litigation by the 

operator of the SJGS, and thus delay 

cleanup efforts. The Navajo Nation 

expressed concern that the proposed 

compliance schedule is too stringent for 

SJGS to reasonably meet and could 

result in a reduction-in-force of a 

significant number of employees, 

including Navajo workers, thereby 

contributing to family hardships and 

limiting the ability of affected 

employees, contractors, and 

subcontractors to meet their financial 

obligations. 

Another commenter asked if there is 

a smarter way to phase the installation 

of controls over a longer period of time. 

Another commenter stated any 

proposed truncation of the five-year 

compliance period should be 

persuasively justified by a specific 

analysis of the feasibility and costeffectiveness of such a schedule in light 

of the circumstances at the facility in 

question. According to the commenter, 

no such justification appears in the 

proposed rule. The proposal simply 

asserts that a three year compliance 

deadline would be applicable because 

similar compliance schedules have been 

met at some other facilities. 

Another commenter stated that a 

compliance deadline of three years will 

result in significant additional costs that 

we did not account for in our analysis. 

They stated the proposed FIP attempts 

to justify a three-year compliance 

deadline by citing two studies, but those 

studies do not reflect a realistic 

schedule for installing SCRs at SJGS. 

This commenter made several points 

concerning two studies on SCR 

timelines we cited in our proposal that 

the commenter feels call our use of the 

information into question. The 

commenter then cites another report it 

believes is more representative and 

concludes the site congestion and other 

site-specific challenges at SJGS will 

demand an implementation schedule 

that is similar to SCR installations at 

Units 6 and 7 of First Energy’s Sammis 

facility, which required 60 and 62 

months to complete, respectively. 

Response: We have decided, based on 

our review of several comments, to 

finalize a schedule for compliance with 

the emission limits of 5 years—rather 

than 3 years—from the effective date of 

our final rule. We view the B&V cost 

analysis as being a very preliminary, 

low-level estimate, that is missing much 

of the information required to develop 

a site-specific schedule. This estimate 

does not include, for example, plot 

plans, a diagram showing SCR layout, 

an analysis of constructability, 

construction site plan, or an 

implementation schedule, which are 

required to develop a site-specific 

schedule. Thus, we selected an average 

compliance time, based on a review of 

a number of sources, including the 

following: 

• 13 months for 675 MW Somerset 

Station; 

• 18 months for Harding Street; 

• 19 months for two 900 MW units at 

Keystone. 

• 26 months for Asheville Power 

Station with a reported normal range of 

27 to 30 months. 

• 30 months for 4 units based on 21 

months typical for 1 unit, each 

additional unit at same facility adds 2– 

3 months. Findings for typical 

installations.55

• 36 months for St John River Power 

Park, from contract award to startup. 

• 42 months for 14 SCRs installed to 

comply with the Texas Nonattainment 

SIP. 

• 60 months estimated by B&V for 5 

units at Four Corners. 

• 69 months estimated by Sargent & 

Lundy for 3 units at Navajo. 

The median of these estimates is 33 

months and the average is 37 months. 

The UARG report 56 cited in this 

comment was published around the 

same time (October 1, 2010) that we did 

most of our SCR analysis and was 

unknown to us at that time. PNM and 

B&V did not identify it in discussions 

with us in October–November 2010. 

That report confirms the information we 

found through independent 

investigation, summarized above. It 

indicates that it took 28 to 62 months to 

design and install the 14 SCRs in its 

sample (compared to 18–69 months for 

the 9 facilities (greater than 33 units) in 

our sample). The average design/build 

time for the units in the report is 43 

months, compared to an average of 37 

months for our retrofit SCR timeframes. 

None of the units in these two 

collections overlap. We agree, based on 

the information we have from the site, 

that site congestion will require a longer 

total installation time for all four units 

than the average found in both of these 

collections. Please see our Complete 

Response to Comments for NM Regional 

Haze/Visibility Transport FIP document 

for more detail concerning our response 

to this question. 

However, we do not believe there is 

a basis in the record for concluding that 

installation of SCRs would require a 

timeframe as long as claimed for 

Sammis Units 6 and 7. The seven 

Sammis units were subject to an 

enforcement action,57 and the SCRs 

were installed pursuant to a Consent 

Decree.58 The Consent Decree allowed 

5+ years, from the date of the Decree in 

March 2005, to install SCR on two units, 

SNCR on five units, low NOX burners, 

and new SO2 scrubbers on seven units. 

Construction was completed faster than 

the Consent Decree schedule, however, 

and all of the controls were operating by 

May 2010. 

The Sammis retrofit project at this 

2,200 MW plant is generally recognized 

as the largest air quality control retrofit 

in the history of the United States and 

is considered to be ‘‘the most difficult 

in the country because of the extremely 

limited space for installation of the new 

air emission control equipment and 

systems.’’59 This project is not 

comparable to SCR retrofits at SJGS, 

neither in scope, nor complexity, nor 

site congestion. 

Based on an examination of site 

conditions and available data on 

historical SCR installation timeframes as 

described above, we find that a change 

to our proposed compliance schedule is 

appropriate. We believe that a longer 

time frame than the median time frame 

for construction identified in our survey 

of SCR retrofits is justified due to site 


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congestion. We do not believe a 

timeframe as long as that allowed for the 

Sammis units is warranted, nor is it 

allowed by the RHR. Consequently, we 

are finalizing a schedule which requires 

compliance with the emission limits 

within 5 years—rather than 3 years— 

from the effective date of our final rule. 

Comment: A commenter objected to 

the proposed compliance schedule of 3 

years and was concerned that SCR 

installations often trigger PSD 

permitting requirements because they 

constitute physical changes to an 

existing emission unit that may result in 

increased emissions of sulfuric acid 

mist. The commenter stated that 

obtaining a PSD permit for an SCR can 

take up to 18 months or more and even 

if the SCRs do not trigger PSD 

permitting requirements projects could 

still trigger state permitting 

requirements, which can require several 

months to satisfy. The commenter 

further stated that the installation of an 

SCR will involve a significant capital 

expenditure that will require approval 

from the New Mexico Public Regulation 

Commission. The commenter alleged 

that we failed to take these requirements 

into account resulting in an 

unachievable deadline for compliance. 

Response: As stated elsewhere in our 

response to comments, we have 

modified the compliance schedule. We 

are finalizing a schedule which requires 

compliance with the emission limits 

within 5 years—rather than 3 years— 

from the effective date of our final rule. 

We conclude this is adequate time for 

the inclusion of any possible permitting 

requirements. 

Comment: A commenter stated that 

our compliance schedule of three years 

from the effective date of our final rule 

did not allow time for competitive 

bidding. To meet a three-year schedule, 

the commenter argued, PNM would 

have to simply offer the work to a single 

vendor, eliminating the opportunity to 

identify other qualified vendors or 

provide any incentive to encourage 

competitive pricing. Therefore, the 

failure to account for this renders the 

three-year compliance date unrealistic, 

and calls into question the underlying 

cost estimates, which are based on 

contracts entered into by other utilities 

that most likely were allowed sufficient 

time to complete a proper competitive 

bidding process. 

Response: We believe this comment is 

incorrect. The 3 year schedule we 

proposed did include time to prequalify 

bidders. However, as stated elsewhere 

in our response to comments, we have 

extended the compliance schedule to 5 

years. 

Comment: A commenter stated that 

our cost estimate does not appear to 

account for the need to have two units 

offline at the same time to install the 

SCRs, and the commenter expresses the 

view that PNM would not be able to 

meet a three-year deadline for 

compliance without taking two units 

offline at once. The commenter listed a 

number of things that would have to 

occur in the construction process, such 

as engineering, vendor procurement, 

and catalysts procurement, and finally, 

the fact that construction on each unit 

needs to take place during an outage. In 

addition, the commenter argues, a threeyear deadline would likely eliminate the 

ability of PNM to plan the outages for 

off-peak seasons, when the demand for 

power and the cost for replacement 

power are lower. Also, a three-year 

period would require PNM to 

prefabricate as much of the SCRs as 

possible, which would require 

extremely large prefabrication yards and 

prefabrication crews, significant 

overtime hours, expedited material 

costs, double ‘‘heavy long-lift’’ crane 

costs, and a larger construction 

workforce overall. The commenter states 

these costs were not included in its 

analysis. The commenter lists other 

complications such as a shortage of 

skilled labor, air permitting 

requirements, and other preconstruction activities, the possible 

need to purchase electricity at higher 

prices, and strain on PNM’s other 

generating assets. The commenter 

requests we consider these costs and 

constraints in its setting a three- to fiveyear, compliance schedule and set the 

deadline for compliance to the five 

years allowed by law, or even longer if 

PNM is required to respond with a 

‘‘Better than BART Alternative.’’ 

Response: As stated elsewhere in our 

response to comments, we have 

modified the compliance schedule. We 

find that compliance with the emission 

limits must be within 5 years of the 

effective date of our final rule. A longer 

schedule will allow PNM to tie in the 

SCRs during routinely scheduled 

maintenance outages and to plan 

outages for off-peak seasons. We have 

not received any request from PNM that 

we consider a ‘‘better than BART 

alternative.’’ 

F. Comments on the Conversion of the 

SJGS to a Coal-to-Liquids Plant With 

Carbon Capture as a Means of Satisfying 

BART 

We received comments encouraging 

us to consider coal-to-liquids (CTL) 

technology with integrated power 

generation as an option in determining 

BART for SJGS. The commenter states 

that our BART determination proposal 

would reduce NOX emissions, but 

would do little to reduce SOX or carbon 

dioxide (CO2) emissions, leaving SJGS 

far from compliance with new or future 

standards. The commenter states our 

BART proposal could cost $750 million 

or more (based on PNM’s figures), and 

would have an adverse effect on the cost 

of electricity. Based on 2006-generation 

numbers of 12.5 million MWh’s, 

amortized over a 20-year period at 8% 

interest, and a $750 million 

modification price, the commenter 

calculates the cost of electricity would 

increase by approximately $6 per MWh 

or 0.6 cents per kWh. 

The commenter states that although 

natural gas fired combined cycle, and 

integrated gasification combined cycle, 

have merit no option offers more 

benefits than a CTL plant with 

integrated power generation. According 

to the commenter, the synthetic fuels 

produced are drop-in replacements for 

diesel and jet fuel, and contain virtually 

no sulfur. The US military has 

conducted extensive tests on these fuels, 

and finds that they produce far lower 

emissions than conventional petroleumbased fuels. 

According to the commenter, the 

conversion of the SJGS into a CTL plant 

with integrated power generation would 

retain jobs in the mining and plant 

operations, will create ultra-clean 

biodegradable synthetic fuels in the CTL 

process, and will use the waste heat and 

byproduct gases from the process to 

cogenerate electric power. The 

commenter states that emissions of 

criteria pollutants from the CTL plant 

manufactured by his company approach 

those of a NGCC plant and emissions of 

CO2 are half those of a NGCC plant. 

The commenter calculates that a 

50,000 barrel per day CTL plant can coproduces 1200 MW of clean, efficient, 

low carbon power. This would be 

baseload generation, the commenter 

argues, that would be produced 24/7 

and could be sold into the California 

marketplace. The size of the facility 

could be scaled to meet greater energy 

needs. The commenter states a plant of 

this size would consume approximately 

30,000 tons per day of coal, which is 

nominally twice as much coal as is 

currently consumed, so more jobs will 

be needed at the mine. 

According to the commenter, NOX

emissions would be reduced by 50 to 1, 

SOX emissions would be reduced by 20 

to 1, and CO2 emissions would be 

reduced by 5 to 1. The commenter also 

notes that ash in the coal is melted in 

the gasification process, and can be used 

as an aggregate for paving roadways. In 

addition, the sulfur from the process can 


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60 70 FR 39104, 39164. 

be collected as elemental sulfur, and 

sold as a byproduct. Water consumption 

would be reduced by about 1⁄2 in 

comparison to a conventional power 

plant of the same MW output, due to the 

use of a hybrid cooling system (aircooled condenser in conjunction with a 

cooling tower). 

The commenter points out that 

KinderMorgan has an existing CO2

pipeline in the vicinity. The CO2 from 

the plant could be sold to KinderMorgan 

and used for enhanced oil recovery. 

A plant of this scale, according to the 

commenter, would cost approximately 

$8 billion to construct, assuming all 

new equipment. However, this cost 

could be substantially reduced by reutilization of much of the plant, 

including coal handling equipment, 

steam turbines, condensers, cooling 

towers, and transmission lines. The reutilization of existing equipment could 

reduce the capital cost by an estimated 

25 to 35% as compared to a totally new 

facility. The commenter suggests this 

could be a BART (retrofit) solution. The 

commenter argues the revenues from 

this plant would provide a return on 

investment that exceeds all other 

considered options by a wide margin. 

The commenter encourages us to 

consider conversion to a CTL plant with 

integrated power generation to be BART 

for SJGS. 

Response: We appreciate the 

commenter’s suggestion that we 

consider CTL technology with 

integrated power generation as an 

option in determining NOX BART for 

the SJGS. Although we encourage PNM 

and the other owners of the SJGS, and 

the Navajo Nation to examine this 

concept in detail, we cannot consider it 

as a potential NOX BART technology as 

it would involve a complete redesign of 

the plant. We note the BART guidelines 

state that ‘‘[w]e do not consider BART 

as a requirement to redesign the source 

when considering available control 

alternatives.’’ 60

We agree with the commenter that the 

NOX BART determination in our 

proposal would reduce NOX emissions, 

yet would do little to reduce SO2 and 

CO2 emissions from the SJGS. SO2

emissions under the RHR are covered by 

the New Mexico submittal, which we 

received on July 5, 2011. We will 

address the adequacy of that submission 

in a future action. As discussed in our 

proposal, we disagree with PNM’s cost 

estimate for installing SCR on the four 

units of the SJGS. Although PNM 

estimated the total cost to be in excess 

of $900 million, we estimated that cost 

to be approximately $250 million. As 

discussed elsewhere in our response to 

comments, in light of information 

provided by commenters, we have 

refined our estimate to be $344,542,604. 

We note that this estimate, being about 

one-third that of PNM’s, will result in 

significantly lower costs being passed 

on to rate payers than what has been 

estimated by PNM. 

G. Comments on Health and Ecosystem 

Benefits, and Other Pollutants 

Comment: Several conservation 

organizations jointly submitted a 

comment letter pointing out that the 

same pollutants that contribute to 

visibility impairment also harm public 

health and have negative ecosystem 

impacts. They note that these same 

pollutants also harm terrestrial and 

aquatic plants and animals, soil health, 

and moving and stationary bodies of 

water by contributing to acid rain, ozone 

formation, and nitrogen deposition. 

Another commenter, a retired 

pediatrician, notes that NOX as a 

precursor to ozone, causes numerous 

respiratory problems and adversely 

affects children in particular; he 

supports our action. Another 

commenter urges us to take into 

consideration the health impacts of 

toxic emissions from the SJGS. Two 

commenters state there are high levels 

of mercury pollution originating from 

the SJGS. A commenter also points out 

that nitrous oxide (N2O) is a greenhouse 

gas (GHG) that contributes to climate 

change. According to the commenter, 

PNM has accumulated many air quality 

violations, and no amount of money is 

worth the poisoning of our air, water, 

and soil. Another commenter points out 

that a recent study of the 2010 health 

impacts of the SJGS estimated 33 

deaths, 50 heart attacks, 600 asthma 

attacks, and over 30 hospital 

admissions, resulting in an estimated 

$255 million in health care costs in 

2010. A commenter also expresses 

concern that if EPA lowers the ozone 

standard in 2011, La Plata County, CO, 

would not be attaining the standard. 

Response: We appreciate the 

commenters’ concerns regarding the 

negative health impacts of emissions 

from the SJGS. We agree that the same 

PM2.5 emissions that cause visibility 

impairment can be inhaled deep into 

lungs, which can cause respiratory 

problems, decreased lung function, 

aggravated asthma, bronchitis, and 

premature death. We also agree that the 

same NOX emissions that cause 

visibility impairment also contribute to 

the formation of ground-level ozone, 

which has been linked with respiratory 

problems, aggravated asthma, and even 

permanent lung damage. We agree that 

these pollutants can have negative 

impacts on plants and ecosystems, 

damaging plants, trees, and other 

vegetation, and reducing forest growth 

and crop yields, which could have a 

negative effect on species diversity in 

ecosystems. Therefore, although our 

action concerns visibility impairment, 

we note the potential for significant 

improvements in human health and the 

ecosystem. 

Although we appreciate the 

commenter’s concern regarding the 

negative health impacts of toxic 

emissions from the SJGS, we note that 

toxic emissions are not considered to be 

visibility impairing pollutants. 

Similarly, Mercury is not a visibility 

impairing pollutant,. N2O—a GHG— 

does not belong to the NOX family, nor 

is it considered a visibility impairing 

pollutant. 

Comment: One commenter states that 

power plants are responsible for 

approximately one-quarter of the NOX

emitted in the U.S. each year, and 

therefore urges us to adopt a plan with 

stricter standards to regulate the toxic 

air emissions from the SJGS to protect 

public health, decrease emergency room 

visits and asthma. According to the 

commenter, the SJGS is one of the 

greatest NOX polluters in the nation, 

contributing to the formation of harmful 

particulate matter, ground level ozone 

smog, and acid rain. 

Response: We appreciate the 

commenters’ concerns regarding the 

NOX emissions from power plants such 

as the SJGS. We agree that these 

emissions are detrimental to human 

health and the environment, with NOX

being a precursor to ground-level ozone 

and also leading to the formation of acid 

rain. Although we appreciate the 

commenter’s encouragement that we 

adopt even stricter standards, after 

considering all the comments we 

received, as we have stated elsewhere in 

this notice, we believe that the 

standards proposed in our proposal 

establish BART and will prevent 

visibility impairment from the SJGS. 

H. Miscellaneous Comments 

Comment: A commenter stated that it 

is appropriate and necessary for us to 

promulgate a FIP that addresses 

interstate transport of air pollutants 

from New Mexico, pointing out that the 

SJGS is located a short distance from 

several state boundaries. They also state 

we should have presented a clearer 

explanation of the events that have 

taken place related to New Mexico’s 

work on the SIP in the 2003–2010 

timeframe. The commenter believes 

including more detail in the background 

section of the proposal about the 


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intermediate actions taken by us and 

NMED in the given timeframe in regards 

to New Mexico’s SIP would have added 

clarity for the public. 

Response: We believe the level of 

detail we included in the ‘‘Background’’ 

section of our proposal is appropriate 

and sufficient to give the public a clear 

picture of the events leading up to our 

proposal. In particular, the subsection 

titled Statutory and Regulatory 

Framework Addressing Interstate 

Transport and Visibility provides 

detailed information to give the public 

a clear picture of what we received from 

New Mexico in terms of the RH SIP and 

the Interstate Transport SIP. 

Comment: A commenter is concerned 

with degradation of visibility in Mesa 

Verde National Park over the last 

decade. The commenter believes that in 

the Interstate Transport SIP we received 

on September 17, 2007, New Mexico’s 

statement that no sources in New 

Mexico impact the protection of 

visibility in neighboring states seems to 

be unsupported by the evidence 

presented by NMED. 

Response: We note that it appears that 

the commenter may have a 

misconception of what NMED 

submitted in terms of the Interstate 

Transport SIP. As explained in our 

proposal, we received a SIP from New 

Mexico to address the interstate 

transport provisions of CAA section 

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

and PM2.5 NAAQS on September 17, 

2007. New Mexico did not state in this 

Interstate Transport SIP that no sources 

in New Mexico impact the protection of 

visibility in neighboring states. Instead, 

New Mexico’s Interstate Transport SIP 

stated that the requirement under 

section 110(a)(2)(D)(i)(II) that the state 

not interfere with the visibility 

programs of other states would be 

addressed by the submittal of a RH SIP 

by December 2007. As we state 

elsewhere in our response to comments 

and in our proposal, because New 

Mexico had not submitted a RH SIP or 

an alternative means of demonstrating 

that emissions from its sources would 

not interfere with the visibility 

programs of other States at the time of 

our proposal, we proposed disapproval 

of the September 17, 2007 SIP, and 

proposed a FIP to fill that gap. We are 

now finalizing our proposed FIP to 

ensure that emissions from New Mexico 

do not interfere with the visibility 

programs of other States. We received 

New Mexico’s RH SIP under section 

51.309 on July 5, 2011, long after 

statutory and regulatory deadlines. We 

will review that submission, and 

address it in a future action. 

Comment: A commenter generally 

agrees with our proposed determination 

that all the air pollution sources in New 

Mexico are achieving the emission 

levels assumed by the WRAP modeling 

except for the SJGS, but would like to 

know what data and modeling supports 

it. 

Response: We based our conclusion 

that all sources in New Mexico are 

achieving the emission levels assumed 

by the WRAP in its modeling except for 

the SJGS by reviewing the WRAP 

photochemical modeling emission 

projections used in the demonstration of 

reasonable progress towards natural 

visibility conditions and comparing 

these emission projections to current 

emission levels from sources in New 

Mexico. 

Comment: A commenter stated that 

there must be balance in the proposals 

and regulations that are presented by 

the federal and state governments. The 

commenter indicated that although this 

is an issue of visibility, he is sure we 

have somehow taken health impacts 

into consideration in formulating our 

proposal. The commenter also 

expressed his belief that our proposal is 

counter-productive and has a better than 

average potential to harm the local and 

state economies. The commenter stated 

that the technology we are proposing is 

costly and seems unnecessary, as PNM 

recently completed a project that put it 

in compliance with all current health 

requirements, and only considers 

visibility in the surrounding national 

parks and wilderness areas while 

ignoring the economic impact to the 

local community. The commenter 

expressed his belief that cost estimates 

from the private sector tend to be more 

accurate than government estimates. 

The commenter stated that our proposal 

calls into question the continued 

viability of the SJGS as an asset to the 

Public Service Company of New 

Mexico. The commenter stated that this 

is not an issue that requires emergency 

action, and suggests allowing 

tomorrow’s technology provide a 

solution to today’s problems. 

Response: We understand the 

commenter’s concern regarding the need 

for balance in the regulations 

promulgated by state and federal 

governments. This decision is based on 

the RH requirements of the CAA. We 

have not relied on any potential health 

impacts in reaching our decision, 

although we note the potential for 

significant improvements in public 

health. The SJGS is one of the largest 

sources of NOX in the western U.S. and 

is within 300 kilometers of 16 Class I 

areas. Finalizing our proposal is 

necessary to satisfy CAA requirements, 

including section 110(a)(2)(D)(i)(II) with 

respect to preventing emissions from 

New Mexico sources from interfering 

with other states’ measures to protect 

visibility. As previously stated, we have 

an obligation to promulgate a FIP to 

address the requirements of section 

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

and a FIP to address the requirements of 

RH. The purposes and requirements of 

these programs are intertwined. As 

such, we consider it appropriate to 

promulgate one FIP that addresses the 

requirements of section 110(a)(2)(D)(i) 

with respect to visibility and the BART 

requirements for NOX for SJGS. 

We disagree with the commenter’s 

belief that our proposal is counterproductive. As presented in our 

proposal, our modeling analysis 

demonstrates significant visibility 

improvement at numerous Class I areas 

from installation of SCR at the SJGS. As 

we discuss elsewhere in our response to 

comments, our estimate of the cost of 

installing SCR is approximately 1⁄3 what 

PNM estimated. Regarding the 

commenter’s belief that the technology 

we proposed seems unnecessary since 

PNM recently completed a project that 

‘‘put it in compliance with all current 

health requirements,’’ we note that as 

part of our visibility impairment and 

BART evaluation, we did consider the 

controls previously installed by PNM as 

a result of its consent decree with the 

Grand Canyon Trust, Sierra Club, and 

NMED on March 10, 2005. These 

controls included the installation of 

low-NOX burners with overfire air ports, 

a neural network system, and a pulse jet 

fabric filter. 

However, as we discuss elsewhere in 

our response to comments, these 

controls were not sufficient to prevent 

New Mexico sources from interfering 

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. The reduction in NOX from 

our NOX BART determination and the 

SO2 emission limits 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. In addition, the RHR requires us 

to examine additional retrofit 

technologies. We have determined that 

SCR is cost effective and results in 

significant visibility improvements at a 

number of Class I areas, over and above 

the existing pollution controls currently 

installed. With regard to the 

commenter’s belief that cost estimates 

from the private sector tend to be more 

accurate than government estimates, we 

note that we take our duty to estimate 

the cost of controls very seriously and 


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52412 Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 

61States 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). 

make every attempt to make a 

thoughtful and well-informed 

determination. With regard to the 

commenter’s belief that this is not an 

issue that requires emergency action 

and that we should allow tomorrow’s 

technology provide a solution to today’s 

problems, we note that Congress added 

the BART requirements to the CAA in 

1977 to focus attention on the visibility 

impacts from sources such as SJGS. We 

therefore believe it is appropriate to take 

action now, and our FIP is necessary to 

satisfy the requirements of CAA section 

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

visibility for the 1997 8-hour ozone 

standard and the 1997 PM2.5 standard, 

and to satisfy certain related RH 

requirements. We also note that as 

described elsewhere in this preamble, 

New Mexico has only recently 

submitted a RH plan that addresses the 

interstate provisions of the CAA with 

respect to visibility, and as also 

explained we cannot review it as part of 

this action. The FIP clocks of both 

statutory requirements have expired and 

we therefore have an obligation to act 

now under the CAA. 

Comment: An owner participant of 

Units 1 and 2 at the SJGS indicates that 

our proposal presents significant 

challenges and risks to its resource 

planning by handicapping its ability to 

cost effectively respond to changing 

conditions. The commenter states that 

uncertainties such as the impact of 

potential future regulations, future fuel 

prices, and customer load growth/ 

decline, have the potential to change the 

economic viability of their generating 

resources. The commenter points out 

that implementation of our proposal 

would require it to make a significant 

capital investment in the plant, the cost 

of which could only be recovered 

through long-term operation of that 

asset. This would likely have the effect 

of ‘‘locking’’ SJGS into the generation 

portfolio for a considerable period of 

time or risk stranding those 

investments. According to the 

commenter, this loss of flexibility would 

hamper its ability to respond to future 

scenarios such as changes in the 

economic viability of coal resources, 

changes in acceptance of coal resources 

by State utility commissions, and 

reduced demand for coal resources. The 

commenter states that this loss of 

flexibility is completely unnecessary 

given that the RH program is intended 

to make gradual reductions in emissions 

over a decades-long period of time. The 

commenter asks us to recognize the 

significant reductions already made at 

SJGS or to defer to the SIP submitted by 

NMED to the Environmental 

Improvement Board. The commenter 

suggests that further reductions could be 

made at the plant, including the 

possible installation of SCR, over 

subsequent planning periods. Such an 

approach would reduce the immediate 

financial burden on the power plant’s 

customers, allow time for greater 

certainty in terms of potential carbon 

limits and customer demand, and retain 

greater flexibility in future resource 

decisions. 

Response: Regarding costs, EPA 

reevaluated projections based on 

comments received to increase them to 

$344,542,604, which is still much less 

than industry projections and cost 

effective. Cost is one of the five factors 

considered in making BART 

determinations.61 Regarding the utility’s 

loss of flexibility, the emission limits we 

select today are the result of a schedule 

in the 1977 Clean Air Act to make 

gradual reductions in emissions over a 

decades-long period of time 

With regard to the commenter’s 

request that we recognize the emissions 

reductions already made at SJGS or to 

defer to the SIP recently that was 

submitted by NMED to the 

Environmental Improvement Board near 

the time of the comment, we note that 

as part of our NOX BART evaluation for 

SJGS, we did consider the controls 

previously installed by PNM as a result 

of its consent decree with the Grand 

Canyon Trust, Sierra Club, and NMED 

on March 10, 2005. However, in making 

the NOX BART determination, we were 

obligated by the RHR to examine 

additional retrofit technologies. EPA 

will give priority to the review of New 

Mexico’s recently submitted Haze SIP; 

however, it was received too late to be 

taken into consideration in this rule 

making. 

Comment: The Navajo Nation 

submitted comments stating that the 

Navajo Nation Environmental Protection 

Agency is concerned that non-air 

quality impacts have not been 

adequately considered in the proposed 

rule. The commenter states that 20% of 

the plant workers at the SJGS and 41% 

of the mine workforce at the San Juan 

Mine are Navajo Nation tribal members. 

The commenter is concerned that we 

have provided no information or 

analyses to explain how the SJGS will 

fund the SCR installation costs within 

the limited timeframe without resorting 

to a reduction-in-force that would 

potentially impact Navajo workers, 

contractors, and subcontractors. 

Response: Because SJGS has not 

proposed to shut down, we do not 

believe that jobs at the facility will be 

threatened. EPA’s decision to lengthen 

the compliance deadline from 3 to 5 

years should also provide some 

increases in local employment during 

that time associated with the 

installation of pollution controls. The 

RHR requires that the costs of 

compliance and the non-air quality 

environmental impacts of compliance 

be considered [40 CFR 

51.308(e)(1)(ii)(A)]. As described in our 

proposal, we found that 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 EPA evaluated 

included the consideration of water 

usage and waste generated from each 

control technology. 

Comment: A commenter argues that 

things like wood burning stoves, wood 

burning fireplaces, and natural 

occurrences such as dust, wind, fires, 

and humidity, impair visibility just as 

much as utilities. The commenter asks 

us to explain how we propose to control 

those events that affect air quality. 

Response: Natural haze factors are 

recognized in the current degree of 

visibility impairment in Class 1 areas. 

The purpose of this decision is to 

significantly decrease impairment from 

the largest man made sources. In 

addition, the emissions resulting from 

wood burning stoves and fireplaces are 

typically included in the emission 

inventory, which is part of the RH SIP 

New Mexico recently submitted to us 

under 40 CFR 51.309. We will review 

the adequacy of this SIP submission in 

a separate future proposal. 

Comment: The commenter asks us to 

explain how we intend to analyze the 

cost benefits to businesses and 

individuals. 

Response: The CAA requires us to 

consider the cost of installing controls 

and the visibility benefits as part of the 

BART analysis, and we have done that. 

The commenter may wish to consult the 

Statutory and Executive Orders Review 

section of this action, which includes 

our determination that the FIP does not 

contain a Federal mandate that may 

result in expenditures that exceed the 

inflation-adjusted Unfunded Mandates 

Reform Act of 1995 (UMRA) threshold 

of $100 million by State, local, or Tribal 


jlentini on DSK4TPTVN1PROD with RULES2
Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 52413 

governments or the private sector in any 

1 year. 

I. Comments in Favor of Our Proposal 

Comment: Overall, we received more 

than 12,000 comment letters in support 

of our rulemaking from members 

representing states, tribes, local 

governments, various organizations and 

concerned citizens in support of this 

rulemaking: These comments were 

received at the Public Hearing in 

Farmington, New Mexico, by Internet, 

and through the mail. Each of these 

commenters was generally in favor of 

our proposed decision for the SJGS. 

These comments include urging us to 

require appropriate retrofit technology 

at the SJGS for emission control, and 

limiting NOX, SO2, sulfuric acid and 

ammonia currently or potentially 

released by the facility. A number of 

representative comments from this 

group are summarized below. The 

Complete Response to Comments for 

NM Regional Haze/Visibility Transport 

FIP document includes the full text 

received by these commenters. 

We received many letters which were 

similar in content and format, and are 

represented by thirteen types of positive 

comment letters in the docket for this 

rulemaking. Each of these comment 

letters supports our proposed decision 

for the San Juan Generation Station in 

New Mexico. More than 7,000 of these 

letters specifically urge us to keep or 

lower our proposed numeric limits on 

nitrogen oxides, ammonia, and sulfuric 

acid pollution in our final decision and 

urge us to require compliance with the 

limits within three years. 

We received a letter from the State of 

Colorado in support of this rulemaking. 

These comments include support for 

our careful evaluation of NOX emission 

control costs for the SJGS, and our 

proposed promulgation of cost effective 

emission control for this facility to 

improve visibility and provide other 

environmental benefits. The State of 

Colorado also encouraged us to work 

closely with the State of New Mexico in 

selecting the most appropriate NOX

control technology. 

We received a letter from the 

Southern Ute Indian Tribe in support of 

this rulemaking. The Tribe’s comments 

include support for our proposed action 

to prevent emissions from New Mexico 

sources from interfering with other 

state’s measures to protect visibility, 

and to implement NOX and SO2

emissions limits at the SJGS to prevent 

interference. In addition, the Tribe 

supports our proposal to regulate 

emissions sources in neighboring areas 

that could undermine the Tribes’ efforts 

to maintain air quality on the 

Reservation. The Tribe is concerned 

about the impacts of emissions from 

SJGS on visibility on the Reservation; 

therefore the Tribe is in favor of 

reducing the regional transport of ozone 

and ozone precursors such as NOX. 

We received two resolutions which 

generally support this rulemaking, one 

from the City of Durango, Colorado, and 

another from the Town of Ignacio 

Colorado. These resolutions include 

support for requiring the use of BART 

at the San Juan Generating Station. 

Another commenter expressed 

support of our proposal. The commenter 

states that for the past 30–40 years, the 

SJGS has had a largely unrestricted use 

of the large common air-shed shared by 

Montezuma County, Colorado and San 

Juan County, New Mexico. During this 

timeframe, the residents of Montezuma 

County and their neighbors have been 

continually exposed to the air pollution 

arising from the SJGS, yet the residents 

of Montezuma County receive no benefit 

from operation of the plant in terms of 

electricity (aside from 40 MW 

purchased from SJGS), tax revenues, 

and community support. 

Another commenter supported all 

aspects of our proposed rule. The 

commenter volunteers at Mesa Verde 

National Park and mentions that many 

park visitors express disappointment 

over the degraded air quality and 

limited vistas from the Park. The 

commenter states that the 2.88 deciview 

of visibility improvement we predicted 

at Mesa Verde National Park with SCR 

installed at SJGS, would be readily 

noticed by both residents and visitors to 

the region. The commenter notes that 

PNM’s Web site claims that SCR is 

‘‘unnecessary’’ and would ‘‘raise 

electricity prices for the SJGS’s two 

million customers,’’ yet PNM offers no 

data or other support for its conclusion. 

The commenter also notes that no 

significant improvement in Four 

Corners RH has been seen since PNM 

completed installation of emission 

controls pursuant to the 2009 consent 

decree. The commenter also states that 

it is legally, socially, and economically 

appropriate for PNM’s customers to pay 

the full costs of the power they 

consume, including the air pollution 

created while generating it. The 

commenter also states that although 

PNM characterizes the SJGS as a ‘‘low 

cost’’ producer of power, it fails to 

acknowledge that a substantial cost of 

its power, in the form of regional air 

quality degradation, is borne by the 

people of the Four Corners region, many 

of whom do not consume SJGS power 

and derive no economic benefit from the 

facility. The commenter believes a 

three-year implementation schedule for 

SCR at the SJGS is both appropriate and 

achievable at a reasonable cost. 

Response: We note that several of the 

specific emissions and timeframe 

limitations supported by these 

commenters in the proposal have been 

modified slightly in this final action 

based on all of the information received 

during the comment period. Please see 

the docket associated with this action 

for additional detail. 

J. Comments Arguing Our Proposal 

Would Hurt the Economy and/or Raise 

Electricity Rates 

Comment: A commenter stated that if 

the FIP is adopted, the owners of the 

SJGS will have three options: 

compliance, plant shutdown, or plant 

modification. The commenter states that 

compliance would result in a capital 

expense not justified by the likely 

results of that investment, and would be 

a terrible, indefensible waste of 

resources. Plant shutdown would result 

in the loss of hundreds of jobs in direct 

plant employment, coal mining, and 

other support and service sectors. The 

commenter also points out that plant 

shutdown would result in the SJGS 

customers losing their investment in the 

plant, which they have paid for through 

rate payment. SJGS customers would 

have to pay for the development of new 

generation facilities and fuel contracts 

or would have to buy power on the open 

market, and they would also be 

responsible for the reclamation of the 

plant site and any coal mine that might 

be abandoned as a result of plant 

closure. The commenter states that plant 

modification would likely take the form 

of conversion from coal-fired to natural 

gas-fired, which would also result in 

loss of jobs, as there would be no need 

for coal. The commenter indicates that 

all three options would result in an 

increase in the cost of electricity to 

customers, which should be avoided or 

eliminated in light of the weakened and 

unstable economic conditions at the 

national, state, and local levels. 

Another part owner of Unit 4 at the 

SJGS, submitted comments stating that 

the impact from imposing its share of 

the costs of installing SCR at the SJGS, 

may require it to raise electric rates, cut 

back on planned clean energy 

investments, or both, all for what appear 

to be insignificant benefits. 

Response: EPA’s evaluation of capital 

expenses by the implementation of the 

FIP shows them to be justified by the 

degree of improvement in visibility in 

relationship to the cost of 

implementation. The FIP calls for NOX

and SO2 emission limits at the SJGS to 

prevent interference with other states’ 

visibility SIPs as well as requiring BART 


jlentini on DSK4TPTVN1PROD with RULES2
52414 Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 

62WildEarth Guardians v. Lisa Jackson, Case No. 

4:09–CV–02453–CW. 

for NOX at this source. BART requires 

that we evaluate (1) cost of compliance, 

(2) the energy and non-air quality 

environmental impacts of compliance, 

(3) any existing pollution control 

technology in use at the source, (4) 

remaining useful life of source, and (5) 

degree of improvement in visibility 

which may reasonably be anticipated to 

result from the use of such technology. 

After careful cost review EPA has 

determined that the significant benefits 

in visibility resulting from the 

implementation of the FIP outweigh the 

increase in costs for the facility. 

K. Comments Arguing Our Proposal 

Would Help the Economy 

Comment: We received several 

comments stating that the proposed FIP 

would help local economies by creating 

new and different jobs in the Region and 

by increasing tourism. In particular, one 

commenter stated reducing visibilitycausing pollutants have far-reaching 

impacts on local economies, human 

health, and ecosystems. The commenter 

stated that decreasing these pollutants 

will benefit all of these important areas 

of concern. This commenter noted that 

tourism is critical to the economy of 

New Mexico and the Four Corners 

region, and made several points: Utah’s 

five Class I areas, all of which are 

national parks, generate a significant 

portion of this sustainable tourism 

economy: in 2008, these areas were 

responsible for 5.7 million recreation 

visits, over $400 million in spending, 

and nearly 9,000 jobs. Parks attract 

businesses and individuals to the local 

area, resulting in economic growth in 

areas near parks that is an average of 1 

percent per year greater than statewide 

rates over the past three decades. 

National parks also generate more than 

four dollars in value to the public for 

every tax dollar invested. Therefore, this 

commenter concluded, improving 

visibility at these national parks 

improves the local economies around 

them. 

This commenter also noted that an 

additional economic incentive behind 

protecting air quality is the necessary 

investment in pollution control 

technologies as they are a job-creating 

mechanism in itself. Each installation 

creates short-term construction jobs as 

well as permanent operations and 

management positions. 

Response: We agree with the 

comments. Although we did not 

consider the potential positive benefits 

to local economies in making our 

decision today, we do expect that 

improved visibility would have a 

positive impact on tourism-dependent 

local economies. Also, retrofitting the 

SJGS with SCR is a large construction 

project that we expect to take 3 to 5 

years to complete. This project will 

require well-paid, skilled labor which 

can potentially be drawn from the local 

area, which would seem to benefit the 

economy. 

L. Comments Requesting an Extension 

to the Public Comment Period 

Comment: We received comments 

requesting that the comment period be 

extended, with most requesting an 

additional 60 days. We also received 

comments requesting additional public 

hearings. 

Response: Originally the comment 

period for our proposal was due to close 

on March 7, 2011. In response to 

requests we extended the public 

comment period to April 4, 2011. In 

doing so, we took into consideration 

how an extension might affect our 

ability to consider comments received 

on the proposed action and still comply 

with the terms of a consent decree we 

have with WildEarth Guardians.62 We 

do note that our February 17, 2011, 

public hearing in Farmington, New 

Mexico was well attended and provided 

an opportunity for people to comment 

on our proposal. 

M. Comments Requesting We Defer 

Action in Favor of a New Mexico SIP 

Submittal 

Comment: Various commenters have 

stated that the NMED should take the 

lead in implementing the RH 

requirements of the CAA based on the 

fundamental principle that the CAA and 

the RHR emphasize that states, not EPA, 

are to take the lead in implementing the 

RH program, and we should wait taking 

action until NMED submits to the 

Agency their revised RH SIP and adopt 

such submittal instead of promulgating 

a FIP. 

Response: Congress crafted the CAA 

to provide for States to take the lead for 

implementing plans, but balanced that 

decision by requiring EPA to approve 

the plans or prescribe a federal plan 

should the State plan be inadequate. 

Our action today is consistent with the 

statute. As explained in our proposal, 

we received a SIP from New Mexico to 

address the interstate transport 

provisions of CAA section 

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

and PM2.5 NAAQS on September 17, 

2007. New Mexico’s September 17, 2007 

submittal addressed the requirement 

that the state not interfere with the 

visibility programs of other states by 

stating that it would submit a RH SIP by 

December 2007. 

On January 15, 2009, EPA 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 

requires BART for stationary source 

emissions of NOX and PM under either 

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

notice initiated a 2-year deadline, 

referred to as the ‘‘FIP clock,’’ for New 

Mexico to submit a SIP or for EPA to 

issue a FIP. The FIP would provide the 

basic program requirements for each 

State that has not completed an 

approved plan of their own by January 

15, 2011. The CAA requires EPA to 

promulgate a FIP if a State fails to make 

a required SIP submittal or if we find 

that the State’s submittal is incomplete, 

does not meet the minimum criteria 

established in the CAA or we 

disapprove in whole or in part the SIP 

submission. CAA section 110(c)(1). 

In addition, WildEarth Guardians 

sued EPA alleging that we failed to 

perform the non-discretionary duty to 

either approve a SIP or promulgate a FIP 

for New Mexico, among other States, to 

satisfy the requirements of CAA section 

110(a)(2)(D)(i) with regard to the 1997 

National Ambient Air Quality Standards 

for 8-hour ozone and fine particulate 

matter. We have entered into a consent 

decree with WildEarth Guardians to 

resolve this matter. 

This consent decree specifically 

requires us—no later than August 5, 

2011—to sign a notice either approving 

a SIP, promulgating a FIP, or approving 

a SIP in part with promulgation of a 

partial FIP, for New Mexico to meet the 

requirement of 42 U.S.C. 

7410(a)(2)(D)(i)(II) regarding interfering 

with measures in other states related to 

protection of visibility. As required by 

the consent decree, since New Mexico 

did not submit a complete proposed SIP 

to address the visibility requirement by 

May 10, 2010, then by November 10, 

2010, EPA was required to propose one 

of three actions: A FIP; approval of a SIP 

(if one has been submitted in the 

interim); or partial promulgation of a 


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Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 52415 

FIP and partial approval of a SIP. In the 

absence of a SIP, EPA proposed a FIP on 

January 5, 2011. We received the New 

Mexico submittal on July 5, 2011,after 

the close of the record for the proposed 

FIP EPA will give priority to the review 

of New Mexico’s SIP but we cannot 

consider it and meet the consent decree 

deadline. 

N. Comments Generally Against Our 

Proposal 

Comment: Various commenters 

generally stated they do not support the 

proposed rulemaking. Their reasons 

included: It will affect the town’s 

economy, affect the coal power plant 

industry, electricity costs will increase, 

they have no direct health problems 

from actual emissions, direct and 

indirect jobs/businesses would be 

affected, current air pollution control 

equipment meet EPA and health 

standards. Others commented that our 

decision is arbitrary as no other similar 

facilities have the same requirements 

imposed by the FIP and that there will 

be no benefit to the community. One 

commenter argues that SJGS already 

meets the visibility standards required 

by the CAA. 

Response: While we appreciate the 

effort and time of the commenters, the 

comments did not include 

documentation, rationale, or data for 

EPA to respond beyond our responses 

provided elsewhere. 

O. Comments on Legal Issues 

1. EPA’s Authority 

Comment: Various commenters 

argued that combining Interstate 

Transport and RH BART requirements 

in the proposed action exceeds our 

authority and does not satisfy the 

regulatory requirements of each 

program, and each program has different 

requirements and purposes. 

Response: We do not agree that it 

exceeds our authority to combine action 

on RH BART requirements as part of our 

action on the required State submittal to 

meet section 110(a)(2)(D) of the CAA. 

EPA has two separate sources of 

authority and obligations to take this 

action, i.e., a statutory obligation to 

promulgate a FIP to meet the 

requirements of section 

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

obligation to promulgate a FIP to meet 

RH program requirements of the CAA. 

Nothing in the CAA precludes EPA from 

addressing both requirements 

simultaneously, and indeed, to address 

both in the same action is rational to 

ensure the most efficient use of 

resources by both the Agency and the 

affected source. The SJGS is subject to 

both provisions of the CAA, and both 

provisions concern emissions of NOX

(among other pollutants). To separate 

our actions could potentially lead to the 

same source needing to install two 

successive levels of control measures, 

the first in order to meet the 

requirements of section 110(a)(2)(D)(i), 

and then the second in order to meet the 

requirements of the RH program. 

The CAA requires each state to 

develop a SIP that provides for the 

implementation, maintenance, and 

enforcement of the NAAQS. CAA 

section 110(a)(1). The statute explicitly 

requires that each state’s SIP shall 

include, among other things, adequate 

provisions prohibiting any source from 

emitting any air pollutants in amounts 

which will interfere with measures 

required to be included in the 

applicable implementation plan for any 

other State to protect visibility. CAA 

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

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 notice included a finding 

that New Mexico and other states had 

failed to submit SIPs to address any of 

the four prongs of section 

110(a)(2)(D)(i), including the provisions 

relating to interstate transport of air 

pollution affecting visibility, and started 

a 2-year clock for us to promulgate a 

FIP, unless a State made a submission 

to meet the requirements of section 

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

submission. CAA section 110(c)(1). That 

two year period has expired. 

The CAA also requires each state to 

develop a SIP to protect visibility. CAA 

section 169. 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. In that notice we 

found that New Mexico and other states 

had failed to submit complete SIPs for 

improving visibility in the nation’s 

national parks and wilderness areas by 

the required date of December 17, 2007. 

Specifically, 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. In 

addition, we also found that New 

Mexico had failed to submit 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). This finding of failure to 

submit started a 2-year clock for us to 

promulgate a FIP, unless the State made 

a RH SIP submission and we approved 

it. That two year period has also 

expired. 

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 that submission, 

the state indicated that it intended to 

meet the requirements of section 

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

by submission of a timely RH SIP. Those 

RH SIPs were due no later than 

December 17, 2007. 

As of the time of our proposal for this 

action on January 5, 2011, the state had 

not make the RH SIP submission as 

represented in its section 110(a)(2)(D) 

submission, and had not make a RH SIP 

submission or alternate section 

110(a)(2)(D) submission indicating that 

the state intended to meet visibility 

prong by any other means. 

We received a RH SIP submittal from 

the state on July 5, 2011. Unfortunately, 

due to the timing of that submittal, we 

cannot evaluate it as part of this action. 

We note that this RH SIP submittal 

arrived approximately 31⁄2 years past the 

due date of December 17, 2007, and well 

past January 15, 2011, the date by which 

we were obligated either to approve a 

RH SIP submission or to promulgate a 

RH FIP, as a result of the 2009 finding 

of failure to submit the RH SIP. 

Moreover, the July 5, 2011, submission 

also occurred more than four years after 

the date by which we were obligated 

either to approve a SIP submission or to 

promulgate a FIP to address the state’s 

failure to submit a submission for 

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

We are under a consent decree 

deadline with WildEarth Guardians that 

requires the Agency to take action by 

August 5, 2011, either to approve the 

New Mexico section 110(a)(2)(D) SIP, or 

to promulgate a FIP, to address the 

110(a)(2)(D)(i)(II) visibility prong. 

Because of the lateness of the July 5, 

2011 submission, it is not possible to 

review and potentially fully approve the 

July 5, 2011, SIP submission by 

proposing a rulemaking and 

promulgating a final action by August 5, 

2011, as required by the consent decree. 

The CAA requires us to promulgate a 

FIP if a State fails to make a required 

SIP submittal or if we find that the 

State’s submittal is incomplete, does not 

meet the minimum criteria established 

in the CAA or we disapprove in whole 

or in part the SIP submission. CAA 

section 110(c)(1). As previously 

discussed, we have made findings 

related to the New Mexico SIP 

submission needed to address interstate 

transport and the requirement that 

emissions from New Mexico sources do 


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52416 Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 

63See, ‘‘Guidance for State Implementation Plan 

(SIP) Submissions 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,’’ from William T. Harnett, 

Director Air Quality Policy Division, OAQPS, to 

Regional Air Division Director, Regions I–X, dated 

August 15, 2006 (the ‘‘2006 Guidance’’). 

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. 

Therefore, as New Mexico failed to 

submit an approvable SIP that addresses 

the interstate provisions of the CAA 

with respect to visibility, and has made 

a very late RH SIP submission giving us 

no time to complete the regulatory 

process necessary to evaluate that 

submission in light of the deadlines 

imposed by the above-mentioned 

consent decree, we have the statutory 

authority and the obligation to 

promulgate a FIP that meets one or both 

requirements. 

In addition, we think that it is 

appropriate to take action on the 

visibility requirements of section 

110(a)(2)(D)(i)(II) and RH program 

requirements simultaneously in these 

circumstances because the purposes and 

requirements of the interstate transport 

provisions of the CAA with respect to 

visibility and the RH program are 

intertwined. The requirements of CAA 

section 110(a)(2)(D)(i)(II) explicitly 

provide that states must have SIPs with 

adequate provisions to prevent 

inference with the efforts of other states 

to protect visibility, which includes the 

protections contemplated by the RH 

program. This section of the CAA 

requires each SIP ‘‘to include adequate 

provisions prohibiting any source from 

emitting any air pollutants in amounts 

which will interfere with measures 

required to be included in the 

applicable implementation plan for any 

other State * * * to protect visibility.’’ 

These required SIP measures to protect 

visibility are set forth in sections 169A 

& 169B of the CAA and EPA’s 

implementing regulations for the RH 

program. 

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

explicitly define what is required in 

SIPs to prevent the prohibited impact on 

visibility in other states. However, 

because the RH program requires 

measures that must be included in SIPs 

specifically to protect visibility, EPA’s 

2006 Guidance 63 recommended that RH 

SIP submissions meeting the 

requirements of the visibility program 

could satisfy the requirements of CAA 

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

visibility. 

Subsequently, when some states did 

not make the RH SIP submission, in 

whole or in part, or did not make an 

approvable RH SIP submission, we have 

evaluated whether states could comply 

with section 110(a)(2)(D)(i)(II) by other 

means. Thus, we have elsewhere 

determined that states may also be able 

to satisfy the requirements of CAA 

section 110(a)(2)(D)(i)(II) with 

something less than an approved RH 

SIP, see e.g. Colorado (76 FR 22036 

(April 20, 2011)) and Idaho (76 FR 

36329 (June 22, 2011)). In other words, 

an approved RH SIP is not the only 

possible means to satisfy the 

requirements of CAA section 

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

visibility; however, such a SIP could be 

sufficient. Given this reasoning, we do 

not agree with commenters’ contentions 

that the two programs have completely 

different requirements and purposes 

and that it is unreasonable for EPA to 

seek to address these issues in the same 

action. 

Comment: Various commenters have 

stated that we proposed to act on an 

interstate transport SIP requirement, 

while borrowing portions of the RH SIP 

requirements, and that such partial 

implementation of programs is 

inappropriate and conflicts with the 

structure and purpose of the CAA. 

Response: We disagree with the 

premise of the commenters that we 

cannot address more than one statutory 

requirement in the same notice and 

comment rulemaking. See response to 

comments, above, regarding our general 

authority and obligation to act on 

section 110(a)(2)(D)(i)(II) and RH SIP 

requirements. We also specifically 

disagree that acting on portions of the 

RH SIP requirements in this action is 

inappropriate and conflicts with the 

structure and purpose of the CAA. We 

have authority to act on submissions, or 

portions of submissions, as appropriate 

to meet the requirements of the CAA, in 

accordance with section 110(k)(3). In 

this instance, we have determined that 

it is appropriate to take action 

addressing the NOX BART requirements 

for an individual source, and thereby to 

meet a portion of our outstanding 

statutory FIP obligation for the RH 

program, at the same time as acting on 

the section 110(a)(2)(D)(i)(II) SIP 

submission with respect to the visibility 

prong to meet that statutory FIP 

obligation. 

We note that we have previously 

acted on other portions of the section 

110(a)(2)(D)(i) SIP submission from the 

state. 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). Were it in fact 

‘‘inappropriate’’ to act on portions of 

SIP submissions, or were it contrary to 

the structure and purpose of the CAA to 

do so, as the commenters argue, we 

would not have taken such prior actions 

on portions of the state’s section 

110(a)(2)(D)(i) submission. Moreover, no 

one objected to those actions on these 

grounds. 

We also contend that promulgating 

FIPs to address specific CAA 

requirements is consistent with the 

purposes of the statute. One of the 

primary goals of the CAA is to protect 

and enhance the quality of the Nation’s 

air resources so as to promote the public 

health and welfare. CAA section 

101(b)(1). Failing to submit an 

approvable SIP submission, as required 

by section 110 of CAA, is contrary to the 

purposes and goals of the CAA. The 

CAA requires us to promulgate a FIP if 

a State has failed to make a required 

submission or finds that a plan does not 

satisfy the minimum established 

criteria, or disapproves a SIP 

submission in whole or in part. CAA 

section 110(c)(1). 

In this action, we are disapproving a 

portion of 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. 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) with respect to visibility 

by submission of a timely RH SIP. As 

previously explained above, we 

received a RH SIP submission from the 

state on July 5, 2011. Because of the 

lateness of the submission, and in light 

of our obligations under the WildEarth 

Guardians consent decree to have 

completed rulemaking on the visibility 

prong of Section 110(a)(2)(D)(i), it is not 

possible to review such SIP submission, 

propose a rulemaking, and promulgate a 

final action prior to the August 5, 2011 

deadline. 

Therefore, as previously stated, we 

have both a statutory obligation to 

promulgate a FIP to address the 

requirements of section 110(a)(2)(D)(i) 

with respect to visibility and a statutory 

obligation to promulgate a FIP to 

address the requirements of RH. As also 

previously stated, the purposes and 


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requirements of these programs are 

intertwined. As such, we consider it 

appropriate to promulgate one FIP that 

addresses both the requirements of 

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

visibility and the BART requirements 

for NOX from SJGS. Although there are 

additional RH SIP requirements to be 

addressed, and we intend to address 

these requirements in the near future, 

there is no requirement in the CAA that 

we take action to address a state’s 

failure to submit an approvable RH SIP 

in only one action. 

Comment: Some commenters argued 

that the proposed FIP is too all 

encompassing, exceeds the authority 

vested in EPA under Section 110 of the 

CAA because it provides too stringent a 

control for attaining visibility standards, 

and will have broader impact than the 

purpose of the CAA to not interfere with 

neighboring state implementation plans. 

Response: In general, for the reasons 

we have outlined elsewhere in our 

responses to comments, we disagree that 

our FIP is too all encompassing or 

exceeds our authority under section 

110(a)(2)(D)(i) of the CAA. Under that 

provision, we may not approve the SIP 

submission from the state unless the SIP 

contains provisions adequate to prohibit 

emissions from sources in that state 

from interfering with measures required 

to protect visibility in other states. As 

explained in this action, we have 

determined that emissions sources in 

New Mexico meet this requirement, 

except for the SJGS. For this source, we 

have determined that additional and 

federally enforceable controls are 

required in order to meet the NOX

emissions used in the WRAP 

photochemical modeling and that 

federally enforceable emission limits are 

required in order to meet the SO2

emissions used in the WRAP 

photochemical modeling, as part of this 

action in order to be in compliance with 

section 110(a)(2)(D)(i). Our action is also 

based in part on our authority to address 

the NOX BART requirements for the 

SJGS. To meet this separate 

requirement, we have determined that 

specific NOX controls are required for 

the SJGS. 

Comment: Various commenters 

argued that EPA failed to present ‘‘a 

coherent or defensible justification’’ for 

its interpretation of section 

110(a)(2)(D)(i)(II) in the proposal, and 

that EPA failed to explain adequately its 

interpretation of CAA section 

110(a)(2)(D)(i)(II) and the relationship 

between that provision, as interpreted 

by the Agency, and CAA sections 169A 

and 169B. In addition, the commenter 

asserted that EPA has no basis to 

disapprove the state’s section 

110(a)(2)(D) submission with respect to 

the visibility prong, because the state’s 

submission was consistent with EPA’s 

2006 guidance to states for these SIP 

submission. 

Response: We disagree with these 

assertions. First, in the proposal we 

explained our views as to the proper 

interpretation of section 

110(a)(2)(D)(i)(II). We explained that 

section 110(a)(2)(D(i)(II) requires states 

‘‘to have a SIP, or submit a SIP revision, 

containing provisions ‘prohibiting any 

source or other type of emissions 

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. 76 FR 493 (January 5, 2011). 

We explicitly stated that ‘‘[b]ecause 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.’’ Id. 

In the proposal, we expressed our 

view 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’’ Id. 

at 496. We clearly stated that the statute 

is thus ambiguous and that the Agency 

must interpret that provision in this 

action. Id. We are explaining our 

reading of the ambiguity in the statute 

in this notice and comment rulemaking. 

Thereafter, we articulated in detail the 

underlying premise for our 2006 

guidance, and the recommendations 

that states address this requirement 

through submission of the RH SIP. We 

specifically explained the basis for our 

belief that the development of those 

SIPs would provide an appropriate 

forum in which states would have 

evaluated the need for emission controls 

to protect visibility, and in particular 

would have considered emissions from 

sources in other states and their degree 

of control as part of developing their 

respective programs to protect visibility. 

The proposal articulated our basis for 

proposing to interpret the requirement 

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

the state’s SIP must contain at least 

those emission reductions that other 

states would have relied upon from New 

Mexico sources in the development of 

their reasonable progress goals in their 

respective visibility programs. 

Moreover, our proposal articulated that 

evaluation of the analysis conducted by 

the WRAP is one means of gauging 

whether New Mexico has adequately 

controlled its sources for this purpose. 

We also disagree with the assertion 

that we have failed to explain 

adequately our interpretation of the 

visibility prong of section 110(a)(2)(D)(i) 

in light of the requirements of section 

169A and 169B of the Act. As explained 

in our proposed action, the CAA 

establishes a visibility protection 

program that sets forth ‘‘as a national 

goal the prevention of any future, and 

the remedying of any existing, 

impairment of visibility in mandatory 

class I Federal areas which impairment 

results from manmade air pollution.’’ 

CAA section 169A(a)(1). In section 

169A(a)(1) 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 which 

impairment results from manmade air 

pollution.’’ 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.’’ 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 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). 

We disagree with the argument that 

because section 169A and B create a 

specific program for protection of 

visibility, that compels the conclusion 

that section 110(a)(2)(D)(i)(I) could not 


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52418 Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 

64See, e.g., ‘‘Finding of Significant Contribution 

and Rulemaking for Certain States in the Ozone 

Transport Assessment Group Region for Purposes of 

Reducing Regional Transport of Ozone; Final Rule,’’ 

63 FR 57356, October 27, 1998, (the NOx SIP Call). 

65Subsequent to the proposal for this action, and 

subsequent to the commenter’s comments, the state 

did make a RH SIP submission on July 5, 2011, one 

month before we have to finalize rulemaking either 

by promulgating a FIP or reviewing, proposing a 

rulemaking and promulgating a final action fully 

approving the SIP, as required by the August 5, 

2011 consent decree deadline. Nevertheless, the 

commenter was clearly in error given that there was 

no submission purporting to meet the requirements 

of the RH program as of the time of its comments. 

have any substantive bearing on this 

issue. Such an argument is at odds with 

the clear provisions of the statute, and 

with the structure of the CAA. Section 

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

that SIPs shall include adequate 

provisions ‘‘prohibiting * * * any 

source * * * 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 * * * to 

protect visibility.’’ (Emphasis added). 

Because sections 169A and 169B 

establish the national goal for visibility 

protection, including RH issues, we 

infer that when Congress included 

protection of required visibility 

programs in other states as part of 

section 110(a)(2)(D)(i), it was a 

conscious reference to the sections in 

the CAA that address that matter. 

Indeed, in section 110(a)(2)(D)(i)(II), 

Congress directed us to prevent 

interference with the ‘‘measures 

required to be included in the 

applicable implementation plan for any 

other State under part C of this chapter 

* * * to protect visibility,’’ and the RH 

program is unequivocally among those 

required measures to protect visibility. 

Thus, it is reasonable for EPA to 

evaluate whether the SIP of a given state 

prohibits emissions, consistent with 

what other states will have developed 

their own visibility programs in reliance 

upon. 

It is illogical to conclude that 

Congress would have explicitly directed 

us to assure that state SIPs contain 

provisions to protect visibility programs 

in other states, but that we not have the 

authority to require such provisions as 

part of a section 110(a)(2)(D)(i)(II) SIP 

submission, or if necessary to supply 

them as part of a FIP. Such an argument 

is also clearly inconsistent with the 

other prongs of section 110(a)(2)(D)(i). 

The mere existence of other statutory 

programs to provide for attainment and 

maintenance of the NAAQS required in 

part D of the Act, does not negate the 

requirement that states also meet the 

requirement of the ‘‘significant 

contribution to nonattainment’’ and 

‘‘interference with maintenance’’ prongs 

of section 110(a)(2)(D)(i)(I), and the 

authority of EPA to require substantive 

provisions in the SIP, or to promulgate 

a FIP to provide them, as may be 

necessary. We have exercised such 

authority and issued SIP calls or 

promulgated FIPs to assure that state 

SIPs meet the requirements of section 

110(a)(2)(D)(i).64 Because of the impacts 

on visibility from the interstate 

transport of pollutants, we thus 

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 of the 

RH program set to protect Class I areas 

in other states of the RH program. 

Finally, we disagree with the 

commenter’s views concerning the 

state’s September 2007, submission 

complying with the Agency’s 2006 

guidance, and even if it had complied 

with that guidance, the purported legal 

significance of that fact for purposes of 

this action. As the commenters 

themselves conceded, the state’s 2007 

submission stated that it would make a 

timely RH SIP submission by December 

of 2007 as its intended means of 

meeting the requirements of section 

110(a)(2)(D)(i)(II) for visibility, but due 

to intervening events the state did not 

in fact do so prior to our proposed 

action. Contrary to the commenter’s 

views, that submission was not factually 

consistent with the recommendations of 

the guidance.65

More importantly, however, our 2006 

guidance reflected our 

recommendations for how states could 

potentially meet the section 

110(a)(2)(D)(i)(II) requirement at that 

point in time. As of August 2006, we 

stated our belief that it was ‘‘currently’’ 

premature for states to make a more 

substantive SIP submission for this 

element, because of the anticipated 

imminent RH SIP submissions. We 

explicitly stated that ‘‘at this point in 

time’’ in August of 2006, it was not 

possible to assess whether emissions 

from sources in the state would interfere 

with measures in the SIPs of other 

states. As subsequent events have 

demonstrated, we were mistaken as to 

the assumption that all states would 

submit RH SIPs in December of 2007 

and mistaken as to the assumption that 

all such submissions would meet 

applicable RH program requirements 

and therefore be approved shortly 

thereafter. Thus the premise of the 2006 

Guidance that it would be appropriate 

to await submission and approval of 

such RH SIPs before evaluating SIPs for 

compliance with section 

110(a)(2)(D)(i)(II) was in error. Our 2006 

Guidance was clearly intended to make 

recommendations that were relevant at 

that point in time, and subsequent 

events have rendered it inappropriate in 

this specific action. 

In short, we must act upon the state’s 

submission in light of the actual facts, 

and in light of the statutory 

requirements of section 110(a)(2)(D)(i). 

Whereas our prior recommendations 

were prospectively anticipating the 

submission of the RH SIP as a means of 

the state imposing the controls 

necessary on New Mexico sources 

necessary to prevent interference with 

the required visibility programs of other 

states, those recommendations are 

inappropriate at this juncture. In order 

to evaluate whether the state’s SIP 

currently in fact contains provisions 

sufficient to prevent the prohibited 

impacts on the required programs of 

other states, we are obligated to consider 

the current circumstances and 

investigate the level of controls at New 

Mexico sources and whether those 

controls are or are not sufficient to 

prevent such impacts. 

We similarly disagree with the 

commenters’ argument that it is still 

‘‘premature’’ to evaluate the compliance 

of the state’s SIP at this time, and that 

we ‘‘must await the date on which 

regional haze SIPs have been submitted 

and approved.’’ First, this approach is 

illogical, as it fails to address what 

would happen if a state were never to 

submit the required RH SIP, or were 

never to submit a RH SIP that was 

approvable. On its face, the 

commenter’s argument is simply 

inconsistent with the objectives of the 

statute to protect visibility programs in 

other states if a state never submits an 

approvable RH SIP. Second, this 

approach is flatly inconsistent with the 

timing requirements of section 110(a)(1) 

which specifies that SIP submissions to 

address section 110(a)(2)(D)(i), 

including the visibility prong of that 

section, must be made within three 

years after the promulgation of a new or 

revised NAAQS. We acknowledge that 

there have been delays with both RH 

SIP submissions by states and our 

actions on those RH SIP submissions, 

but that fact does not support a reading 

of the statute that overrides the timing 

requirements of the statute. We believe 

that there are means available now to 

evaluate whether a state’s section 

110(a)(2)(d)(i)(II) SIP submission meets 

the substantive requirement that it 

contain provisions to prohibit 

interference with the visibility programs 


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of other states, and therefore that further 

delay, until all RH SIPs are submitted 

and fully approved, is unwarranted and 

inconsistent with the key objective to 

protect visibility. 

Section 110(a)(2)(d)(i)(II) directs EPA 

to evaluate the SIP of a state for 

adequate controls on emissions from the 

state to prevent interference with 

measures ‘‘required to be included in 

the applicable state implementation 

plan’’ of other states. Thus, this 

evaluation is supposed to consider what 

other states should have in their SIPs as 

of this point in time, and is not limited 

by the fact that other states may or may 

not have made the required RH SIP 

submission, nor by the fact that we may 

or may not have approved those RH SIP 

submissions at this point in time. 

Instead, we must evaluate the state’s 

section 110(a)(2)(D)(i)(II) submission in 

light of the programs that states are 

required to have, and that clearly 

includes the RH program required in 

other states. As discussed above, we 

believe that one means to evaluate this 

issue is to determine whether the level 

of controls in the SIP are consistent with 

the expectations for controls at New 

Mexico sources relied upon by other 

states in the development of their own 

respective visibility programs and 

consistent with the needs for emissions 

reductions that we ourselves conclude 

are needed for purposes of the RH 

program. 

Comment: The proposed FIP requires 

exceedingly stringent and expensive 

compliance obligations that are not 

adequately legally supported because 

the proposed FIP fails to adequately 

satisfy the interstate transport 

provisions of Section 110(a)(2)(D)(i) of 

the CAA or the provisions of the RHR. 

Response: We disagree that the FIP is 

not legally supported. The FIP satisfies 

provisions in both section 

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

interstate transport of pollutants 

affecting visibility in other states and for 

the NOX BART determination for the 

SJGS, the RHR. 

We find that the emissions from the 

SJGS in New Mexico are interfering 

with the other states’ required measures 

to protect visibility. Therefore, we are 

imposing through the FIP, specific 

emission limits upon the SJGS to 

prevent such interference. We are 

imposing an SO2 limit and a NOX limit. 

To provide greater certainty to the SJGS 

that controls needed to prevent 

interference with other states’ visibility 

programs, as well as the controls needed 

to meet the RHR’s BART requirements, 

do not conflict with each other and end 

up imposing unnecessary greater costs 

upon the SJGS, we are imposing a BART 

NOX emission limit that meets both 

requirements at this time, rather than 

postponing action on this RH SIP 

requirement. We are only determining 

that the SJGS is subject to BART and 

promulgating the NOX BART FIP for the 

SJGS. We are not addressing whether 

New Mexico has met the requirements 

of the RHR for any other sources; we are 

not addressing whether the SJGS is 

meeting the RH BART requirements for 

any other pollutants; and we will 

address those requirements in later 

actions. 

We have the specific authority to 

promulgate a FIP imposing a NOX BART 

emission limitation upon the SJGS 

because 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 section 110(c)(1). 

The FIP obligation imposed upon us 

became effective on February 15, 2011. 

Part of that FIP obligation includes 

making a NOX BART determination for 

the SJGS. To prevent a possible conflict 

between a NOX visibility transport 

emission limitation FIP for the SJGS and 

the NOX RH BART emission limitation 

FIP for the SJGS, we chose to 

promulgate now, rather than later, the 

NOX RH BART determination for the 

SJGS. We are combining the 

requirements of section 

110(a)(2)(D)(i)(II) for NOX with a NOX

BART evaluation (40 CFR 51.308) to be 

efficient and provide greater certainty to 

the source as to the appropriate NOX

controls needed to meet those two 

separate but related requirements. 

This FIP also will impose a federally 

enforceable limit on the emissions of 

SO2 from the SJGS based upon the 

WRAP determination of each member 

state’s contribution to visibility 

impairment of SO2 emissions, of which 

New Mexico is a member. The SJGS’s 

existing SO2 permit does not provide 

the necessary emission limits and 

enforceable mechanisms to ensure the 

SO2 emissions used in the WRAP 

photochemical modeling for the SJGS 

units will be met. Therefore, we 

assumed the SO2 emission limit used in 

the WRAP modeling and, by this action, 

make it enforceable. This is necessary to 

ensure that 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. 

Comment: One commenter argued 

that EPA took too narrow an 

interpretation of the term ‘‘interfere’’ in 

the visibility protection context of 

Section 110(a)(2)(D)(i)(II) for New 

Mexico, and that EPA should account 

for a broader range of causes of visibility 

impairment when considering 

regulating interference with other states’ 

visibility. According to the commenter, 

EPA’s action should consider future 

growth in emissions from area sources 

such as oil and gas development as part 

of evaluating interference with the 

visibility programs required in other 

states’ SIPs because the proposed New 

Mexico RH SIP already reduces NOX

emissions sufficiently. The commenter 

also argued that pollutants other than 

NOX cause interference with other 

states’ visibility programs and should be 

considered instead of reducing NOX

emissions under BART because the 

commenter believes NOX emissions 

contribute a minor portion to overall 

visibility impairment. 

Response: We disagree with the 

assertion that we took too narrow a view 

of the term ‘‘interfere’’ in Section 

110(a)(2)(D)(i)(II). In the FIP proposed 

and finalized in this action, we are 

concluding that the New Mexico SIP 

contains adequate provisions to prevent 

such impacts on the visibility programs 

of other states, except for the emissions 

from the SJGS. By promulgating a FIP to 

impose NOX and SO2 emission limits 

necessary at the SJGS to prevent such 

interference, as well as to meet the 

requirement for BART for NOX for this 

same source, EPA is addressing the 

requirements of the statute. In reaching 

this conclusion, we considered the term 

‘‘interfere’’ based upon the facts, 

information, and data available to the 

Agency at this time. 

As we discuss in our proposal, we 

relied on WRAP modeling to determine 

the appropriate emission limits for 

sources in New Mexico in order to 

determine if New Mexico’s emissions 

were interfering with other state 

visibility SIPs. The states in the West, 

including New Mexico, 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. 

Western states are relying on the WRAP 

assumed reduction in emissions levels 

modeled for sources in New Mexico 

including the SJGS in order to meet 

their RH reasonable progress goals. All 

of the sources except for SJGS met the 

WRAP assumed reduction in emissions 

levels modeled for New Mexico’s 

assigned contribution to the region’s 

visibility impairment of Federal class I 

areas. Thus, we proposed a FIP to 

prevent emissions from New Mexico 

sources from interfering with other 


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52420 Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 

66 70 FR 39104, 39120. 

states’ measures to protect visibility, 

and to implement NOX and SO2

emission limits necessary at one source, 

the SJGS, to prevent such interference, 

as well as BART for NOX for this source. 

We determined that enacting a NOX

BART determination for SJGS was 

necessary because the WRAP analyses 

showed that NOX emissions in general 

and SJGS NOX emissions, specifically, 

contribute significantly to haze in the 

West. SJGS is by far the largest source 

of NOX emissions in NM. Our FIP 

requires substantial reductions in NOX

emissions from this source. We agree 

that oil and gas development can result 

in emissions that could have an impact 

on visibility due to increases in NOX

emissions. However, we are basing our 

evaluation of the potential impacts of 

emissions from New Mexico sources on 

the WRAP analysis, and consideration 

of the sources that other states would 

have assumed that New Mexico 

intended to control as part of that 

modeling. The state’s initial submission 

for section 110(a)(2)(D)(i) indicated that 

the state intended to meet its obligations 

with respect to the visibility prong by 

means of the RH SIP. Therefore, we 

have examined the issue in light of what 

other states would have assumed such 

a SIP would achieve. Moreover, even if 

the impacts from the oil and gas sector 

were significant, this fact would not 

justify a decision to not act on the BART 

requirements for NOX for the SJGS, 

because NOX emissions from SJGS are a 

significant source of NOX emissions that 

interfere with other state’s required 

visibility programs. In addition, based 

on the facts and information currently 

available, we believe the most effective 

means of ensuring that emissions from 

New Mexico do not interfere with other 

states’ visibility programs is to require 

further and federally enforceable NOX

reductions and federally enforceable 

SO2 limits at SJGS. 

We also specifically disagree with the 

commenter’s statement that NOX

emissions contribute only a minor 

portion to overall visibility impairment. 

As we noted in our proposal, our 

modeling indicates that the visibility 

impairment due to the SJGS’s emissions 

is primarily dominated by nitrate 

particulates. As our NOX BART 

modeling demonstrates, reducing NOX

emissions from the SJGS will result in 

a 21.69 dv, cumulative improvement, 

across 16 Class I areas. As the RHR 

states, ‘‘States should consider a 1.0 

deciview change or more from an 

individual source to ‘‘cause’’ visibility 

impairment, and a change of 0.5 

deciviews to ‘‘contribute’’ to 

impairment.’’ 66 Therefore, we do not 

view a cumulative visibility impairment 

of 21.69 dv as an insignificant 

contribution. The commenter suggests 

we consider future growth in emissions 

from area sources such as oil and gas 

development as part of our control 

strategy. We agree with the commenter 

that oil and gas activity in New Mexico 

produces NOX and other emissions. We 

understand the WRAP is currently 

reviewing and refining the emissions 

inventory for this sector. We will 

address this matter further in our review 

of New Mexico’s RH SIP. 

2. BART Requirements 

Comment: One commenter states 

‘‘EPA’s BART determination for the San 

Juan Generating Station contravenes 

EPA’s rules and conflicts with the 

structure and purpose of CAA Section 

169A.’’ Following this comment, there 

appears a parenthetical ‘‘see’’ reference 

to comments that had been submitted 

from two other commenters. 

Response: The comment does not give 

any underlying rationale or facts for its 

assertion that our action contravenes 

our rules and conflicts with CAA 

Section 169A. We disagree with the 

statement, because the NOX BART 

determination for the SJGS was made in 

accordance with our rules and CAA 

requirements. The references to 

subsections of other submitted 

comments do not appear to match with 

the comments we had received. We 

cannot further evaluate or respond to 

this comment. In any event, the other 

comments are separately addressed in 

this document. 

Comment: One commenter states that 

our proposed rule must be withdrawn 

because it fails to justify 

implementation of a SCR BART limit. 

This commenter cites to a portion of 

American Corn Growers v. EPA, 291 

F.3d 1, 19 (DC Cir. 2002), where the DC 

Circuit wrote of state’s having ‘‘broad 

authority over BART determinations.’’ 

The commenter also points to that 

court’s discussion of legislative history, 

where it stated that ‘‘* * * Congress 

intended the states to decide which 

sources impair visibility and what 

BART controls should apply to those 

sources.’’ Id. at 8. From this, the 

commenter states that the authority of 

states to establish BART cannot be 

constrained by us. 

Response: While a State has broad 

authority over a BART determination 

when it is the decision maker, we 

similarly have broad authority when 

promulgating a FIP. Because, as 

discussed earlier in this notice, New 

Mexico did not timely formulate and 

submit its BART determinations, we 

have the authority and responsibility to 

make a NOX BART determination for 

SJGS. 

Comment: One commenter argues that 

an evaluation of the amount of 

reasonable progress expected to be 

achieved in the Class I areas by other 

control measures is required before the 

amount of reasonable progress needed 

from BART at the SJGS should be 

determined. Under the CAA, BART is 

not expected to be the maximum degree 

of emissions reduction technologically 

feasible. In fact, it may be lower if 

reasonable progress from other CAA 

programs is sufficient. 

Response: We believe BART to be a 

severable piece of the RHR that can be 

evaluated on its own. BART can be a 

part of a reasonable progress strategy, 

and controls imposed under other CAA 

requirements can be considered to be 

BART. In fact, as we discuss elsewhere 

in our response to comments, we did 

evaluate the existing controls at the 

SJGS, but found them inadequate to 

satisfy NOX BART. However, there is 

not any requirement in the RHR that 

would require we first make an 

evaluation of reasonable progress prior 

to conducting a BART evaluation, nor is 

there any consideration of lessening the 

degree of a potential BART control in 

light of other CAA programs. 

Comment: One commenter alleges our 

proposed rule improperly requires 

BART for the San Juan Generating 

Station under Section 110 of the CAA 

and not Section 169A. While we 

propose to act under the ‘‘good 

neighbor’’ provision in Section 110 of 

the CAA, the commenter alleges, EPA 

‘‘appears to selectively borrow’’ the 

BART requirement from the RH program 

established under Section 169A to do 

what ‘‘neither section could do alone.’’ 

One commenter states Congress 

intended BART to be one part of a 

‘‘comprehensive, long-term strategy for 

addressing RH in Class I areas.’’ The 

commenter asserts that BART is more 

stringent than 169A requires, because it 

is being used ‘‘out of context’’ in a 

limited Section 110 program designed to 

ensure one state does not interfere with 

another state’s air quality plans. The 

commenter feels the approach we use is 

a partial or piecemeal implementation 

of the RH program, which is contrary to 

the integrated, comprehensive decisionmaking that 169A envisions. Because 

requirements of Section 110 and the 

Section 169A were not kept separate 

from each other, the commenter feels 

our proposal is substantively and 

procedurally flawed and fails to 


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Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 52421 

67Supplemental Proposed Rule of Source 

Specific Federal Implementation Plan for 

Implementing Best Available Retrofit Technology 

for Four Corners Power Plant: Navajo Nation, 76 FR 

10530. 68 Id. 

properly implement the programs under 

both sections. 

Response: We are not requiring NOX

BART for the SJGS under section 110 of 

the CAA. We are requiring NOX BART 

for the SJGS under section 169A and the 

RHR. Further, we disagree with the 

statement that BART requirements were 

selectively borrowed from the RH 

program or that any provisions were 

selectively borrowed or considered out 

of context. In making the BART 

determination, we first looked to RHR 

requirements and determined SJGS is 

BART eligible for NOX at each affected 

emissions unit. We then established 

BART for those units under the RH Rule 

and the Guidelines for BART 

Determinations found in Appendix Y of 

40 CFR part 51. Because our BART 

determination is in accordance with the 

guidelines, it is not any more stringent 

due to the additional action under 

Section 110. Moreover, as discussed 

elsewhere, we do not agree our 

determination is procedurally or 

substantively flawed because it is not 

comprehensive enough. While other 

commenters have suggested that we 

should proceed to determine BART for 

other pollutants, we are finalizing a 

NOX BART determination for the SJGS 

and will address other RH requirements 

in a separate future action. Therefore, 

we do not agree that the action under 

Section 110 and the determination 

under Section 169A have created any 

conflict or flaw in the implementation 

of either program. 

Comment: A commenter states that 

although a similar analytical approach 

is appropriate, the outcome of the BART 

analysis for the SJGS should differ from 

the proposed BART determination for 

the Four Corners Power Plant. 

Commenter agrees that a consistent 

method of analysis should apply. 

However, it disagrees that the outcomes 

of the analyses must be the same, given 

the meaningful differences between the 

two facilities. For example, the site 

congestion is a much greater concern at 

the SJGS than at Four Corners. EPA 

should reconsider the emission limit it 

assumed for San Juan in the sitespecific, plant-wide manner employed 

by Region 9. 

Another commenter states the 

proposal fails to consider other BARTeligible sources or other emission 

control strategies. In addition, the 

commenter is concerned that our 

proposed FIP for the SJGS may have 

been inappropriately influenced by the 

FIP proposed for Four Corners Power 

Plant by Region 9. Although the overall 

analytical approach must be consistent, 

the commenter argues, the final 

determinations should be different to 

reflect the differences between those 

two facilities. 

Response: We agree with the 

commenters that a consistent method of 

analysis should apply for all BART 

evaluations, and we believe the use of 

the BART Guidelines ensures that 

occurs. However, we see no reason to 

conclude the outcomes of these analyses 

should be prejudged to necessarily have 

any relationship to each other. We note 

that the differences the first commenter 

mentions, such as existing pollution 

control equipment and site congestion, 

were factored into our SJGS NOX BART 

visibility modeling (baseline emissions) 

and cost evaluation, respectively. Also, 

concerning the amount of review time 

(e.g., comment period), our consent 

decree deadline prevents us from 

extending the comment period more 

than we already have, which was almost 

a month over our initial 60 day period. 

We disagree with the first commenter 

that we failed to properly consider the 

NOX emission limit the units of the 

SJGS can reliably attain. Elsewhere in 

our response to comments, we present 

detailed information that documents 

these units can reliably meet a NOX

BART emission limit of 0.05 lbs/ 

MMBtu. In our analysis, we see no 

information in the record that causes us 

to conclude there are any site specific 

issues that would prevent the units of 

the SJGS from attaining this emission 

limit. Lastly, as we discuss elsewhere in 

our response to comments, we have 

modified the compliance schedule. We 

find that compliance with the emission 

limits for the SJGS should be within 5 

years of the effective date of our final 

rule. We note that the compliance 

schedule for the Four Corners Power 

Plant is now being analyzed under a 

‘‘better than BART’’ scenario according 

to section 51.308(e)(2)–(3), which 

provides for a possibly longer time 

period for the installation of controls.67

Comment: The proposed FIP for SJGS 

is entirely inconsistent with the FIP 

proposed for six units in Oklahoma by 

EPA. Given the similarity of the BART 

determinations made by the state of 

Oklahoma and the BART determination 

prepared for San Juan by PNM’s 

consultant, and the significant 

difference between those determinations 

and EPA’s proposed FIP, commenter 

asks EPA to reconsider its BART 

analysis for SJGS using the method of 

analysis applied in Oklahoma. 

Response: We disagree that the results 

(e.g., emission limits and controls) of 

our proposed NOX BART 

determinations for Oklahoma 68 and the 

NOX BART determination we proposed 

for the SJGS should be similar. The cost 

of controls must be compared to the 

expected visibility benefits, and those 

benefits from the potential installation 

of SCR on sources in Oklahoma were 

predicted to be much less than what we 

expect to result from the installation of 

SCR at the SJGS. In fact, the visibility 

benefit (or lack thereof) from the 

installation of SCRs on the Oklahoma 

BART sources is so small that we did 

not see the need to refine the cost 

estimate by investigating the feasibility 

of a lower NOX emission limit. Our 

conclusion in no way implies we 

accepted the SCR cost estimate at face 

value—only that we did not see the 

need to refine it. With regard to the 

different BART compliance schedules 

between our proposals, we believed in 

SJGS’s case that the expected visibility 

benefits were so significant that the 

controls should be installed ‘‘as 

expeditiously as practicable.’’ 40 CFR 

51.308(e)(1)(iv). As we discuss 

elsewhere in our response to comments, 

we have modified the compliance 

schedule. We are finalizing a schedule 

which requires compliance with the 

emission limits within 5 years—rather 

than 3 years—from the effective date of 

our final rule. 

Comment: Some commenters have 

stated that the proposed FIP does not 

satisfy other requirements of the RH 

Program. 

Response: We are acting on a portion 

of the State’s SIP revision addressing 

Interstate Transport requirements, 

specifically visibility. We are not acting 

upon a state RH SIP submittal. The only 

RH requirement on which we are acting 

is to make a NOX BART determination 

for the SJGS and promulgate a NOX

BART FIP for the SJGS under the RHR. 

We have made clear in our proposal that 

we will later act on the rest of the RH 

requirements. 

Comment: One commenter states that 

the requirement to install SCR at the 

SJGS is a fatally flawed and unnecessary 

approach to RH reduction, and that the 

FIP is not consistent with the law, 

science, economics, or prudent 

engineering practice. 

Response: While we appreciate 

Commenter’s general concern about the 

control equipment for RH reduction, the 

Commenter did not provide any specific 

examples in the record to be able to 

adequately respond to this generalized 

statement. It should be noted that EPA’s 

action establishes emission limits that 


jlentini on DSK4TPTVN1PROD with RULES2
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69See Exhibit 1 RTC Revised Cost Analysis, lines 

91, Cost Analysis Fox. 

may be met with SCR but it does not 

mandate specific control equipment. 

Comment: A commenter states that 

our BART analysis should be only about 

visibility and not public health 

concerns, which can be misleading. 

Response: We agree with the 

commenter that our action should be, 

and in fact is, about protecting visibility. 

We derive our authority for this action 

both under section 110(a)(2)(D)(i)(II) of 

the CAA and the RHR. In so doing, 

although we do note the ancillary public 

health benefits resulting from 

controlling the same pollutants that 

cause visibility, we have not considered 

those benefits in arriving at our 

decision. 

3. Executive Orders Comments 

Comment: The MSR Public Power 

Agency (MSR) disagrees with our 

findings under the Unfunded Mandates 

Reform Act of 1995 that the proposed 

FIP does not contain a federal mandate 

that may result in expenditures by state, 

local, or tribal governments that exceed 

the inflation-adjusted threshold of $100 

million ($100 million in 1995 dollars) or 

more in any one year thus triggering a 

written assessment of the costs and 

benefits of the proposed FIP. MSR 

believes that the cost of retrofitting the 

four units at the SJGS is closer to PNM’s 

estimated cost of $908 million. 

Response: The Unfunded Mandates 

Reform Act (UMRA) requires that 

Federal agencies assess the effects of 

Federal regulations on State, local, and 

tribal governments and the private 

sector. In particular, UMRA requires 

that agencies prepare a written 

statement to accompany any rulemaking 

that ‘‘includes any Federal mandate that 

may result in the expenditure by State, 

local, and tribal governments, in the 

aggregate, or by the private sector, of 

$100,000,000 or more (annually 

adjusted for inflation) in any one year’’ 

(Section 202(a)). Our revised cost 

estimate indicates that the Total Annual 

Cost is $39,265,670.69 Therefore, we 

have determined that we are below this 

threshold, even without adjusting it for 

inflation. In other words, even if the 

entire Total Annual Cost of the 

installation of SCRs on the units of the 

SJGS were ascribed to one entity, we do 

not believe the UMRA threshold would 

be triggered. 

Comment: Once commenter states 

that we should not ignore Executive 

Order 12866. 

Response: This action is not a 

‘‘significant regulatory action’’ under 

the terms of Executive Order 12866, (58 

FR 51735, October 4, 1993) as it only 

applies to one facility and is not a rule 

of general applicability. Therefore, this 

action is not subject to review under the 

Executive Order. 

Comment: One commenter states that 

the proposed rulemaking is contrary to 

Executive Order 13563 (Improving 

Regulation and Regulatory Review) of 

January 18, 2011 and as such we should 

consider the cost of promulgating the 

rule and take the least burdensome path 

among different options. 

Response: Executive Order 13563 is 

supplemental to and reaffirms the 

principles, structures, and definitions 

governing contemporary regulatory 

review that were established in 

Executive Order 12866 of September 30, 

1993. The President issued the 

referenced Order on January 18, 2011, 

after we issued our proposed 

rulemaking. In general, the Order seeks 

to ensure the regulatory process is based 

on the best available science; allows for 

public participation and an open 

exchange of ideas; promotes 

predictability and reduces uncertainty; 

identifies and uses the best, most 

innovative, and least burdensome tools 

for achieving regulatory ends; and takes 

into account benefits and costs, both 

quantitative and qualitative. However, 

nothing in the Order shall be construed 

to impair or otherwise affect the 

authority granted by law to the Agency. 

Although this Order was issued after 

our proposed rulemaking, in our review 

process the cost of compliance was one 

of the elements addressed to ensure that 

the requirements to achieve the goals 

stated in the CAA were beneficial and 

not burdensome to the regulated entity. 

Please refer elsewhere in our response 

to comments for a detailed analysis of 

the elements required by our regulations 

for BART determinations. 

Comment: The Navajo Nation EPA 

commented that the FIP proposal has 

tribal implications as specified in 

Executive Order 13175, and that 

consultation is required because of the 

impacts to Navajo workers, contractors, 

and subcontractors at San Juan 

Generating Station and the San Juan 

Mine. 

Response: Executive Order 13175, 

entitled ‘‘Consultation and Coordination 

with Indian Tribal Governments’’ (65 FR 

67249, Nov. 9, 2000), relates to 

consultations with tribal governments 

by federal agencies. As directed by the 

Executive Order, EPA has recently 

issued a new policy entitled EPA Policy 

for Consultation and Coordination with 

Indian Tribes (May 4, 2011), which reestablishes and clarifies EPA’s process 

for consulting with tribes. We have 

concluded that this final rule does not 

have tribal implications, as specified in 

Executive Order 13175, because this 

action does not impose federally 

enforceable emissions limitations on 

any source located on tribal lands, and 

neither imposes substantial direct 

compliance costs on tribal governments, 

nor preempts tribal law. However, in 

response to this comment, we engaged 

in government-to-government 

consultation at the request of the Navajo 

Nation regarding this rule and the 

Nation’s previously submitted 

comments. 

4. Other General Legal Comments 

Comment: A number of commenters 

have requested that we should approve 

the New Mexico Interstate Transport SIP 

previously submitted in 2007 as it 

satisfies both our policy and our 

Consent Decree with WildEarth 

Guardians. Another commenter states 

that we have no sound basis in any 

event for disapproving New Mexico’s 

SIP revision under the visibility clause 

of section 110(a)(2)(D)(i)(II), as that SIP 

revision simply carries out our own 

guidance to the states. 

Another commenter stated that our 

proposal to adopt a FIP before NM 

completes its ongoing rulemaking 

process to adopt a RH SIP is premature 

and deprives the state of its significant 

discretion to establish and administer 

its own RH program. 

Response: We disagree that we should 

approve the SIP submitted in 2007 

because it satisfies both our policy and 

the WEG Consent Decree. Our consent 

decree with WEG requires that by 

August 5, 2011, we must approve a SIP, 

promulgate a FIP, or approve a SIP in 

part with promulgation of a partial FIP 

for New Mexico to meet the requirement 

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

interfering with measures in other states 

related to protection of visibility. As 

stated elsewhere in this notice, New 

Mexico’s 2007 submittal fails to meet 

this requirement. That SIP anticipated 

the timely submission of a substantive 

RH SIP, which was due by December 17, 

2007, as the means of meeting this 

requirement. Because until recently that 

RH SIP was not submitted, we had no 

choice but to seek other means of 

satisfying our WEG consent decree 

deadline of August 5, 2011. 

Because states were late in their RH 

SIP submissions, 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. In New Mexico’s 

case, this finding included sections 40 

CFR 51.309(g) and 40 CFR 51.309(d)(4). 

Section 51.309(d)(4)(vii) states that the 

implementation plan must contain any 


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Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 52423 

70See RHR, 64 FR 35714 (July 1, 1999). 

71BART-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. 

necessary long term strategies and 

BART requirements for stationary 

source PM and NOX emissions. Any 

such BART provisions may be 

submitted pursuant to either 

§ 51.308(e)(1) or § 51.308(e)(2). 

This finding started a 2-year clock, 

which expired on January 15, 2011, for 

the promulgation of a RH FIP by us, 

unless those states, including New 

Mexico, made a RH SIP submission and 

we approved it. Therefore, we had full 

authority to promulgate a FIP for the 

State of New Mexico that included a 

NOX BART determination for the SJGS. 

In response to the second commenter, 

we do not view it as premature to take 

action on one element of the RH 

requirements at this time. We chose to 

exercise this authority to conduct a NOX

BART review of the SJGS, as a partial 

route forward in satisfying our consent 

decree with WEG. 

Although we subsequently received 

the New Mexico submittal on July 5, 

2011, we simply have arrived at a point 

where we do not have the time to stop 

our action, review that SIP, propose a 

rulemaking, take and address public 

comment, and promulgate a final action 

as defined in the consent decree. 

Comment: One commenter alleges 

that our statement that the SJGS is more 

than 30 years old and needs to update 

its control equipment is inaccurate. 

Response: As explained elsewhere in 

this notice and our proposal, our data 

supports the need for the SJGS to retrofit 

their sources of emissions to meet the 

requirements of the CAA. 

Comment: One commenter argues that 

the Administrative Procedures Act is 

not adequate regarding impacts on small 

governmental entities. 

Response: This final rulemaking only 

addresses the disapproval of a portion of 

the SIP revision submitted by the State 

of New Mexico for the purpose of 

addressing the visibility prong of the 

Interstate Transport rule. See elsewhere 

in our response to comments for a 

detailed description of what is 

addressed in this Final Action. 

Therefore, comments related to the 

Administrative Procedures Act and how 

it is not adequate regarding the impacts 

to small businesses are outside the 

scope of our proposed action. 

Comment: One commenter alleges 

that ‘‘Federal forces’’ create air 

regulations to solve a problem that 

doesn’t exist and threatens our county’s 

livelihood. 

Response: This rulemaking is the 

result of CAA requirements that a SIP 

must have adequate provisions to 

prohibit emissions from adversely 

affecting another state’s air quality 

through interstate transport and that 

certain facilities install BART to protect 

visibility in national parks and 

wilderness areas. The visibility problem 

in these areas of great scenic importance 

has been recognized as a significant 

issue by policymakers from Federal, 

State and local agencies, industry and 

environmental organizations.70

Technical data, that are part of the 

record, evidence that emissions of SO2

and NOX from the SJGS are interfering 

with efforts to protect visibility in other 

states, as well as impacting Class I areas 

within NM. 

P. Modeling Comments 

Comment: The San Juan Coal 

Company (SJCC) commented that EPA 

compared the emission levels of both 

New Mexico’s 2018 projected emissions 

and New Mexico’s current emissions 

that were developed for the WRAP 

photochemical modeling. EPA relied 

upon that comparison to determine that 

all of the sources in New Mexico are 

achieving the emission levels assumed 

by WRAP in its modeling except for the 

SJGS. SJCC alleged that EPA’s summary 

of that analysis presents no relevant 

data to support the Agency’s 

conclusion. Because the WRAP 

inventories are so extensive and 

difficult to research and review, EPA at 

a minimum should have provided 

copies of the State’s emissions 

inventories that were reviewed and the 

specific emissions data for SJGS that 

supports EPA’s conclusion. SJCC stated 

that EPA should not have put the 

burden of interpreting the WRAP 

technical support documents on the 

reader. Furthermore, in light of the 

substantial number and different types 

of emission sources throughout New 

Mexico, our conclusion is suspect. EPA 

must produce the specific emissions 

information for SJGS and for all other 

emission sources in the State, which 

isolates SJGS as the only reason for New 

Mexico’s interstate interference with 

visibility protection. 

Response: While we did point in the 

proposed rule to the WRAP Web site as 

a reference for the emission data that we 

reviewed and compared, we also 

developed a complete TSD, and 

included some of the spreadsheets for 

2002, i.e., the ‘‘current’’ emissions and 

for the projected 2018 emissions, in the 

docket for the proposed rule. 

Specifically, in Chapters 2 (BART 

Eligible Determination), 3 (Subject-toBART Determination) and 4 (BART 

Guidelines and Modeling Protocols) of 

the TSD we discussed the WRAP’s 

CALPUFF screening modeling and why 

we identified SJGS as the only source in 

New Mexico that was not sufficiently 

controlled to eliminate interference with 

the visibility programs of other states. 

Our review and the State’s first 

focused on BART eligible sources 

because these are sources first 

considered for control in State Regional 

Haze Plans. In May 2006, NMED 

conducted an internal review of sources 

that met the regulatory definition 

‘‘BART-eligible’’ source set forth in 40 

CFR 51.301.71 The State identified 11 

facilities that were BART-eligible. The 

WRAP performed the initial BART 

CALPUFF screening modeling for the 

state of New Mexico. The modeling was 

performed for each of the 11 sources 

and their combined SO2, NOX, and PM 

emissions. The purpose of this BART 

CALPUFF screening modeling was to 

determine whether any of these 11 

sources ‘‘emits any air pollutant which 

may reasonably be anticipated to cause 

or contribute to any impairment of 

visibility’’ in any Federal Class I area. 

Consistent with the BART Guidelines, 

this WRAP initial BART CALPUFF 

screening modeling evaluated the 98th 

percentile visibility impacts at any Class 

I area from each of these 11 sources. 

Using 0.5 dv as the significance 

threshold, of the 11 sources, only one 

source’s visibility impacts at any Class 

I area due to its combined SO2, NOX, 

and PM emissions was above the 0.5 dv 

significance threshold (i.e., PNM’s SJGS 

Boilers #1–4). Of the 10 other sources, 

none were above a 0.33 dv impact. 

Consequently, only the PNM’s SJGS 

Boilers #1–4 were determined by NMED 

to be emitting pollutants contributing to 

impairment of visibility in any Federal 

Class I area and therefore were 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 dv. As discussed in the 

TSD, based on modeling sensitivities, 

even if we re-ran the BART CALPUFF 

screening modeling for the other 10 

sources, the conclusion reached by both 

New Mexico and EPA would be 

unlikely to change. Therefore, these 

facilities are not subject to BART. As 

such, New Mexico did not propose 

additional controls for these facilities 

nor did the WRAP modeling include 

additional reductions for these 10 


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sources. These 10 sources are 

sufficiently controlled to eliminate 

interference with other states’ visibility 

programs. 

Our review and the States’ 

particularly focused on sources 

potentially subject to BART because in 

developing RH plans, sources subject to 

BART were a particular focus for States 

in projecting emission reductions. After 

the running of the WRAP initial BART 

CALPUFF screening modeling that 

identified the one source subject to 

BART, the WRAP ran photochemical 

modeling for all the sources in the entire 

region for the base year (2002) and the 

future year (2018). The WRAP 

participating states based their RH 

reasonable progress goals and long-term 

strategies upon this photochemical 

modeling and its inputs, particularly the 

future year projections for all of the 

sources in the region. All the 

participating WRAP states agreed to the 

emissions input for the base and future 

years. These states are relying upon the 

WRAP photochemical modeling’s future 

year projected emissions from all the 

sources in the region to establish their 

Reasonable Progress Goals. In 

consultation with New Mexico, the 

WRAP photochemical modeling 

included anticipated reductions in 

emissions at the SJGS. Through the 

WRAP consultation process, New 

Mexico provided the anticipated future 

year projected emissions from SJGS to 

be 0.27 lb/MMBtu for units 1 and 3 and 

0.28 lb/MMBtu for units 2 and 4. Other 

WRAP states are relying on the levels 

modeled for the SJGS units, developed 

in consultation, in their demonstration 

of reasonable progress plans towards 

natural visibility conditions. New 

Mexico, however, did not adopt limits 

to insure that the levels assumed for 

SJGS in the WRAP modeling would be 

achieved. This discrepancy from what 

other States assumed is a particular 

concern because, as discussed 

previously, SJGS, was found in the 

BART modeling to, by itself, contribute 

significantly to visibility impairment. 

Our review of the WRAP BART 

CALPUFF screening modeling and 

analysis for sources potentially subject 

to BART in New Mexico is well 

documented in the TSD as described 

above. In addition, as part of our review, 

we evaluated the methodologies used by 

WRAP in developing their future year 

emissions projections for the WRAP 

photochemical modeling. The 

spreadsheets on the WRAP Web site 

document the future year projections 

used by the WRAP in their 

photochemical modeling. Except for 

SJGS, the WRAP projections in the 

photochemical modeling were 

supported by accepted and agreed upon 

emissions inventory projection 

methodologies in combination with 

regulations or other limitations and 

were based on the data available at the 

time. This information was publicly 

available for review on the WRAP Web 

site. 

Therefore, we adequately explained 

why our action is limited to the SJGS. 

In addition, the information we relied 

on to reach our conclusions is available 

to the public and was validated by a 

voluntary group of state, federal and 

local air agencies dealing with regional 

air quality issues. Relying on WRAP 

data provides consistency of analyses 

throughout the Western states, and 

assures that our decisions are not 

arbitrary. Thus, EPA’s decision is based 

on data to support that the SJGS is the 

only source that requires the enforceable 

measures in this action to ensure 

reductions needed to meet the 

anticipated level of emissions relied 

upon in the WRAP modeling. 

Comment: SJCC contests EPA’s 

conclusion that SJGS is the only source 

in New Mexico continuing to contribute 

to visibility impairment in other states 

because EPA reached this conclusion 

without comparing all the New Mexico 

sources’ current emissions in the WRAP 

modeling with their projected 2018 

emissions. In addition, EPA did not use 

the annual emissions value in the ‘‘core 

emission inventories’’ presented in the 

WRAP modeling for the SJGS reported 

in tons per year (tpy). The commenter 

states that EPA performed its 

comparison by using emission rates in 

terms of units of pounds per British 

thermal unit (lbs/MMBtu) for the SJGS. 

The commenter continues to allege that 

in addition to using lbs/MMBtu rather 

than the annual emissions, EPA 

apparently, further adjusted SJGS’s 

current emissions that were in the 

WRAP modeling to account for a shorter 

averaging time because the WRAP 

averaging periods were unenforceable. 

This methodology was not applied to 

any other source. SJCC claims that if 

EPA had applied this methodology to 

the other New Mexico sources, it is 

extremely likely that EPA would have 

needed to adjust their current levels as 

well. Therefore, EPA’s comparison 

analysis is flawed, and EPA cannot 

assume that the SJGS is the only source 

in the State (or within the WRAP region 

for that matter) whose current emissions 

have not been specified on a basis that 

is consistent with how projected 2018 

emissions were expressed for the WRAP 

modeling. 

Response: As discussed in our 

proposal and elsewhere in this notice, 

the analysis conducted by the WRAP 

provides an appropriate means for 

evaluating whether emissions from 

sources in a state are interfering with 

the visibility programs of other states, as 

contemplated in section 110(a)(2)(D)(i) 

of the Act. In developing their visibility 

projections using photochemical grid 

modeling, the WRAP states assumed a 

certain level of emissions from sources 

within New Mexico. The visibility 

projection modeling was in turn used by 

the states to establish their own 

respective reasonable progress goals. We 

evaluated the planned emission 

reductions from point sources in New 

Mexico assumed in the WRAP 2018 

modeling. But for SJGS, the WRAP 

projections were supported by accepted 

and agreed upon emissions inventory 

projection methodologies and/or 

regulations or other limitations and 

were based on the data available at the 

time. As a result of the initial BART 

analysis performed by the WRAP, 

identifying SJGS as subject-to-BART, 

and consultation with New Mexico, the 

WRAP photochemical modeling 

included anticipated reductions in 

emissions at the SJGS. The reductions at 

SJGS were the only additional 

reductions that other states relied upon 

occurring that NMED would require in 

their RH/BART SIP. The WRAP’s 

photochemical modeling that was 

performed to yield daily (24-hour) 

visibility impairment impacts adjusted 

the future year NOX emissions from 

SJGS after input from NMED and PNM 

to 0.27 lb/MMBtu for units 1 and 3 and 

0.28 lb/MMBtu for units 2 and 4. 

PNM has subsequently indicated that 

they cannot meet these relied-upon 

emission rates without installing 

additional control equipment and the 

actual achievable emission rate is 

approximately 0.30 lb of NOX/MMBtu 

on a longer-term basis (30 day rolling 

average) as currently reflected in their 

permit and 0.33 lb of NOX/MMBtu on a 

shorter-term basis. Clearly, the 

difference between what was assumed 

by the WRAP and what is actually being 

achieved and is enforceable should not 

be ignored. 

We disagree that our use of lbs/ 

MMBtu versus the annual emissions 

rate compromised our evaluation. There 

is no compromise in integrity using the 

lbs/MMBtu versus using an annual 

emission rate, since the annual NOX

emission rate for each EGU in the 

WRAP photochemical modeling is 

calculated using the short term emission 

rate of lbs/MMBtu multiplied with the 

heat input and hours of operation. In the 

future case photochemical modeling for 

most sources, the actual base emissions 

from 2002 were projected to the future 

using differing techniques to project the 


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72 Document that was included in our proposal 

docket, ‘‘Developing the WRAP Point and Area 

Source Emissions Projections for the 2018 

Reasonable Progress Milestone for Regional Haze 

Planning’’, Paula G. Fields, Martinus E. Wolf, Tom 

Moore, Lee Gribovicz. 

73NMED Proposed Regional Haze SIP, available 

at AppxA_NM_SJGS_NOxBARTDetermination

_06212010.pdf and modeling files provided by 

NMED to EPA for Review June/July 2009. 

amount of growth and yield an estimate 

of the future emissions, taking into 

account the source type, any applicable 

regulations and limitations, and data 

available at the time. As discussed in 

another response to comment, the 

WRAP modeling was conducted in a 

collaborative effort, and the 

participating states agreed with these 

methodologies for generating the future 

year emission inventories. To apply the 

same exact procedures in calculating 

future emissions that were applied to 

the SJGS to all other sources in New 

Mexico would be inconsistent with the 

methodology that the WRAP used. We 

used the same methodology to calculate 

emissions for EGU’s that were installing 

controls as the WRAP did for other 

EGUs installing controls. We used the 

short-term 0.33 lb/MMBtu emission rate 

as it directly relates to the averaging 

period for evaluating the visibility 

impairment, which is daily. For EGUs, 

the WRAP utilized a forecasting 

technique to yield 2018 emission 

estimates by applying a growth factor to 

the 2002 firing rate up to a capacity 

threshold of 0.85.72 For NOX and SOx 

emissions from EGUs, the WRAP also 

used data from 2004 to be representative 

of emission rates for 2018. However, for 

EGU sources where the installation of 

controls was anticipated, such as the 

SJGS, they utilized the short-term 

emission factor that would result from 

the addition of controls (lb of pollutant 

per MMBtu) and then multiplied by the 

heat input to yield an annual tpy value 

that was reported in the WRAP’s 

emission spreadsheets. While the 

commenter is correct that the WRAP’s 

spreadsheets for photochemical 

modeling report data is in tpy, the 

WRAP calculation method uses the 

same basis for calculation that we used 

in our analysis, a lb of pollutant per 

MMBtu. We did our emission 

calculations for the SJGS using the same 

methodologies as the WRAP for other 

EGUs installing controls and, therefore, 

disagree with the commenter’s 

allegation that the SJGS were calculated 

unfairly. 

We disagree with the characterization 

that we adjusted the SJGS current 

emissions in the WRAP. From the 

comment it is unclear if the 

commenter’s concerns were just about 

emission rate/calculations for the 

photochemical modeling or the 

CALPUFF modeling. Because the 

comment is unclear, we have addressed 

their comment for both types of 

modeling. At issue is the emission rate 

that needs to be calculated from the 

SJGS in order to determine visibility 

impacts from the facility. For the 

CALPUFF modeling, the July 2005 

BART rules recommend using the actual 

24-hour maximum emission rate over 

the last several years as the basis for the 

baseline emissions, and when a source 

is controlled in the future the emission 

rate that would represent a maximum 

24-hour potential emission rate after 

install of controls is used for the future 

control scenario. Therefore, the values 

used in the CALPUFF modeling 

pursuant to EPA regulation and 

guidance are a short-term (24-hour) 

emission rate to reflect visibility 

impairment impacts. For the baseline, 

we took the existing enforceable permit 

level, which is a 30-day average and 

converted it to a 24-hour maximum 

emission rate to use in CALPUFF to 

determine the visibility impacts from 

the SJGS. PNM and NMED’s CALPUFF 

modeling, conducted to estimate daily 

visibility impairment at Class I areas for 

the baseline conditions, utilized an 

emission factor rate of 0.33 lb/MMBtu as 

the level that they could show 

compliance on a short-term basis.73 We 

utilized the same emission rate in our 

CALPUFF modeling of the base case 

visibility impacts. 

In the photochemical modeling, the 

emission rate used in the baseline 

inventory was based on a NOX emission 

rate of 0.27 or 0.28 (depending on the 

boiler Unit) and a 0.33 lb/MMBtu based 

rate as the maximum 24-hour emission 

rate in the CALPUFF modeling. We also 

note that these baseline emission rates 

were used by the state in consultation. 

In summary on this issue, EPA believes 

the commenter did not fully understand 

how emission rates were modeled for 

the two modeling platforms in 

comparison to how the WRAP 

calculated future year emission rates for 

EGUs, and we believe we have followed 

our regulations and guidance in 

accurately assessing the impacts with 

appropriate emission rates. 

As part of our action for 

110(a)(2)(D)(i) of the CAA, we are also 

setting a SO2 limit in our action to be 

protective of the 0.15 lb/MMBtu limit 

for SJGS units that was included in the 

WRAP photochemical modeling and 

relied upon by WRAP states. SJGS has 

installed control equipment that is 

achieving below this level currently, but 

does not have an enforceable limit that 

limits the SJGS units to 0.15 lb of SO2/ 

MMBtu. 

Comment: The SJCC found the 

wording of EPA’s conclusion comparing 

New Mexico’s current emissions and 

projected 2018 emissions to be 

confusing. If all sources in New Mexico, 

other than SJGS are currently achieving 

projected 2018 emissions, as EPA 

asserts, then that means the only 

emissions reductions that will occur 

during the first RH planning period 

from all emission sources in New 

Mexico will be from SJGS, which SJCC 

asserts is incorrect. To support this 

interpretation, the SJCC turned to the 

New Mexico emissions inventories used 

in the WRAP modeling and noted that 

the WRAP modeling projects a 

reduction in NOX emissions of about 

10,500 tpy from the SJGS by 2018. The 

SJCC notes that in comparison, the 

State’s (then) proposed RH SIP 

estimated that statewide NOX emissions 

will decrease by 64,814 tpy by 2018. 

Based upon these numbers and 

comparing them, the SJCC concludes 

that the statement that all sources in 

New Mexico, except SJGS, are achieving 

the emission levels assumed by the 

WRAP modeling is incorrect. Rather, the 

SJCC asserts, information shows that 

other New Mexico sources besides the 

SJGS could be ‘‘interfering’’ with other 

states’ measures to protect visibility. 

The SJCC concludes that although EPA’s 

interpretation of ‘‘interference’’ may be 

reasonable on its face, the application of 

its explanation of its meaning indicates 

otherwise. EPA’s explanation provides 

no credible justification for singling out 

the SJGS as the only New Mexico source 

of emissions that is interfering with 

other states’ visibility-protection 

measures. 

Response: The statement that other 

sources were achieving the necessary 

reductions may have been unclear. In 

developing its emissions inventory, 

WRAP states estimated the emissions 

growth and all reductions that were 

expected to occur from point, area, and 

other sources, from all regulatory 

requirements. For New Mexico point 

sources other than the SJGS, the current 

federally enforceable emission limits for 

these sources are consistent with those 

relied upon in the WRAP modeling. For 

the SJGS, the WRAP states considered 

the impact of the RH BART 

requirements. As discussed in our 

proposal and elsewhere in this notice, 

we evaluated the planned emission 

reductions from point sources in New 

Mexico assumed in the WRAP modeling 

and concluded that the SJGS was the 

only source in New Mexico that was 

expected to get reductions beyond the 

current, i.e., baseline levels, because 


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74Memo from Joseph Paisie (Geographic 

Strategies Group, OAQPS) to Kay Prince (Branch 

Chief EPA Region 4) on Regional Haze Regulations 

and Guidelines for Best Available Retrofit 

Technology (BART) Determinations, July 19, 2006 

75Page 39129 of BART Rule, ‘‘We believe the 

maximum 24-hour modeled impact can be an 

appropriate measure in determining the degree of 

visibility improvement expected from BART 

reductions (or for BART applicability)’’, Pages 

39107–3918 of BART Rule For assessing the fifth 

factor, the degree of improvement in visibility from 

various BART control options, the States may run 

CALPUFF or another appropriate dispersion model 

to predict visibility impacts. Scenarios would be 

run for the pre-controlled and post-controlled 

emission rates for each of the BART control options 

under review. The maximum 24-hour emission 

rates would be modeled for a period of three or five 

years of meteorological data. 

that source was determined to be subject 

to BART. The 10,500 tpy NOX reduction 

mentioned by the commenter refers to 

the reduction in NOX emissions at the 

SJGS anticipated by the WRAP and 

included in the future case 

photochemical modeling. 

For other sources, such as the ones 

the SJCC points to as accounting for the 

remainder of their 64,814 total 

reduction of NOX emissions in New 

Mexico, the WRAP states considered 

other rules on the books, projected 

reductions from other federal rules 

(including those addressing mobile 

sources), national consent decrees, and 

mobile source fleet turnover, among 

other things. These projections were 

reviewed and agreed to by the WRAP 

states as a part of their joint 

development of a complete WRAP 

emission inventory in support of their 

RH SIPs, and were relied upon by the 

WRAP states as a part of the reasonable 

progress goals. The commenter is 

correct that other sources in New 

Mexico are projected to reduce their 

emissions as well. Those projections are 

based on the states’ best estimate of the 

growth of emissions from some sources 

and the future impact of all combined 

regulatory programs. We conclude, for 

the purpose of satisfying section 

110(a)(2)(D)(i)(II), those projections were 

reasonable and adequately incorporated 

into the WRAP modeling. 

As to the comment on how we 

defined ‘‘interference’’ in the context of 

CAA § 110(a)(2)(D)(i)(II), please refer to 

our response to comments to legal 

issues (Section O.1 of this notice), 

where we have a full response as to how 

we view the term ‘‘interfere’’ in the 

context of the interstate transport 

requirements of the CAA. In that 

response we state that by promulgating 

a FIP to impose NOX and SO2 emission 

limits necessary at the SJGS to prevent 

such interference, as well as to meet the 

requirement for BART for NOX for this 

same source, EPA is addressing the 

requirements of the CAA. In reaching 

this conclusion, we considered the term 

‘‘interfere’’ based upon the facts, 

information, and data available to EPA 

at this time. 

Comment: PNM commented that our 

choice of an SO2 baseline and future 

emission rate of 0.15 lbs/MMBtu was 

incorrect, and that an SO2 emission rate 

of 0.18 lbs/MMBtu is more appropriate. 

PNM alleges that this is based on the 

current, federally enforceable emission 

limit. PNM asserts that our justification 

for using the lower SO2 rate is that the 

lower rate is expected in the future. The 

commenter argues that utilizing the 

current SO2 limit is the more 

appropriate modeling method even 

though the use of the current limit 

would actually result in higher expected 

visibility improvements. 

Response: We conducted CALPUFF 

visibility modeling to analyze the 

impacts on visibility impairment from 

the NOX BART proposed controls. Due 

to the nonlinear nature and complexity 

of atmospheric chemistry and chemical 

transformation among pollutants, all 

relevant pollutants should be modeled 

together to predict the total visibility 

impact at each Class I area receptor.74 In 

order to estimate the benefits from the 

NOX BART proposed controls, we 

included the SO2 emissions as relied 

upon in the WRAP modeling in our 

CALPUFF modeling. The SO2 emission 

limit of 0.15 lb/MMBtu that we input 

into the NOX BART visibility modeling 

is based upon what was relied upon in 

the WRAP modeling. Our FIP makes 

this WRAP-relied upon SO2 limit of 0.15 

lb/MMBtu federally enforceable. PNM’s 

requested baseline emission rate of 0.18 

lb/MMBtu of SO2 is not what was relied 

upon in the WRAP modeling. 

Per EPA’s BART Guidelines, 

maximum actual emissions should be 

utilized in the visibility modeling of the 

base case, and all installed control 

technology should be considered. 

Future case modeling should include 

post control maximum emission rates.75

We note that the SJGS currently has SO2

control technology installed and has 

current actual SO2 emissions below our 

proposed FIP limit. As a result, the 

facility will not have to install 

additional controls to meet our SO2 FIP 

limit. As we are setting the 0.15 lb/ 

MMBtu SO2 emission limit in the FIP 

for SJGS, we modeled an emission rate 

of 0.15 lb/MMBtu for SO2 for both the 

baseline (current) and control (future) 

cases in estimating the anticipated 

visibility improvement due to 

installation of the NOX BART proposed 

controls. By holding the SO2 emissions 

constant in the revised baseline 

(current) and future (control) cases, the 

modeled predicted improvements in 

visibility due to the NOX BART 

proposed controls are kept separate 

from any potential changes in visibility 

due to changes in SO2 emissions. This 

means the final CALPUFF analysis 

reflects only the benefits due to the 

additional NOX reductions beyond the 

baseline. This also reflects the SJGS’s 

flexibility to increase its SO2 emissions 

up to the SO2 FIP limit of 0.15 lb/ 

MMBtu. It provides a more 

representative estimate of anticipated 

visibility improvements from 

installation of NOX controls. 

Comment: A commenter disagrees 

with the general modeling approach and 

assumptions relied upon in EPA’s 

modeling analysis. The commenter 

contends that we performed numerous 

different visibility models and chose the 

one with the highest visibility 

improvements, even though the chosen 

model results are the least consistent 

and the least realistic of the modeling 

runs prepared. The commenter claims 

that EPA’s chosen value suggests that 

visibility improvements associated with 

installing SCRs at SJGS will be three 

times higher than the model that would 

assume more realistic, site-specific 

background ammonia concentrations 

and the Method 6 post-processing that 

has been relied upon by PNM, NMED, 

and WRAP and by EPA itself with 

regard to SO2 (by relying on the WRAP 

modeling). The commenter argues that 

EPA’s rejection of PNM’s modeling is 

unjustified and unnecessarily inflates 

the expected visibility improvements 

associated with SCRs. The commenter 

states that EPA did not raise any of its 

concerns to PNM or NMED until the 

issuance of the proposed FIP despite 

discussions with NMED over several 

years regarding proper modeling 

techniques. 

Response: This comment is incorrect. 

In January 2010, NMED proposed as 

NOX BART, the installation of SCR on 

the four units at SJGS and relied upon 

modeling much of which was 

completed in the 2006–2007 timeframe. 

SCR is generally considered the most 

stringent control technology available 

for NOX. The Guidelines for BART 

Determinations under the Regional Haze 

Rule’s modeling guidelines in 40 CFR 

part 51 App. Y, IV. D. 5 indicate that 

selection of the most stringent controls 

available may allow a source or the state 

agency to skip conducting visibility 

impairment modeling. Therefore, 

because NMED selected SCR, the most 

stringent control generally available, 

consistent with our RHR requirements 

(Step 1, Number 9 in the Guidelines), 

we did not perform a close review of the 

modeling in the State’s proposal during 


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the State’s public process. 

Unfortunately, NMED decided not to 

finalize their proposal and then 

withdrew it from further state 

rulemaking in May 2010. 

When we developed the proposed FIP 

for NOX BART, we conducted our own 

visibility impact analysis (the degree of 

visibility improvement reasonably 

anticipated due to NOX BART at SJGS). 

In conducting modeling for our 

proposed NOX BART FIP, we utilized 

current practices and model versions 

that were acceptable to us at the time 

they were conducted in the latter half of 

2010. In order to minimize technical 

concerns with the CALPUFF modeling 

system version, modeling options 

selected in CALMET, calculation of 

emissions (including sulfuric acid mist), 

and background ammonia levels 

employed by PNM, we remodeled 

visibility impacts using the CALPUFF 

version that we have determined to be 

appropriate for regulatory purposes. 

Please see our Complete Response to 

Comments for NM Regional Haze/ 

Visibility Transport FIP document for 

more details. We remodeled the 

visibility impacts of SJGS to address 

these issues with PNM and NMED’s 

modeling, utilizing an acceptable 

version of CALPUFF. In doing so, we 

maintain consistency with the most 

current modeling guidance EPA and the 

FLM representatives have provided to 

the states. 

We performed numerous modeling 

runs in order to evaluate the sensitivity 

of model results to the chosen model 

inputs and post processing methods to 

generally inform the process. The 

justification for selecting the revised 

IMPROVE equation (‘‘Method 8’’) over 

the original IMPROVE equation 

(‘‘Method 6’’) is discussed in a separate 

response to comment. Background 

ammonia concentrations are also 

discussed further in a separate response 

to comments. We disagree with the 

commenter’s assertion we simply 

picked the modeling results that best 

supported our position, without regard 

to consistency and/or realism. Every 

parameter and model input was 

evaluated and selected separately, based 

on accepted methodology of EPA and 

the FLM representatives, guidance and 

available data. During selection of 

model versions and inputs, EPA R6 staff 

conferred with other EPA modeling 

experts and FLM representatives on 

these modeling issues to ensure that our 

modeling would be done in accordance 

with current day CALPUFF modeling 

practices for visibility impairment 

analyses. A discussion of model 

selection and inputs was presented in 

our proposal and in the TSD and further 

discussed in the Complete Response to 

Comments for NM Regional Haze/ 

Visibility Transport FIP document. 

Results for all modeling scenarios are 

provided in the Appendix 3 to the TSD, 

entitled ‘‘EPA’s CALPUFF Visibility 

Modeling Results.’’ These results 

demonstrate the sensitivity of the model 

to underestimation of background 

ammonia and the sensitivity to the use 

of the original IMPROVE equation. 

Utilizing the different methods and 

different ammonia levels does result in 

different predicted impact levels, but 

the overall change in visibility 

impairment, i.e., the net visibility 

improvement, due to the proposed NOX

BART FIP emission limit is a significant 

value in all cases. In other words, while 

the ammonia levels affect visibility 

improvement, throughout the range of 

ammonia background being modeled, 

the NOX BART controls adopted here 

result in significant and important 

visibility improvement. For example, 

our sensitivity modeling predicted 

significant visibility improvement at 

Mesa Verde due to the proposed NOX

BART emission limit, ranging from 38 to 

56% improvement, depending on the 

background ammonia and postprocessing method selected. 

Comment: We received comments 

that alleged that our CALPUFF 

modeling analysis failed to fully and 

appropriately account for the visibility 

improvement already achieved by 

recent SO2 and NOX emission 

reductions from SJGS. PNM contracted 

with B&V to perform a BART analysis 

for the SJGS. The commenters claim that 

this analysis used EPA’s BART 

guidelines and showed that the low 

NOX burners installed on all four units 

at SJGS during the environmental 

upgrade project between 2007 and 2009 

meet the requirements for NOX BART. 

Response: Our technical modeling 

analysis accounted for the visibility 

improvements achieved by existing 

controls at the SJGS by incorporating 

the SO2 and NOX enforceable permit 

limits established under the March 10, 

2005 consent decree between PNM and 

the Grand Canyon Trust, Sierra Club, 

and NMED (2005 Consent Decree) into 

the baseline emissions modeling 

scenario. Our analysis of the visibility 

improvements due to the installation of 

NOX controls as part of our proposal 

reflected the visibility improvement due 

to installation of additional NOX

controls beyond those installed as 

required by the 2005 Consent Decree 

(completed in 2009). Furthermore, we 

note that neither NMED nor EPA 

reviewed or approved a NOX BART 

analysis including a CALPUFF 

modeling analysis performed by B&V 

prior to the installation of controls 

under the 2005 consent decree. LowNOX burners do not satisfy the 

requirements for NOX BART for the 

SJGS; they are not supported by the 

NOX BART five-factor analysis. 

Comment: We received comments 

suggesting that modeling should be 

performed using an emission rate of 

0.07lbs NOX/MMBtu, for operation of 

SCR, rather than the 0.05 lbs/MMBtu 

emission rate. 

Response: Our modeling of the 

visibility impacts and benefits of the 

installation of SCR as being NOX BART 

are based on the determination of the 

emission limit technically feasible and 

achievable at the SJGS. This 

determination is discussed in response 

to additional comments received on the 

emission limit achievable by SCR at 

SJGS. 

Comment: We received comments 

that claim that the installation of SCR at 

the SJGS would result in imperceptible 

visibility improvements. 

Response: We performed visibility 

modeling as part of the NOX BART 

determination analysis. A change of 1 

deciview is generally regarded as a 

perceptible change in visibility (70 FR 

39118; July 6, 2005). Our modeling 

indicates that significant improvements 

in visibility are anticipated from the 

installation of SCR to satisfy NOX BART 

requirements. As discussed in the TSD, 

our visibility modeling shows that 

improvement due to installation of SCR 

is significant and at a level that is 

certainly perceptible, including a 3.11 

dv improvement at Canyonlands and 

2.88 dv at Mesa Verde and an 

improvement of 1 deciview or greater at 

7 other Class I areas. Installation of SCR 

will result in significant and perceptible 

visibility improvements at a number of 

Class I areas. 

Furthermore, in a situation where the 

installation of BART may not result in 

a perceptible improvement in visibility, 

the visibility benefit may still be 

significant. ‘‘Failing to consider lessthan-perceptible contributions to 

visibility impairment would ignore the 

CAA’s intent to have BART 

requirements apply to sources that 

contribute to, as well as cause, such 

impairment’’ (70 FR 128; RH 

Regulations and Guidelines for Best 

Available Retrofit Technology (BART) 

Determinations, July 6, 2005). 

Installation of SCR will result in 

significant and perceptible visibility 

improvements at a number of Class I 

areas. However, a perceptible visibility 

improvement is not a requirement of the 

BART determination as a visibility 

improvement that is not perceptible 


jlentini on DSK4TPTVN1PROD with RULES2
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76 Id. 

may still be determined to be 

significant. 

Comment: A commenter asserted that 

EPA’s proposed reductions of NOX

emissions from the SJGS, to satisfy the 

requirements of section 

110(a)(2)(d)(i)(II) of the CAA, are 

excessive and not supported by the 

record. The commenter claimed that 

EPA failed to provide quantitative 

details on how those emissions 

reductions were calculated. 

Furthermore, the emission reductions 

achievable by EPA’s proposed NOX

BART appear to be substantially more 

than the amount of reductions required 

for New Mexico to comply with its 

visibility-related obligation under 

section 110(a)(2)(D)(i)(II). The 

commenter alleges that EPA did not 

provide information on the extent that 

SJGS’s emissions must be adjusted and 

did not provide a straightforward, sideby-side comparison of SJGS’s ‘‘current’’ 

emissions with and without those 

emissions being adjusted by the Agency; 

thus, the actual amounts of the 

emissions ‘‘discrepancies’’ that EPA 

stresses in its preamble are unidentified. 

The commenter challenges EPA’s 

statement that those discrepancies are 

‘‘significant’’ based on ‘‘changes in 

visibility projections’’ and states that 

EPA failed to provide modeling results 

quantifying the visibility impact 

associated with those emission 

‘‘discrepancies.’’ The commenter states 

our ‘‘discrepancies’’ are not differences 

between SJGS’s projected emissions 

used in the WRAP modeling and an 

EPA-adjusted level of ‘‘current’’ 

emissions. Rather, those emissions 

‘‘discrepancies’’ are the differences 

between SJGS’s current levels of NOX

and SO2 emissions used in the WRAP 

modeling and their EPA-adjusted 

counterparts, i.e., current levels of those 

emissions adjusted to values that EPA 

believes should have been used in the 

modeling. The commenter questioned 

how, if New Mexico’s 2002 NOX

emissions were 312,193 tpy (Plan02d) 

and SJGS corresponding emissions were 

30,353 tpy of NOX, only the amount of 

EPA’s adjustment could significantly 

impact out-of-state visibility impairment 

when the State’s total NOX emissions 

will likely be at least 10–100 times 

greater than the ‘‘adjustment’’ amount. 

The commenter then indicated that it is 

impossible to independently evaluate 

the strength of our conclusion regarding 

the extent to which emissions from 

SJGS must be ‘‘adjusted,’’ because the 

specific numbers, which purportedly 

support that Agency conclusion, have 

not been provided. The commenter then 

indicated that a judgment of whether 

EPA’s ‘‘discrepancies’’ are significant 

cannot be evaluated until EPA identifies 

(1) the magnitudes of those 

discrepancies and (2) the resultant 

modeled difference in visibility 

impairment due to those discrepancies. 

The commenter alleges that at no time 

have we specified the amount of 

emissions reductions that may be 

necessary to satisfy New Mexico’s 

obligation under section 

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

commenter estimated the amount of 

NOX reductions in the WRAP modeling 

for the SJGS as 10,590 tpy and then 

approximated the amount of NOX

emission reductions from SJGS under 

EPA’s scheme to prevent New Mexico’s 

‘‘interference’’ as approximately 2,200 

tpy of NOX after considering the consent 

decree reductions of 8,411 tpy since 

2002. They then commented that if 

SJGS’s current (Plan02d) 2002 NOX

emissions are ‘‘adjusted’’ in accordance 

with EPA’s approach, those required 

emission reductions to reach SJGS’s 

projected level used in the WRAP 

modeling would increase by an 

unknown quantity, but they then 

assumed that the discrepancy is 100% 

greater than 2,200 tpy, yielding an 

additional 4,400 tpy NOX reduction 

needed by 2018 to prevent interference. 

Commenter indicated that EPA’s 

proposal under § 110(a)(2)(D)(i)(II) to 

retrofit SJGS’s generating units with 

SCR could achieve roughly 4 times the 

amount of NOX emission reductions 

actually required and EPA’s proposed 

NOX emission reductions from the SJGS 

are excessive. 

Response: We disagree with the 

assertion that EPA must separate the 

required NOX emission reductions 

required by SJGS to meet section 

110(a)(2)(D)(i)(II) requirements from the 

NOX emission reductions required to 

meet the NOX BART determination for 

SJGS. EPA also disagrees that we are 

required to conduct a modeling analysis 

to determine if the NOX reductions 

necessary for SJGS to meet the 

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

would result in significant visibility 

improvement. As we discuss elsewhere 

in this notice, there is no necessity that 

we must evaluate these requirements 

separately and no requirement that we 

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

analysis. See Legal response to 

comments, above, regarding our general 

authority and obligation to act on 

section 110(a)(2)(D)(i)(II) and RH SIP 

requirements. 

The commenter takes issue with the 

fact that we did not specifically quantify 

the difference in emissions between the 

WRAP modeling and what is being 

achieved by SJGS, and explain why the 

discrepancy was believed to be 

significant. We disagree. We provided in 

the proposal and TSD a full discussion 

of how the NOX emissions in the WRAP 

modeling were not being achieved by 

SJGS, and how NOX emissions relied 

upon in the WRAP modeling for the 

SJGS, and agreed upon during 

consultation, are not federally 

enforceable. Therefore, we are 

establishing federally enforceable NOX

emission limits that will eliminate 

interstate interference and at the same 

time address the RH BART requirement 

for NOX for SJGS. The commenter then 

asserts that a side by side comparison 

should have been provided in tons/year. 

We disagree that is necessary to quantify 

this comparison in tons/years. The 

modeling for electric generating units 

(EGUs) may have been reported out as 

tons/year (tpy) in the WRAP emission 

modeling summary tables, but the 

WRAP actual modeling itself used a 

short-term emission rate (i.e., lb/ 

MMBtu). See our other response to 

comment that addresses tpy versus lb/ 

MMBtu modeled emissions in more 

detail. 

In the case of SJGS, the WRAP’s 

photochemical modeling that was 

performed to yield daily (24-hour) 

visibility impairment impacts included 

future emission estimates based on 

emission rates of 0.27 and 0.28 lb of 

NOX/MMBtu and 0.15 lb of SO2/ 

MMBtu. After NMED’s consultation 

with other states, PNM indicated to the 

State that SJGS could not meet the two 

future WRAP emission rates for NOX

without installing additional NOX

controls. PNM claims that the actual 

emission rate was approximately 0.30 lb 

of NOX/MMBtu on a longer-term basis 

as reflected in the permit and 0.33 lb of 

NOX/MMBtu on a short-term basis as 

reflected in PNM’s visibility impact 

modeling for SJGS. PNM and NMED’s 

CALPUFF modeling, conducted to 

estimate daily visibility impairment at 

Class I areas, utilized an emission factor 

rate of 0.33 lb/MMBtu for estimation of 

daily impact as the level that they could 

show compliance on a short-term 

basis.76

We did not model the difference 

between the current enforceable 

emission limits and those emission 

limits relied upon in the WRAP 

modeling for SJGS. We find that New 

Mexico sources, other than the SJGS, are 

sufficiently controlled to eliminate 

interference with the visibility programs 

of other states because the federally 

enforceable emission limits for these 

sources are consistent with those relied 

upon in the WRAP modeling. The SO2

and NOX emissions relied upon in the 


jlentini on DSK4TPTVN1PROD with RULES2
Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 52429 

77 Document that was included in our proposal 

docket, ‘‘Developing the WRAP Point and Area 

Source Emissions Projections for the 2018 

Reasonable Progress Milestone for Regional Haze 

Planning’’, Paula G. Fields, Martinus E. Wolf, Tom 

Moore, Lee Gribovicz. 

WRAP modeling for the SJGS, however, 

are not federally enforceable. Therefore, 

we are establishing federally enforceable 

emission limits for SO2 and NOX for the 

SJGS to eliminate interference with the 

visibility programs of other states. There 

is no requirement to perform a 

110(a)(2)(D)(i)(II) visibility analysis. 

We note that the 98% largest deciview 

impact we modeled using 0.33 lb/ 

MMBtu NOX and 0.15 lb/MMBtu SO2

was 5.15dv at Mesa Verde Class I area. 

We also modeled visibility impacts 

using 0.33 lb/MMBtu NOX and 0.18 lb/ 

MMBtu SO2 in our initial modeling to 

compare model results with those 

presented by PNM and NMED. We note 

that reducing SO2 emissions from 0.18 

to 0.15 lb/MMBtu resulted in a minimal 

change in visibility impacts at all Class 

I areas (0.03 dv at Mesa Verde), 

demonstrating a limited sensitivity to 

changes in SO2 emissions compared to 

the large changes in visibility due to 

decreasing NOX emissions at SJGS, as 

shown in our modeling of the 0.05 lb of 

NOX/MMBtu emission rate (SCR case). 

The use of 0.15 lb/MMBtu SO2 emission 

rate is discussed in a separate response 

to comment. Considering that the 0.33 

lb/MMBtu NOX value is approximately 

20% greater than the 0.27/0.28 rate, the 

significant visibility impacts, and the 

NOX sensitivity demonstrated by the 

modeling, it is clear this difference in 

emission rates can have a significant 

impact on visibility. Even on a longterm basis, the difference between 

relying upon 0.30 lb/MMBtu compared 

to the 0.27/0.28 lb/MMBtu would have 

a significant impact. Although the 

atmospheric chemistry is not strictly 

linear in this case, if modeled, the 

combined difference in NOX and SOX

emission rates would likely result in an 

impact between several tenths of a 

deciview and 1 deciview. Clearly, the 

difference between what was assumed 

by the WRAP and what is actually being 

achieved by the SJGS should not be 

ignored. Since we determined a much 

lower emission rate for BART, we did 

not need to directly evaluate the 

impacts of just achieving the emission 

rate levels included in the WRAP 

modeling. 

The commenter claims that the SJGS 

total emissions in 2002 were 

approximately 10% of the statewide 

New Mexico NOX emission total. The 

commenter implies that the reductions 

found to be needed at SJGS are 

exceedingly small in comparison to the 

total State emissions and therefore 

should not be singled out for control. 

The commenter fails to consider the 

proximity of SJGS to Class I areas and 

the fact that its emissions are 

concentrated relative to the more diffuse 

emissions of many sources in the State, 

such as area and mobile sources. We 

conduct modeling to quantify visibility 

impairment impacts because sources 

that are close to a Class I area and have 

elevated stacks result in greater plume 

impact on the Class I area, and will have 

a greater impact on visibility 

impairment per ton of NOX, compared 

to a much greater tonnage of NOX

emissions from a variety of sources that 

are 100s of kilometers away. Much of 

the New Mexico NOX emissions are 

spread throughout the state and nearer 

to the metropolitan areas of 

Albuquerque and Santa Fe and over 200 

kms from Class I areas in other states, 

in comparison to the SJGS which is just 

42 km from the Mesa Verde Class I area. 

Our modeling indicated that the SJGS 

had a very large impact in our baseline 

emissions modeling (5.15 deciviews at 

Mesa Verde) which highlights why we 

conduct modeling instead of analyzing 

emission ratios, which is apparently 

what the commenter erroneously 

implies we should do. 

The commenter did not provide 

specific details or cite any guidance as 

to how EPA erred in estimating 

emissions for modeling. We disagree 

with the comments that we have 

unfairly adjusted the emission 

calculations to overstate the benefit of 

our proposal. We have conducted our 

calculations consistent with EPA 

methods and guidance, and the WRAP 

EGU modeling projections.77 As 

documented in our TSD, we used the 

most recent materials, including EPRI’s 

spreadsheets, and current EPA guidance 

to estimate emissions for our analyses 

and disagree with the commenter’s 

vague comment that we unfairly 

adjusted the emissions to what we 

thought they should be. 

Comment: We received comments 

from the NPS and USFS supporting the 

reporting of the cumulative visibility 

impact of SJGS and the cumulative 

benefits of SCR. NPS and USFS believe 

it is appropriate to consider both the 

degree of visibility improvement in a 

given Class I area as well as the 

cumulative effects of improving 

visibility across all of the Class I areas 

affected. The BART guidelines do not 

consider the geographic extent of 

visibility impairment. NPS and USFS 

believe the most practical approach to 

this problem is to consider the 

cumulative impacts of a source on all 

Class I areas affected, as well as the 

cumulative benefits from reducing 

emissions. They state that cumulative 

benefits have been a factor in the BART 

determinations by Oregon and 

Wyoming, as well as EPA in its 

proposals for the Navajo Generating 

Station and the Four Corners Power 

Plant. They also note that the 

improvements in visibility impairment 

due to reductions in NOX emissions in 

other analyses have been largest at Class 

I areas other than the closest Class I 

area, therefore evaluation of all Class I 

areas within the modeling domain is 

appropriate. 

Several commenters were opposed to 

the use of a ‘‘cumulative deciviews’’ or 

‘‘total’’ visibility improvement metric. 

These commenters claim that the 

’’cumulative deciviews’’ metric is 

misleading and that the modeling 

impact improvements would take place 

at different locations within a Class I 

area, within different Class I areas, and 

probably on different dates so a 

‘‘cumulative deciviews’’ result would 

not be observed by one viewer. They 

continued that one viewer would not 

perceive visibility impacts in more than 

one Class I area simultaneously, or even 

within relatively short periods of time, 

in nearly every case. Furthermore, the 

visibility impacts to a region should not 

depend on the number of Class I areas 

present. The commenters state it is 

improper to consider a ‘‘cumulative’’ 

deciview improvement over more than 

one Class I area. 

The commenters also suggest that the 

use of a ‘‘total dv’’ metric is inconsistent 

with BART guidelines (40 CFR part 51 

Appendix Y, IV.D.5). The guidelines 

state that it is appropriate to model 

impacts at the nearest Class I area as 

well as other nearby Class I areas to 

determine where the impacts are 

greatest. Modeling at other Class I areas 

may be unwarranted if the highest 

modeled effects are observed at the 

nearest Class I area. The commenters 

claim the analysis should be focused on 

the visibility impacts at the most 

impacted area, not all areas. The 

commenters add that states have already 

successfully dealt with this practice. To 

illustrate, they point to the Colorado Air 

Quality Control Commission declining 

to take a ‘‘cumulative’’ approach to 

deciviews, even though commenters 

had argued the concept should 

influence decision making about BART. 

Response: We agree with the NPS and 

the USDA Forest Service on the utility 

of a cumulative visibility metric in 

addition to the other visibility metrics 

we utilized and we do not agree that our 

approach is inconsistent with BART 

guidelines. Our visibility modeling 

shows that a number of Class I areas are 


jlentini on DSK4TPTVN1PROD with RULES2
52430 Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 

78 70 FR 39170. 

79 70 FR 39118. Impacts of 1 deciview or greater 

are considered to cause a visibility impairment. 

80Revised IMPROVE algorithm for Estimating 

Light Extinction from Particle Speciation Data, 

IMPROVE, January 2006 (http:// 

vista.cira.colostate.edu/improve/Publications/ 

GrayLit/gray_literature.htm) ; Hand, J.L., Douglas, 

S.G., 2006, Review of the IMPROVE Equation for 

Estimating Ambient Light Extinction Coefficients— 

Final Report (http://vista.cira.colostate.edu/ 

improve/Publications/GrayLit/ 

016_IMPROVEEeqReview/IMPROVEeqReview.htm). 

individually and significantly impacted 

by emissions from the SJGS. The 

number of days per year significantly 

impacted by the facility’s NOX

emissions is expected to decrease 

drastically at each Class I area (Table 6– 

8 of the TSD) as the result of installation 

of NOX BART emission controls at the 

SJGS. Clearly, the visibility benefits 

from NOX BART emission reductions 

will be spread among all affected Class 

I areas, not only the most affected area, 

and should be considered in evaluation 

of benefits from proposed reductions. 

The portion of the BART Guidelines 

(40 CFR 51 Appendix Y, IV.D.5) that the 

commenter referenced states: ‘‘If the 

highest modeled effects are observed at 

the nearest Class I area, you may choose 

not to analyze the other Class I areas any 

further as additional analyses might be 

unwarranted.’’ 78 This section of the 

BART Guidelines addresses how to 

determine visibility impacts as part of 

the BART determination. Several 

paragraphs later in the BART Guidelines 

it states: ‘‘You have flexibility to assess 

visibility improvements due to BART 

controls by one or more methods. You 

may consider the frequency, magnitude, 

and duration components of 

impairment,’’ emphasizing the 

flexibility in method and metrics that 

exists in assessing the net visibility 

improvement. 

As discussed in a separate response to 

comment, for any CALPUFF visibility 

modeling in a SIP, a protocol addressing 

procedures and analyses should be 

determined with the appropriate 

reviewing authority and affected FLMs. 

As identified in the BART Guidelines, 

an important element of the modeling 

protocol is the choice of receptors used 

in the model, and the decision of when 

additional analyses including modeling 

the effects at Class I areas beyond the 

nearest area are warranted and 

necessary. As indicated in the TSD and 

RTC for this notice, we conferred with 

EPA OAQPS and FLM representatives 

on the details of conducting the 

CALPUFF modeling in this action, and 

concluded, like PNM and NMED 

previously concluded in their 2009 

modeling, that because of the size of the 

source and the number of Class I area 

potentially affected, we should evaluate 

modeling receptors at all Class I areas 

within 300 km of the source. We also 

received comments from FLM 

representatives supporting the way we 

conducted our modeling including our 

evaluation of multiple Class I areas. 

Our baseline modeling indicated that 

visibility impacts from the SGJS were 

above 0.5 deciviews at all 16 Class I 

areas within 300km of the SJGS and 

above 1 deciview at 14 of the 16 Class 

I areas.79 These significant visibility 

impacts support the conclusion that 

further analyses were warranted. In this 

specific case, our analysis indicated the 

largest baseline impact was at the 

closest Class I area (Mesa Verde) but 

also indicated very large impacts at 

other Class I areas. In fact, we found that 

the largest overall decrease in visibility 

impact resulting from the proposed NOX

emission reductions occurred at a much 

more distant Class I area (Canyonlands). 

Therefore, had we stopped our analysis 

after modeling the visibility 

improvement at Mesa Verde, we would 

not have discovered that the largest 

visibility improvement is predicted to 

occur elsewhere. 

In fully considering the visibility 

benefits anticipated from the use of an 

available control technology as one of 

the factors in selection of NOX BART, it 

is appropriate to account for visibility 

benefits across all affected Class I areas 

and the BART guidelines provide the 

flexibility to do so. One approach as 

noted above is to qualitatively consider, 

for example, the frequency, magnitude, 

and duration of impairment at each and 

all affected Class I areas. Where a source 

such as the SJGS significantly impacts 

so many Class I areas on so many days, 

the cumulative ‘total dv’ metric is one 

way to take magnitude of the impacts of 

the source into account. 

Therefore, under the BART 

Guidelines, and based upon these facts, 

we decided additional analyses were 

not only warranted but necessary. The 

BART Guidelines only indicate that 

additional analyses may be unwarranted 

at other Class I areas, and in no way 

exclude such analyses, as the 

commenter suggests. We concluded that 

a quantitative analysis of visibility 

impacts and benefits at only the Mesa 

Verde area would not be sufficient to 

fully assess the impacts of controlling 

NOX emissions from the SJGS. 

Again, nothing in the RHR suggests 

that a state (or EPA in issuing a FIP) 

should ignore the full extent of the 

visibility impacts and improvements 

from BART controls at multiple Class I 

areas. Given that the national goal of the 

program is to improve visibility at all 

Class I areas, it would be short-sighted 

to limit the evaluation of the visibility 

benefits of a control to only the most 

impacted Class I area. As noted 

previously, NMED and PNM’s BART 

analyses also presented visibility impact 

and improvement projections at all 16 

Class I areas. We believe such 

information is useful in quantifying the 

overall benefit of BART controls. 

Comment: A commenter disagreed 

with our use of the revised IMPROVE 

equation (Method 8) post-processing 

methodology for the CALPUFF model 

results to calculate visibility impairment 

for the SJGS NOX BART determination 

from predicted pollutant concentrations. 

To be consistent with the WRAP 

modeling, the commenter claims we 

instead should have used the original 

IMPROVE equation (Method 6). The 

commenter further alleges that our use 

of Method 8 resulted in much higher 

visibility impacts and improvements 

than would have been predicted using 

Method 6. The commenter also claims 

that our NOX BART modeling analysis 

is internally inconsistent because we 

rely on Method 6 for SO2 (using the 

WRAP modeling) and on Method 8 

modeling for NOX. Furthermore, the 

commenters assert that the use of 

Method 8 is generally justified by EPA 

by referring to the ‘‘regulatory version,’’ 

however, Method 8 processing is not 

supported by the ‘‘regulatory version’’ 

EPA used in its analysis. 

Response: Method 6 and Method 8 

refer to two different versions of 

algorithms used to estimate visibility 

impairment from pollutant 

concentrations. Method 8 is a more 

recently available, more refined version 

of the original equation and is now 

considered by us and FLM 

representatives to be the better approach 

to estimating visibility impairment. 

Compared to the original IMPROVE 

equation, this revised IMPROVE 

equation has less bias, accounts for 

more pollutants, incorporates more 

recent data, and is based on 

considerations of relevance for the 

calculations needed for assessing 

progress under the RHR.80 We are aware 

that Method 8 tends to show more 

improvement in visibility than Method 

6 when reductions in very small 

particles are achieved, such as those 

that are formed by emissions of NOX. 

We believe that this, however, more 

accurately reflects real visibility 

conditions. 

We are also aware that at the time the 

States were working together in the 

WRAP to develop their RH SIPs, 

Method 6 was widely employed to 

develop RPGs and for initial BART 


jlentini on DSK4TPTVN1PROD with RULES2
Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 52431 

81U.S. EPA. Additional Regional Haze Questions. 

U.S. Environmental Protections Agency. August 3, 

2006, available at http://www.wrapair.org/forums/

iwg/documents/Q_and_A_for_Regional_Haze_8-03-

06.pdf#search=%22%22New%20IMPROVE%

20equation%22%22; WRAP presentation, ‘‘Update 

on IMPROVE Light Extinction Equation and Natural 

Conditions Estimates’’ Tom Moore, May 23, 2006; 

U.S. Forest Service, National Park Service, and U.S. 

Fish and Wildlife Service. 2010. Federal land 

managers’ air quality related values work group 

(FLAG): phase I report—revised (2010). Natural 

Resource Report NPS/NRPC/NRR—2010/232. 

National Park Service, Denver, Colorado. 

82U.S. Forest Service, National Park Service, and 

U.S. Fish and Wildlife Service. 2010. Federal land 

managers’ air quality related values work group 

(FLAG): phase I report—revised (2010). Natural 

Resource Report NPS/NRPC/NRR—2010/232. 

National Park Service, Denver, Colorado, available 

at http://www.nature.nps.gov/air/Pubs/pdf/flag/

FLAG_2010.pdf. 

83Comparison of model results presented by 

commenter with values in our TSD Chapter 6. 

analyses. By the time Method 8 was 

widely available, some States were far 

enough along in their SIP development 

that a switch to the newer method 

would have been disruptive. Because of 

this, we did not object to the use of 

Method 6 in the WRAP photochemical 

modeling or subject-to-BART screening 

modeling. In the case of New Mexico, 

Method 6 was used in WRAP modeling 

to determine which sources are subject 

to BART. Using Method 6, New Mexico 

determined that the SJGS was subject to 

BART because of its significant impact 

on Class I areas. We reached the same 

conclusion using either Method 6 or 

Method 8 in our modeling. New Mexico 

and the other WRAP States also used 

Method 6 to develop reasonable 

progress goals for the Class I areas in the 

region. 

For the purposes of ensuring that New 

Mexico’s emissions do not interfere 

with other States’ plans for visibility 

improvement, the choice of IMPROVE 

Method is not relevant. The commenter 

seems to imply that because the WRAP 

modeling largely used Method 6, we 

should use Method 6 for all our 

analyses, including our source specific 

analyses for NOX BART. However, 

regardless of which IMPROVE equation 

is used, New Mexico did not provide 

federally enforceable limitations on 

SJGS’ SO2 and NOX emissions to 

achieve the reductions expected by 

other States. Without these reductions, 

other States will not achieve the 

progress at their Class I areas which 

they expected under the collaborative 

WRAP process. 

As discussed previously, we have 

concluded that it is appropriate to 

address the requirements for NOX BART 

for SJGS at the same time we address 

New Mexico’s obligations under the 

visibility prong of 110(a)(2)(D)(i). As 

part of the BART analysis, we 

performed CALPUFF modeling to assess 

the impacts of the NOX BART proposed 

controls on the single source at issue on 

visibility impairment. Because Method 

8 is the preferred method for analyses 

being conducted at this time,81 we 

estimated the CALPUFF visibility 

impacts using this peer reviewed 

algorithm. We also evaluated modeling 

results using Method 6 to quantify the 

sensitivity of our results to the choice in 

visibility impairment algorithm. We 

note that using either Method 8 or 

Method 6, substantial visibility benefits 

were projected for the installation of 

SCR and support the conclusion that 

SCR is the appropriate BART control. 

We disagree with the comment 

concerning Method 8 and the 

‘‘regulatory version’’ of the model. 

CALPOST is the post-processing tool 

used to apply an algorithm to estimate 

visibility impairment from pollutant 

concentrations from CALPUFF. We 

determined CALPOST version 6.221, 

which includes the option to apply 

either the Method 6 or the Method 8 

algorithm, was the appropriate 

CALPOST version for our analysis. 

Since we determined Method 8 was the 

better method for estimating 

impairment, we chose to use the version 

of CALPOST that allowed the 

calculation using either Method 6 or 

Method 8. We note that this CALPOST 

version was approved and supported by 

the FLMs to allow for application of the 

revised IMPROVE equation (‘‘Method 

8’’).82 As discussed in more detail in a 

separate response to comment in this 

Section N and our Complete Response 

to Comments for NM Regional Haze/ 

Visibility Transport FIP document, the 

ultimate decision on the acceptable 

model version, formulation, and set-up 

of CALPUFF and CALPOST for 

visibility modeling is our responsibility 

in a FIP situation. 

Comment: We received a number of 

comments concerning the version of the 

CALPUFF modeling system EPA has 

used. We utilized CALPUFF Version 5.8 

suite for visibility modeling. The 

commenter indicated revised CALPUFF 

model Versions 6.112 and 6.4 are 

available and submitted modeling 

analyses using these versions of 

CALPUFF with the suggestion that their 

modeling should be used instead of 

ours. A number of commenters stated 

that Version 5.8 is outdated and 

overestimates visibility impacts. The 

commenters argue that the latest 

version, CALPUFF Version 6.4, which 

includes updated chemistry and 

technical enhancements to improve the 

model’s performance and accuracy, 

should be used to evaluate visibility 

impacts. They alleged that this version 

includes updated chemistry that is more 

robust and performs better and technical 

enhancements to improve the model’s 

performance and accuracy. 

Additionally, commenters included 

information on a February 16, 2011 

meeting held with the EPA in Research 

Triangle Park (RTP), North Carolina 

along with representatives of the 

western states utility organization 

WEST Associates, the American 

Petroleum Institute (API), and TRC (the 

developer of CALPUFF). The FLMs 

participated in this meeting by 

teleconference. It was agreed at the 

meeting that the FLMs will take the lead 

on a review and testing of the CALPUFF 

model code changes including the new 

chemistry modules, and Model Change 

Bulletins (MCBs) and coordinate with 

EPA. 

Response: The commenter indicated 

that a revised version of the model is 

available and submitted modeling 

analyses using CALPUFF model 

Versions 6.112 and 6.4. Comments 

received justifying the use of these 

versions of CALPUFF alleged that they 

were more scientifically robust and 

included updated chemistry and 

technical enhancements to improve the 

model’s performance and accuracy. We 

disagree that the newer versions of 

CALPUFF should be used in this action 

to determine potential visibility 

impacts. The newer version(s) of 

CALPUFF have not received the level of 

review required for use in regulatory 

actions subject to EPA approval and 

consideration in a BART decision 

making process. Based on our review of 

the available evidence we do not 

consider the models to have been shown 

to be sufficiently documented, 

technically valid, and reliable for use in 

a BART decision making process. In 

addition, the available evidence would 

not support approval of these models for 

current regulatory use. There are known 

technical problems with CALPUFF 

6.112 and furthermore, the development 

of new model versions requires 

technical and policy evaluations to 

ensure the models meet regulatory 

requirements. 

The commenter’s modeling using 

different model versions with as yet 

unapproved mechanisms and the nonguideline techniques indicated different 

results than past modeling submitted by 

PNM and the results of our modeling of 

SJGS.83 The visibility impacts of their 

modeling results are much lower 

compared to results of past PNM, NMED 

and EPA modeling. These discrepancies 

are large enough to lend further 


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84 70 FR 39123, 39124. ‘‘We understand the 

concerns of commenters that the chemistry modules 

of the CALPUFF model are less advanced than 

some of the more recent atmospheric chemistry 

simulations. To date, no other modeling 

applications with updated chemistry have been 

approved by EPA to estimate single source 

pollutant concentrations from long range 

transport.’’ and in discussion of using other models 

with more advanced chemistry it continues, ‘‘A 

discussion of the use of alternative models is given 

in the Guideline on Air Quality in appendix W, 

section 3.2.’’ 

85EPA report, ‘‘Assessment of the VISTAS 

Version of the CALPUFF Modeling System’’, EPA– 

454/R–08–007, August 2008 available at (http:// 

www.epa.gov/ttn/scram/reports/ 

calpuff_vistas_assessment_report_final.pdf). 

credence to the need for a full review of 

the revised modeling systems before 

considering the modeling results for any 

decision making.84 85 EPA was fully 

justified in following its modeling 

approach, which was consistent with 

current EPA and FLM guidelines, as 

well as similar to modeling recently 

performed by NMED and PNM. EPA 

used the approved version of the model 

in accordance with the appropriate 

procedures, as discussed further in 

other response to comments and is 

confident in using our results as one of 

the five factors in making a BART 

determination. 

In considering the comment that we 

should use the latest version of 

CALPUFF (6.4) or an earlier version 

6.112, we considered the regulatory 

status of CALPUFF for visibility 

analyses and what analyses are needed 

to utilize an updated CALPUFF 

modeling system. The requirements of 

40 CFR 51.112 and 40 CFR part 51, 

Appendix W, Guideline on Air Quality 

Models (GAQM) and the BART 

Guidelines which refers to GAQM as the 

authority for using CALPUFF, provide 

the framework for determining the 

appropriate model platforms and 

versions and inputs to be used. Because 

of concern with CALPUFF’s treatment 

of chemical transformations, which 

affect AQRVs, EPA has not approved the 

chemistry of CALPUFF’s model as a 

‘preferred’ model. The use of the 

regulatory version is approved for 

increment and NAAQS analysis of 

primary pollutants only. Currently 

CALPUFF Version 5.8, is subject to the 

requirements of GAQM 3.0(b) and as a 

screening model, GAQM 4. CALPUFF 

Versions 6.112 and 6.4 have not been 

approved by EPA for even this limited 

purpose. 

Under the BART guidelines, 

CALPUFF should be used as screening 

tool and appropriate consultation with 

the reviewing authority is required to 

use CALPUFF in a BART determination 

as part of a SIP or FIP. The BART 

Guideline cited and referred to EPA’s 

GAQM which includes provisions to 

obtain approval through consultation 

with the reviewing authority. Moreover, 

we also note that in EPA’s document 

entitled Guidance on the Use of Models 

and Other Analyses for Demonstrating 

Attainment of Air Quality Goals for 

Ozone, PM2.5, and Regional Haze 

(EPA–454/B–07–002), that Appendix W 

does not identify a particular modeling 

system as ‘preferred’ for modeling 

conducted in support of state 

implementation plans under 40 CFR 

51.308(b). A model should meet several 

general criteria for it to be a candidate 

for consideration. These general criteria 

are consistent with the requirements of 

40 CFR 51.112 and 40 CFR 51, 

Appendix W. Therefore, it is correct to 

interpret that no model system is 

considered ‘preferred’ under 40 CFR 51, 

Appendix W, Section 3.1.1 (b) for either 

secondary particulate matter or for 

visibility assessments. Under this 

general framework, we followed the 

general recommendation in Appendix Y 

to use CALPUFF as a screening 

technique since the modeling system 

has not been specifically approved for 

chemistry. The use of CALPUFF is 

subject to GAQM requirements in 

section 3.0(b), 4, and 6.2.1(e) which 

includes an approved protocol to use 

the current 5.8 version. 

As noted previously, the summary of 

results provided by the commenter 

indicate much lower results compared 

to the current regulatory approved 

version of the modeling system. The 

significant difference in results is an 

indicator that there are important 

changes in the science between these 

new versions and the current EPA 

version. We must have a full 

understanding of these changes before 

‘approving’ their use. The information 

provided indicates the new science 

includes chemistry for which this model 

was never approved so these changes 

would necessitate a notice and comment 

rulemaking and not a simply update as 

previously done for this model to 

address bug-fixes and the like. We 

believe that with such modifications to 

the modeling system, CALPUFF 

(Version 6.4) used in this manner could 

no longer be considered a screening 

technique under Section 4 of GAQM. 

The CALPUFF Version 6.112 would be 

considered an alternative model and 

would be subject to the requirements of 

Section 3.2 of GAQM. As covered in 

more thorough detail below and in our 

RTC, these alternate versions of 

CALPUFF (6.112 and 6.4) are subject to 

the provisions of GAQM. 

Based on the technical information 

that has been provided, these model 

versions could not be approved because 

the information provided is not 

sufficient and does not comport with 

the requirements of Section 3.2, 

including 3.2.2(b)(3) and (e), of GAQM. 

The model developer has relied upon 

several articles (Escoffier-Czaja and 

Scire, 2007; and Scire, et al., 2003) 

which describe the general reliability of 

the CALPUFF modeling system and 

post-processing techniques for use in 

visibility assessments. Based on our 

review of this information, we do not 

believe it provides sufficient 

information for EPA to assess the 

suitability of the newer versions of the 

modeling system as would be done in 

reviewing models in accordance with 

GAQM Section 3.2.2(e) requirements. 

First, it is important to understand 

that each of the papers were presented 

as part of general proceedings at 

conferences, and therefore do not reflect 

the thoroughness of a formal peer 

review process that would be associated 

with submission to mainline scientific 

journals. Therefore, we do not consider 

these references suitable for establishing 

the validity of the model or postprocessing techniques or demonstrating 

that these models have undergone 

independent scientific peer review as 

necessary for reviewing models in 

accordance with Section 3.2.2(e)(i) of 

GAQM. 

Second, the evaluation techniques 

utilized by the developer are not 

appropriate for evaluation of the 

chemical mechanisms of the CALPUFF 

system. Appendix A.3 of GAQM 

describes CALPUFF as generally 

considered suitable for treatment of 

dispersion of non-reactive pollutants 

from a single source or small group of 

sources for distances beyond 50-km to 

200- to 300-km. CALPUFF usage, in the 

context of the Southwestern Wyoming 

Air Quality Task Force (SWWYTAF) 

modeling dataset presented in both 

Escoffier-Czaja and Scire (2007) and 

Scire et al. (2003), is treated as a full 

photochemical modeling system such as 

the Comprehensive Air Quality Model 

with Extensions (CAMx) or the 

Community Multiscale Air Quality 

Model (CMAQ). However, the 

evaluation techniques presented in the 

aforementioned references evaluate the 

model as a near-field dispersion model, 

presenting information on sulfate and 

nitrate performance in quantile-quantile 

plots (Q–Q plots) only for the BridgerTeton IMPROVE monitoring site. This 

technique is not satisfactory for 

purposes of model performance 

evaluations for full science chemistry 

models. Recommended methods and 

metrics for evaluation of photochemical 

models are discussed at length in EPA’s 

Guidance on the Use of Models and 


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86 ‘‘Most important, the simplified chemistry in 

the model tends to magnify the actual visibility 

effects of that source. Because of these features and 

the uncertainties associated with the model, we 

believe it is appropriate to use the 98th percentile— 

a more robust approach that does not give undue 

weight to the extreme tail of the distribution.’’ 70 

FR 39104, 39121. 

87Comment Letter from EPA Region 6 to TCEQ 

dated February 13, 2007 regarding TCEQ Final 

Report ‘‘Screening Analysis of Potential BARTEligible Sources in Texas’’, December 2006. 

88 GAQM (2005 update) part 3.0(b), and 4.2.1.1 

and 4.2.1.2. Section 4 dealing with screening 

versions of modeling analyses was updated in the 

2005 GAQM notice. 

89Personal communications with Mr. Tyler Fox 

to verify guidance given at meeting pertaining to 

alternate CALPUFF versions. July 29, 2011. 

Other Analyses for Demonstrating 

Attainment of Air Quality Goals for 

Ozone, PM2.5, and Regional Haze (EPA– 

454/B–07–002). Therefore, we do not 

consider the analysis techniques 

presented by the model developer 

sufficient to demonstrate that the model 

is not biased, as would be done to 

justify use of a model in accordance 

with Section 3.2.2(e)(iv) of GAQM. 

Finally, no modeling files were 

provided for review, no protocol or 

other complete documentation was 

provided outlining the methods and 

procedures of operating the alternative 

model in agreement with the 

appropriate reviewing authority (EPA 

Region 6) prior to submission of 

comments, contrary to requirements of 

Section 3.2.2(e)(v) of GAQM. 

Therefore, on the basis of available 

information submitted to the public 

record, we could not approve the use of 

the alternative model versions in 

accordance with Section 3.2.2(e) 

requirements of GAQM. We believe our 

modeling accurately describes the 

visibility impacts of the SJGS, the 

benefits of BART controls, and was 

based on established and wellrecognized methods. 

It would be problematic for us to 

allow the use of any unapproved model 

variants with potentially significant 

changes to chemistry treatment without 

additional information regarding the 

model’s formulation, performance, and 

acceptability. In promulgating the BART 

guidelines we made the decision in the 

final BART Guideline to recommend 

that the model be used to estimate the 

98th percentile visibility impairment 

rather than the highest daily impact 

value as proposed. We made the 

decision to consider the less 

conservative 98th percentile primarily 

because the chemistry modules in the 

CALPUFF model are simplified and 

likely to provide conservative (higher) 

results for peak impacts. Since 

CALPUFF’s simplified chemistry could 

lead to model over predictions and thus 

be conservative, EPA decided to use the 

less conservative 98th percentile.86 The 

modeling that PNM’s contractor 

performed for PNM was based on 

CALPUFF versions that have been 

updated with an allegedly more robust 

chemistry and purportedly performs 

better according to the commenter than 

the current version of the model 

approved for regulatory actions 

(CALPUFF version 5.8). If these versions 

of CALPUFF can be shown to be reliable 

and acceptable to EPA, it would likely 

be appropriate to the use Highest Daily 

impact (1st High instead of the 8th 

High) based on the presumption that the 

updated chemistry of CALPUFF model 

would result in less conservative results 

than Version 5.8. In past agreements in 

using the CAMx photochemical model, 

which has a robust chemistry module, 

the Region has recommended the use of 

the 1st High value when sources were 

being screened out of a full BART 

analysis based on the CAMx results.87

The current version of CALPUFF 

approved for regulatory action was last 

updated by EPA on June 29, 2007. The 

CALPUFF modeling system approved at 

that time included CALPUFF version 

5.8, level 070623, CALMET version 5.8 

level 070623, and CALPOST version 

5.6394, level 070622. CALPUFF is still 

considered a screening model for 

visibility assessments. Therefore, we 

followed the requirements of Appendix 

W for screening models in our 

modeling.88 We conducted our 

modeling with the version 5.8 suite with 

a few exceptions that were discussed 

among modeling experts from EPA 

Region 6, EPA/OAQPS and FLM 

representatives. Our modeling 

procedures were discussed more fully in 

our TSD. 

We note that the CALPUFF Versions 

6.4 and 6.112 have not been reviewed 

by EPA for potential regulatory use. 

PNM’s contractor has indicated that a 

meeting was held with EPA/OAQPS 

representatives on Feb. 16, 2011 and 

FLM representatives participated via 

conference call. The commenter 

indicates that EPA was going to let the 

FLM representatives take the lead on 

review and testing of the new version of 

CALPUFF (6.4) and coordinate with 

EPA regarding this issue. Mr. Tyler Fox, 

Group Leader of the Air Quality 

Modeling Group at EPA/OAQPS has 

indicated that EPA will take the lead on 

the review of the new version 

(CALPUFF Version 6.4) and that the 

new addition of a more sophisticated 

chemistry mechanism is a paradigm 

shift in treatment of chemistry in 

CALPUFF and requires additional rule 

making and public review since 

CALPUFF was never approved for 

chemistry in the GAQM and EPA is 

currently evaluating several models to 

address current modeling needs for 

models that can be used for analyses of 

secondary formation pollutants for 

ozone, PM2.5 secondary, and regional 

haze/visibility impairment.89 At this 

time, EPA and the FLM representatives 

are in the process of planning to move 

forward on reviewing all available 

models to determine their suitability for 

these analyses. We note that we have 

reviewed the materials shared at the 

meeting and discussed the planned 

steps forward from the meeting, but that 

CALPUFF Versions 6.4 and 6.112 have 

still not been evaluated to determine 

their suitability for use in various 

contexts. 

Based on the applicable GAQM and 

BART Guidelines regulations, the 

combination GAQM (2005) citations 

(6.2.1(e) and 3.0(b)), and the BART 

Guidelines outline that for any visibility 

modeling performed with the CALPUFF 

model in a SIP, a protocol addressing 

procedures and analyses should be 

developed with the appropriate 

reviewing authority and affected FLMs. 

Approval of an alternate model usually 

includes consultation with the modeling 

group at EPA/OAQPS even though 

ultimate authority in most cases is the 

Regional Office. In the case of a SIP or 

a FIP, the EPA Regional Office has the 

final approval decision on what 

constitutes appropriate/acceptable 

modeling. Development of an acceptable 

protocol with a Regional Office for 

review and approval of an alternative 

model (i.e. updated model version, etc.) 

can be a very significant task and could 

take 6 months to a year or longer to 

complete a protocol that detailed 

submission of information for review 

including model sensitivity runs, 

evaluation of model performance, etc., 

so this can be a sizable hurdle in order 

for EPA to ensure that we are basing 

decisions on sound science and the best 

tools for actions. Approval of updated 

CALPUFF versions has been such a 

large task that EPA/OAQPS has 

typically taken the lead in approval of 

CALPUFF updates for regulatory use. In 

this case, PNM did not work out a 

protocol to address any of these needed 

elements for EPA Region 6 to conduct 

a review of PNM’s proposed use of an 

alternate model and the modeling 

results. The new versions of CALPUFF, 

version 6.112 or 6.4, that the commenter 

used to provide modeling analyses have 

not gone through a full regulatory 

review in accordance with 40 CFR part 

51 Appendix W Section 3.2.2. 


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52434 Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 

90Sather, et al. ‘‘Baseline ambient gaseous 

ammonia concentrations in the Four Corners area 

and eastern Oklahoma, USA,’’ Journal of 

Environmental Monitoring (September 2008) (‘‘The 

Sather 2008 report’’). 

Furthermore, the currently available 

information does not support the 

approval of these versions of the 

CALPUFF model for use in making 

BART determinations. In addition, if 

these versions of the model were used, 

EPA would have to reconsider whether 

using the 98th percentile impact for 

determining impairment was 

appropriate. Therefore, EPA does not 

believe the use of CALPUFF version 

6.112 or 6.4 is appropriate for this 

rulemaking. We believe we have made 

the appropriate choice in using 

CALPUFF version 5.8. 

Comment: The USDA Forest Service 

(USFS) provided comments supporting 

our assumptions regarding the value of 

the background ammonia (a constant 1.0 

ppb concentration) used for the 

visibility analysis. In contrast, PNM 

claims that the use of variable monthly 

ammonia values ranging from 0.2 ppb in 

the winter months to 1.0 ppb during the 

summer would better reflect the 

seasonal variations in ammonia 

concentrations than would a constant, 

assumed ammonia concentration. PNM 

further argued that the use of variable 

monthly ammonia concentrations 

would still be conservative. Therefore, 

PNM alleges, since a variable monthly 

ammonia scheme is more representative 

and conservative, it should be used 

instead of EPA’s constant ammonia 

levels. PNM also claims that the use of 

the Ammonia Limiting Method (ALM) is 

appropriate given the ‘‘conservatism 

(averaging about a factor of two) of the 

assumed ammonia relative to 

observations.’’ PNM further comments 

that our supporting documentation also 

states that ‘‘alternative levels may be 

used if supported by data’’ and therefore 

we have no basis for criticizing the 

variable, monthly ammonia levels used 

in the modeling prepared by PNM. PNM 

further comments that EPA’s decision to 

rely on constant high background 

ammonia concentrations unjustifiably 

results in higher visibility 

improvements than expected by PNM’s 

more realistic modeling results. 

Response: We agree and concur with 

the use of the 1 ppb ammonia levels 

from USFS representatives. We disagree 

with the comments supporting the use 

of variable, monthly ammonia 

concentrations. There are several factors 

to consider with selecting the 

appropriate ammonia background for 

estimating visibility impacts, including 

the length and temporal resolution of 

the ammonia data collected, whether 

the ammonia data varies depending on 

location of collection in comparison to 

proximity of SJGS plumes, the 

fluctuation of levels throughout the 

year, and the importance of plume 

chemistry from the point of NOX and 

SO2 emissions that react with emitted 

and background ammonia as the plumes 

transport to downwind receptors. We 

have examined the available ammonia 

data collected, including the data cited 

to in the comments.90 Our selection of 

the IWAQM Phase 2 default ammonia 

background constant value of 1 ppb 

(rather than the variable monthly 

ammonia concentrations suggested by 

the commenter) better represents 

ammonia concentrations directly 

around the SJGS emission sources. The 

ammonia near the source that is 

available to interact with the plume as 

it is emitted is of greater concern for 

determining visibility impacts from the 

source due to the atmospheric chemical 

reactions that occur as the pollutants 

and ammonia are transported together to 

a Class I area. Therefore, it is more 

appropriate to use a background level 

for ammonia that is representative of the 

area around the source rather than the 

ammonia levels at the isolated 

downwind Class I areas. 

The pollutants emitted by the source, 

such as sulfate and nitrate, will react 

with available ammonia present near 

the release point and this ammonia and 

ammonia reaction products will be 

transported along with the emitted 

pollutants to the downwind receptors. 

The available monitoring data indicates 

that ammonia levels are higher around 

the SJGS emission sources and decrease 

at Mesa Verde, thus supporting that 

conclusion that when SJGS plumes are 

transported to Mesa Verde (and other 

Class I areas), as expected, the SJGS 

emissions react with ammonia levels 

near the SJGS resulting in decreasing 

ambient ammonia levels downwind 

from the SJGS. The annual average 

ammonia values at the Substation and 

Farmington sites, which are the passive 

monitor readings that are closest to the 

SJGS, are above the 1 ppb levels that we 

have chosen to model. This supports 

our decision to use a constant 1.0 ppb 

ammonia value as being representative 

of the area around the source rather than 

the ammonia levels at the isolated 

downwind Class I areas. Therefore, the 

level we modeled is more appropriate. 

As discussed originally in the TSD and 

also in our Complete Response to 

Comments for NM Regional Haze/ 

Visibility Transport FIP document, we 

have taken into consideration the issues 

raised by the commenter and conferred 

with the author of the 2008 Sather 

report, and concluded that the ammonia 

levels we used in the model are 

appropriate. 

We disagree with the use of the ALM. 

There is a lack of documentation, 

adequate technical justification, and 

validation for the development and use 

of the ALM. This is discussed further in 

a separate response to comments. 

Comment: PNM contracted with Mr. 

Joe Scire to review and prepare a report 

on PNM’s BART modeling submitted to 

NMED during its 2010 state proposed 

rulemaking process. PNM included this 

Report as part of its comments to EPA. 

PNM asserts that the Report confirms 

that PNM’s modeling was consistent 

with the methodology developed for 

CALPUFF and it was prepared 

consistent with the WRAP protocol for 

BART modeling and the WRAP BART 

modeling. The commenter argues that 

since EPA has accepted the WRAP 

modeling and used it to support its own 

positions with regard to SO2 in the 

proposed FIP, and given the fact that 

PNM’s modeling was prepared in a 

manner consistent with the WRAP 

modeling, EPA should not need to alter 

PNM’s modeling. Moreover, the 

modeling results achieved by us are 

merely a function of our modeling 

methods, not true differences in 

visibility impacts. 

In addition to the commenter’s 

position that the PNM modeling was 

conducted appropriately, PNM claims 

that the Report shows more recent 

developments in modeling science and 

chemistry could be used to make a more 

accurate and realistic prediction of the 

visibility improvements that might 

result from installing SCRs at SJGS. The 

recommendations included modeling 

results from the use of (1) two updated 

CALPUFF models, Ver. 6.112 and a 

version with updated chemistry (Ver. 

6.4); (2) a refined modeling grid (1 km 

versus 4 km), and (3) Ammonia Limiting 

Method (ALM). PNM claims use of the 

ALM would take into account the 

spatial variations of background 

ammonia concentrations and account 

for the consumption of background 

ammonia by background sources of 

sulfate and nitrate; and that modeling at 

a higher resolution of 1 km (compared 

to 4 km) is better, to ‘‘better represent 

the wind flow in a complex terrain 

regime.’’ Using these modeling 

techniques, PNM argues that these 

alternate modeling results show that the 

greatest visibility improvement that 

could be achieved at any Class I area by 

installing SCRs at SJGS would be less 

than 0.5 dv per unit, and thus less than 

what a human could perceive. 

Response: The commenter indicates 

that we used the WRAP photochemical 


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Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 52435 

91CALMET/CALPUFF Protocol for BART 

Exemption Screening Analysis for Class I Areas in 

the Western United States (August 15, 2006; 

available at: http://pah.cert.ucr.edu/aqm/308/bart/ 

WRAP_RMC_BART_Protocol_Aug15_2006.pdf 

***). 

92 ‘‘CALPUFF: Status and Update,’’ Dennis 

Atkinson, Presentation at Regional/State/Local 

Modelers Workshop, May 16, 2007. (http:// 

www.cleanairinfo.com/regionalstatelocalmodeling

workshop/archive/2007/presentations/

Wednesday%20-%20May%2016%202007/ 

CALPUFF_status_update.pdf); EPA report, 

‘‘Assessment of the ‘‘VISTAS’’ Version of the 

CALPUFF Modeling System,’’ EPA–454/R–08–007, 

August 2008 available at (http://www.epa.gov/ttn/

scram/reports/calpuff_vistas_assessment_report_

final.pdf); ‘‘CALPUFF Regulatory Update,’’ Roger 

W. Brode, Presentation at Regional/State/Local 

Modelers Workshop, June 10–12, 2008, available at 

(http://www.cleanairinfo.com/regionalstatelocal

modelingworkshop/archive/2008/presentations/

BRODE_CA.pdf). 

modeling to support our action on SO2

controls and from this, somehow 

concludes we should accept PNM’s 

BART CALPUFF visibility modeling, 

allegedly consistent with WRAP 

protocols for assessing the visibility 

impacts of SJGS. In this instance, the 

commenter appears to confuse two 

types of modeling. As we discuss 

elsewhere in this notice, we did rely on 

the WRAP’s photochemical modeling in 

considering whether New Mexico 

sources, specifically SJGS, interfered 

with other States’ visibility plans. The 

WRAP’s CALPUFF screening modeling 

was used to determine which BARTeligible sources were subject to BART. 

As a result of the WRAP CALPUFF 

screening modeling, New Mexico 

identified one source subject to BART 

and, as discussed elsewhere, projected 

emission reductions that were relied 

upon by the WRAP in their 

photochemical modeling. The 

photochemical modeling was used to 

consider the emissions from all sources 

in the regions and was used to establish 

the reasonable progress goals for the 

WRAP States. The source-specific 

CALPUFF visibility modeling, on the 

other hand, requires a site specific 

modeling approach designed to evaluate 

visibility impacts to inform decisions in 

a BART determination for a specific 

source. Our CALPUFF visibility 

modeling, performed using an accepted 

CALPUFF model version and following 

applicable guidance and EPA/FLM 

recommendations, showed significant 

visibility benefits due to the use of SCR 

as NOX BART at SJGS. 

As discussed elsewhere, since NMED 

was previously proposing to install the 

most stringent controls, we did not raise 

some of our concerns with past 

modeling, since the BART guidelines 

allow some flexibility in the need to 

conduct modeling when the most 

stringent controls are being required. In 

our review of PNM’s earlier BART 

CALPUFF visibility modeling, we did 

note some inconsistencies between 

PNM’s CALPUFF modeling protocol 

and the EPA approved modeling 

techniques for source-specific modeling 

to support a BART determination. As 

stated in the TSD that accompanied our 

proposal, however, we agree with the 

commenter that the PNM CALPUFF 

modeling generally followed the BART 

protocol for BART screening analyses 

developed by the WRAP.91 After the 

WRAP CALPUFF screening modeling 

had been generated, some problems 

with the changes from the previous 

CALPUFF modeling system that were 

included in CALPUFF Version 6.211 

and another version referred to as the 

‘‘VISTAS version’’ had been 

identified.92 Version 6.211 has been 

found to set up situations where the 

boundary layer could artificially 

collapse creating unrealistic 

meteorological conditions and 

significantly impacting the modeled 

dispersion (refer to the TSD for 

additional details). This assessment 

leads to EPA’s approval of CALPUFF 5.8 

as the approved version, announced on 

June 29, 2007. Furthermore, PNM did 

not consult with Region 6 to establish a 

protocol for additional CALPUFF 

modeling as part of the BART visibility 

analyses, and while they chose to 

generally follow the protocol developed 

by the WRAP specifically for BART 

screening analyses, PNM deviated in 

some ways. In addition, a site specific 

protocol for SJGS should have included 

additional refinements in model settings 

and incorporation of data. We 

specifically noted several deviations 

from appropriate practice in PNM’s 

implementation of the meteorological 

processing model for CALPUFF, named 

CALMET, in addition to model versions 

issues. PNM’s CALMET modeling 

utilized radii of influence values 

inconsistent with EPA/FLM guidance, 

and did not follow the EPA/FLM 

guidance about including upper air 

observational data. Finally, the 

CALPUFF modeling system (including 

CALMET) versions used by PNM did 

not follow EPA and FLM 

recommendations and guidance. NMED 

received comment on not being 

consistent with established BART 

modeling procedures from the FLM’s 

during the proposed 308 SIP in August 

2010. PNM has also alleged that variable 

ammonia concentrations should be 

used, which is inconsistent with the 

WRAP’s BART screening protocol and 

modeling. Furthermore, NMED 

specifically requested that PNM perform 

modeling using the default constant 1 

ppb background ammonia concentration 

on multiple occasions in 2008 as they 

were developing the proposed RH SIP. 

These numerous deviations from our 

guidance methods and procedures and 

use of an alternate model version were 

not considered by the commenter. These 

deviations are discussed further in the 

Technical Support Document that 

accompanied our proposal. 

As discussed in section 4.3.1 and 

table 4–6 of the TSD, our sensitivity 

modeling results support the conclusion 

that the differences between the WRAP 

BART screening protocol and our 

current regulatory approach would not 

likely change the original determination 

by the WRAP and NMED of which 

sources screen out of BART and which 

are subject to a full BART analysis. We 

disagree, however, that PNM’s modeling 

was acceptable modeling for evaluating 

the visibility impacts to inform a BART 

determination. It would have been 

inappropriate for us to use a CALPUFF 

model version with known problems/ 

errors to support our proposed BART 

determination instead of using the 

CALPUFF version we approved for 

regulatory review. Therefore, our BART 

CALPUFF visibility modeling sought to 

correct the deficiencies in the PNM 

BART CALPUFF visibility modeling. In 

addition, given that the emission rates 

that we proposed as NOX BART differed 

from those used in PNM and NMED’s 

BART visibility modeling, it was 

necessary to perform our CALPUFF 

visibility modeling, following EPA/FLM 

guidance and practices, to assess the 

anticipated visibility improvements 

from the use of SCR with our proposed 

BART lower emission rate of 0.05 lb of 

NOX/MMBtu (NMED/PNM modeling 

used an emission rate of 0.07 lb of NOX/ 

MMBtu for SCR). As discussed in the 

TSD, we also had updated emission 

estimates for sulfuric acid emissions 

based on the latest information that was 

included in our modeling. We therefore 

disagree with the commenter and have 

explained why we needed to do our 

own BART CALPUFF visibility analysis. 

We used the approved version of the 

model in accordance with the 

appropriate procedures, as discussed 

further in other response to comments 

and we are confident in using our 

results as one of the five factors in 

making a BART determination. The 

commenter did not provide any direct 

comments indicating that our BART 

visibility modeling differed in any way 

from EPA and FLM modeling guidance 

and standard practices that EPA and the 

FLM representatives have approved in 

other protocols. 

With regard to the commenter’s 

suggestion that more recent versions of 


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CALPUFF be used, as discussed in more 

detail in another response, the two 

suggested model versions have not gone 

through the appropriate review to assess 

if they are founded in appropriate 

science and perform adequately and 

reliably and are an improvement to the 

current version that is acceptable for 

regulatory actions. PNM did not submit 

the modeling files as part of its 

comments. Instead, the PNM submitted 

report only includes a summary of the 

modeling results. Therefore, sufficient 

evidence has not been presented to 

support PNM’s claims had we wished to 

review this modeling done with nonapproved models. Because the model 

results provided by the commenter 

cannot be evaluated and because we 

have no basis to conclude that these 

versions provide reliable results, we did 

not conduct a full review of the 

submitted summary of the model output 

results. In looking over the summary of 

the modeling results in the submitted 

report, however, we continue to have 

significant concerns with the model 

version and options/inputs used given 

that the results are indicating drastically 

lower values than our modeling that 

was conducted with CALPUFF Version 

5.8. 

We disagree with the use of a higher 

grid-resolution (1-km) for modeling of 

visibility impacts using the CALPUFF 

modeling system. Current EPA guidance 

from the May 15, 2009 EPA Model 

Clearinghouse memorandum defaults to 

a horizontal grid resolution of 4-km. 

While this guidance does not 

automatically preclude the use of higher 

resolution meteorological fields, the 

memorandum discusses five issues that 

should be addressed in considering use 

of a 1-km meteorological grid. None of 

these five elements were addressed by 

the commenter. Among the elements 

that should have been considered were 

a discussion of the nature of SJGS’s 

source-receptor relationship to Class I 

areas in the modeling domain and 

meteorological characteristics which 

govern these source-receptor 

relationships, a statistical performance 

analysis showing the inadequacy of the 

4-km CALMET fields, demonstration of 

the technical adequacy of CALMET 

diagnostic algorithms in a complex 

terrain situation, statistical evaluation 

demonstrating that 1-km CALMET fields 

perform better than 4-km fields in this 

specific situation, and discussion of 

how the enhanced resolution impacts 

the air quality model. When CALMET is 

using much higher grid resolutions, 

such as 1-km grid, on the original 

Numerical Weather Prediction files, the 

CALMET meteorological model 

performance must be examined through 

appropriate statistical analysis to 

understand if the CALMET diagnostic 

adjustments perform appropriately. The 

Report presented no evidence to support 

the claim that a 1-km resolution 

increases the accuracy of the final wind 

field in specifically modeling the SJGS. 

The commenter has not provided any 

statistical or other analyses to justify 

such a deviation for modeling of the 

SJGS. Consistent with EPA–FLM 

recommendations for CALMET and the 

WRAP BART screening modeling 

protocol, we determined that a 4-km 

grid resolution should be used. 

We also disagree with the use of the 

Ammonia Limit Method which is also 

called ALM and note that it is 

inconsistent with the nitrate 

repartitioning approach that has been 

previously accepted by the FLMs and 

EPA. There is a lack of documentation, 

adequate technical justification, and 

validation for the development and use 

of the ALM. We and the FLMs have 

previously reviewed protocols 

proposing using ALM and we and/or the 

FLMs have not approved the use of the 

proposed ALM procedure. In general 

terms, one of the key issues is ALM is 

a method to have emissions from other 

sources consume ammonia, so there is 

less ammonia to react with the source of 

interest being modeled. Since ammonia 

levels from the local area around the 

plant were used by EPA, to do 

calculations in the modeling to consume 

ammonia from surrounding sources 

would unnaturally consume ammonia 

that was actually monitored in the 

vicinity of the SJGS. The ALM has not 

been approved by EPA and the FLMs 

through interagency workgroups 

(IWAQM or FLAG) as an approved part 

of CALPUFF based visibility analyses. 

The commenter has not provided any 

adequate justification, documentation, 

or other analyses to justify the proposed 

use of ALM. 

Furthermore, the use of ALM requires 

the input of background ammonia 

concentrations as well as background 

concentrations of sulfate, nitrate, and 

nitric acid. The commenter used 

background concentrations derived from 

modeling simulations of the EPA 

Community Multiscale Air Quality 

Modeling System (CMAQ) for 2002. The 

Report’s summary shows that monthly 

averages of predicted concentrations for 

ammonia, sulfate, nitrate, and nitric 

acid at a grid resolution of 36 km were 

used as model inputs to apply the ALM. 

As discussed in a separate response to 

comments, available ammonia monitor 

data indicates that ammonia 

concentrations are higher in the vicinity 

of the SJGS and city of Farmington than 

at the Mesa Verde Class I area 

(approximately 42 km from SJGS). The 

use of 36 km resolution model 

predictions results in an average 

ammonia level for the entire 36km by 36 

km grid cell and does not reflect the 

higher ammonia concentrations 

measured near the SJGS which are of 

greater concern for determining 

visibility impacts from the source. In 

addition, the CMAQ model predictions 

that the commenter used are not an 

appropriate estimation of background 

ammonia available for reaction with the 

SJGS emissions since this CMAQ 

simulation of ‘‘background’’ 

concentrations already includes SJGS 

emissions and reactions they have in the 

atmosphere. The background ammonia 

concentration that the commenter input 

into the non-approved CALPUFF model 

has already been decreased by reaction 

with SJGS emissions in the CMAQ 

model predictions. 

The commenter also provided a 

summary of the modeling results based 

on variable ammonia levels using 

CALPUFF version 6.112 and 6.4. We 

disagree with the use of variable 

ammonia as we have responded to 

comments about using variable 

ammonia levels in another response to 

comment. We note that variable 

ammonia levels were not approved in 

the WRAP’s BART screening modeling 

protocol, nor in protocols by NMED in 

their 2010 proposal, nor by EPA Region 

6 as the commenter seemed to indicate 

in their comment. 

We note that the summary of the 

report’s BART visibility modeling 

results shows that an SCR emission rate 

of 0.07 lb/MMBtu was used, rather than 

the 0.05 lb/MMBtu that we included in 

our proposal. Using this higher level of 

0.07 lb/MMBtu would bias the 

reduction in impacts from the 

installation of SCR lower than what we 

proposed. If their modeling was 

conducted using our proposed emission 

rate, it may have shown a value greater 

than 0.5 dv for each individual unit. 

This is not relevant though given the 

numerous issues associated with their 

modeling analysis as discussed above. 

Moreover, as noted in the BART 

Guidelines, the CALPUFF model results 

are useful for considering the 

comparative impacts of single sources 

on visibility impairment in a relative 

sense and relative to other sources, 

SJGS’s impacts are significant. We note 

that the SJGS is one of the single largest 

sources of NOX in the United States and 

located close to 16 Class I areas. As 

such, even without modeling results, 

one could conclude that the source is 

likely to contribute to significant 

visibility impacts at multiple Class I 


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areas and that the installation of SCR 

would lead to meaningful visibility 

benefits. We also note that our modeling 

looked at the dv improvements at 16 

Class I areas and indicates even greater 

visibility benefits at other Class I areas 

than Mesa Verde. The summary of the 

modeling results provided by the 

commenter do not evaluate 

improvements at other Class I areas or 

any cumulative visibility improvement 

benefits of SCR, yet they asserted that 

their analysis showed the maximum 

impacts from SCR at any Class I area. As 

we note elsewhere, we actually 

projected the largest visibility 

improvement due to SCR control level 

at the Canyonlands Class I area. As a 

result, there is no evidence to support 

the commenter’s claim that the largest 

improvement was less than 0.5 dv at 

any Class I area. Given the relative size 

of SJGS and its location as compared to 

other BART sources, such results would 

be surprising. We conclude that our 

modeling which was performed using 

an accepted CALPUFF model version 

and following applicable guidance and 

EPA/FLM recommendations is an 

appropriate approach for assessing the 

visibility benefits due to the use of SCR. 

This modeling confirmed that our NOX

BART determination will result in 

significant visibility benefits. 

Comment: A commenter alleged that 

EPA lacks the requisite statutory 

authorization in this proceeding to 

implement its proposed emission limits 

for H2SO4 and NH3 emissions from the 

SJGS. The commenter indicated that if 

EPA has not shown that limits on 

emissions of H2SO4 and NH3 from the 

SJGS will result in reduced visibility 

impairment or make reasonable progress 

in a class I area’s Reasonable Progress 

Goal, the Agency has no authority under 

CAA § 169A to require the proposed 

emission limits on those pollutants from 

SJGS. The commenter also alleged that 

if EPA has not shown interference from 

H2SO4 or NH3 emissions, EPA has no 

authority to regulate these pollutants 

under CAA section 110(a)(2)(D)(i)(II). 

EPA has not shown that its conclusory 

statement that the proposed limits will 

‘‘minimize the contribution of these 

compounds to visibility impairment’’ 

falls short of demonstrating a visibilityimpairment contribution that is 

necessary to authorize regulation of 

those compounds under Section 169A. 

The commenter indicated that if EPA 

has no other policy reason other than 

appropriate considerations of comity, 

EPA should defer to New Mexico’s 

determination of which pollutants to 

regulate with BART requirements. The 

commenter noted that New Mexico’s 

proposed regional haze SIP under 

section 309 of 40 CFR part 51 and the 

withdrawn regional haze SIP proposal 

under section 308 both demonstrates the 

State’s intent to regulate regional haze 

during the first planning period with 

controls only on emissions of SO2, NOX

and PM. The commenter concluded that 

any proposal by EPA to limit emissions 

of either H2SO4 or NH3 from New 

Mexico sources goes beyond the 

planned scope of the State’s regional 

haze SIP and should be abandoned. The 

commenter also indicated it is unclear 

from EPA’s proposal if its action is 

being proposed under CAA section 

110(a)(2)(D)(i)(II) as an Interstate 

Transport provision related to visibility, 

id., or instead under CAA section 169a 

as part of a BART determination for the 

SJGS. 

Response: For the reasons discussed 

elsewhere in our response to comments, 

we have determined that neither an 

ammonia limit nor ammonia monitoring 

requirements are appropriate. The 

design plans for the SCRs that will be 

submitted will address design and 

operation of SCRs based on a maximum 

ammonia slip level of 2 ppm. Proper 

design and operation of the SCR should 

be protective of visibility impairment 

modeling projections. We disagree with 

the commenter concerning the need to 

regulate H2SO4. If a power plant is 

installing SCR at an existing facility in 

an area where a state has a concern 

about PM2.5 and regional haze impacts, 

it would be normal for a state to 

consider the imposition of limits on 

H2SO4 to minimize/limit the amount of 

degradation in visibility due to any 

increases in these pollutants. 

As we discussed in our proposal, we 

have concluded that the low sulfur coal 

burned at the SJGS generates very little 

sulfur trioxide (SO3), and hence H2SO4, 

which is formed when SO3 combines 

with water in the flue gas to form 

H2SO4. In addition, SCR catalysts are 

available with a low SO2 to SO3

conversion of 0.5%, further limiting the 

production of H2SO4. Nevertheless, we 

conducted several modeling runs with 

different H2SO4 emission levels and that 

modeling indicated that increases in 

H2SO4 did result in some visibility 

degradation at Class I areas in New 

Mexico and surrounding states. The 

H2SO4 runs can be found in the TSD 

and its appendices or in the RTC for this 

action. Some of the H2SO4 runs were not 

used in the final decision modeling 

analysis, but provided a basis for being 

concerned about potential H2SO4

impacts and thus limiting the amount of 

growth in H2SO4 from our action. 

In summary, we conclude that 

emissions of H2SO4 will not be a 

significant concern at the SJGS. 

However, modeling conducted by us 

and some modeling results provided by 

PNM’s contractors indicate that 

visibility impairment could worsen if 

emissions of H2SO4 are not limited in an 

enforceable manner. We do not wish to 

allow a growth in emissions to occur 

that would undermine the NOX

reductions that we are requiring to 

ensure that NM emission sources do not 

interfere with visibility in other states as 

required by the 110(a)(2)(D)(i)(II). 

Therefore, we believe we have struck 

the right balance in limiting emissions 

of H2SO4 to a reasonable level verified 

by annual stack testing. We are 

controlling H2SO4 under the BART 

provisions of the RHR and CAA Section 

110. Our regulatory authority includes 

CAA section 169A(b)(2), 40 CFR 

51.308(e)(1)(ii) and CAA section 

110(a)(2)(D)(i)(II). 

IV. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This action is not a ‘‘significant 

regulatory action’’ under the terms of 

Executive Order 12866 (58 FR 51735, 

October 4, 1993) and is therefore not 

subject to review under Executive 

Orders 12866 and 13563 (76 FR 3821, 

January 21, 2011). This action finalizes 

a source-specific FIP for the San Juan 

Power Generating Station (SJGS) in New 

Mexico. 

B. Paperwork Reduction Act 

This action does not impose an 

information collection burden under the 

provisions of the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. 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 FIP applies to a single 

facility, (SJGS), the Paperwork 

Reduction Act does not apply. See 5 

CFR 1320(c). 

Burden means the total time, effort, or 

financial resources expended by persons 

to generate, maintain, retain, or disclose 

or provide information to or for a 

Federal agency. This includes the time 

needed to review instructions; develop, 

acquire, install, and utilize technology 

and systems for the purposes of 

collecting, validating, and verifying 

information, processing and 

maintaining information, and disclosing 

and providing information; adjust the 

existing ways to comply with any 


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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 our 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 rule on small entities, small 

entity is defined as: (1) A small business 

as defined by the Small Business 

Administration’s (SBA) regulations at 13 

CFR 121.201; (2) a small governmental 

jurisdiction that is a government of a 

city, county, town, school district or 

special district with a population of less 

than 50,000; and (3) a small 

organization that is any not-for-profit 

enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of this action on small entities, 

EPA certifies that this action will not 

have a significant economic impact on 

a substantial number of small entities. 

The FIP for SJGS being finalized today 

does not impose any new requirements 

on small entities. See Mid-Tex Electric 

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

(DC Cir. 1985). 

D. Unfunded Mandates Reform Act 

(UMRA) 

This rule does not contain a Federal 

mandate that may result in expenditures 

of $100 million or more for State, local, 

and tribal governments, in the aggregate, 

or the private sector in any one year. 

Our cost estimate indicates that the total 

annual cost of compliance with this rule 

is below this threshold. Thus, this rule 

is not subject to the requirements of 

sections 202 or 205 of UMRA. 

This rule is also not subject to the 

requirements of section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. This 

rule contains regulatory requirements 

that apply only to the San Juan Power 

Generating Station (SJGS) in New 

Mexico. 

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 

solicited comment on the proposed rule 

from State and local officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This rule does not have tribal 

implications as specified by Executive 

Order 13175 (65 FR 67249, November 9, 

2000), because the rule neither imposes 

substantial direct compliance costs on 

tribal governments, nor preempts tribal 

law. Therefore, the requirements of 

section 5(b) and 5(c) of the Executive 

Order do not apply to this rule. 

However, consistent with EPA policy, 

EPA consulted with one Tribe on this 

action. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

EPA interprets EO 13045 (62 FR 

19885, April 23, 1997) as applying only 

to those regulatory actions that concern 

health or safety risks, such that the 

analysis required under section 5–501 of 

the EO has the potential to influence the 

regulation. This action is not subject to 

EO 13045 because it implements 

specific standards established by 

Congress in statutes. 

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 rule would 

require the affected units at SJGS 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 


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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 rule 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 rule limits emissions of pollutants 

from a single stationary source, the 

SJGS. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. EPA will submit a 

report containing this action and other 

required information to the U.S. Senate, 

the U.S. House of Representatives, and 

the Comptroller General of the United 

States prior to publication of the rule in 

the Federal Register. A major rule 

cannot take effect until 60 days after it 

is published in the Federal Register. 

This action is not a ‘‘major rule’’ as 

defined by 5 U.S.C. 804(2). This rule 

will be effective on September 21, 2011. 

L. Judicial Review 

Under section 307(b)(1) of the CAA, 

petitions for judicial review of this 

action must be filed in the United States 

Court of Appeals for the appropriate 

circuit by October 21, 2011. Pursuant to 

CAA section 307(d)(1)(B), this action is 

subject to the requirements of CAA 

section 307(d) as it promulgates a FIP 

under CAA section 110(c). Filing a 

petition for reconsideration by the 

Administrator of this final rule does not 

affect the finality of this action for the 

purposes of judicial review nor does it 

extend the time within which a petition 

for judicial review may be filed, and 

shall not postpone the effectiveness of 

such rule or action. This action may not 

be challenged later in proceedings to 

enforce its requirements. See CAA 

section 307(b)(2). 

List of Subjects in 40 CFR Part 52 

Environmental protection, Air 

pollution control, Best available control 

technology. Incorporation by reference, 

Intergovernmental relations, Interstate 

transport of pollution, Nitrogen dioxide, 

Ozone, Particulate matter, Regional 

haze, Reporting and recordkeeping 

requirements, Sulfur dioxide, Visibility. 

Dated: August 4, 2011. 

Lisa P. Jackson, 

Administrator. 

For the reasons set out in the 

preamble, title 40, chapter I, of the Code 

of Federal Regulations is 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. 

Subpart GG—[Amended] 

■ 2. Section 52.1628 is added 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. (1) Compliance 

with the requirements of this section is 

required by: 

(i) SO2: No later than 5 years after 

September 21, 2011. 

(ii) NOX: No later than 5 years after 

September 21, 2011. 

(iii) H2SO4: No later than 5 years after 

September 21, 2011. 

(2) On and after the compliance date 

of this rule, no owner or operator shall 

discharge or cause the discharge of NOX, 

SO2, or H2SO4 into the atmosphere from 

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

for these pollutants. 

(c) Definitions. All terms used in this 

part but not defined herein shall have 

the meaning given them in the CAA 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. 

Boiler-operating-day means any 24- 

hour period between 12:00 midnight 

and the following midnight during 

which any fuel is combusted at any time 

at the steam generating unit. 

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 part 75 of this 

chapter, using data from certified O2

and stack gas flow rate monitors. 

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 

September 21, 2011, 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 NOX control 

device included in this plan shall be 

designed to meet the NOX emission rate 

limit identified in paragraph (d) of this 

section with an ammonia slip of no 

greater than 2.0 ppm. The owner or 

operator shall submit amendments to 

the plan to the Regional Administrator 

as changes occur. 

(2) NOX emission rate limit. The NOX

emission rate limit for each unit in the 

plant, expressed as nitrogen dioxide 

(NO2), shall be 0.05 pounds per million 

British thermal units (lbs/MMBtu), as 

averaged over a rolling 30 boileroperating-day period. The hourly NOX

and O2 data used to determine the NOX

emission rates shall be in compliance 

with the requirements in part 75 of this 

chapter. For each unit on each boileroperating-day, the hourly NOX

emissions measured in lbs/MMBtu, 

shall be averaged over the hours the unit 

was in operation to obtain a daily boileroperating-day average. Each day, the 30- 

day-rolling average NOX emission rate 

for each unit (in lbs/MMBtu) shall be 

determined by averaging the daily 

boiler-operating-day average emission 

rate from that day and those from the 

preceding 29 days. 

(3) SO2 emission rate limit. The SO2

emission rate limit for each unit in the 

plant shall be 0.15 pounds per million 

British thermal units (lbs/MMBtu), as 

averaged over a rolling 30 boileroperating-day period. The hourly NOX

and O2 data used to determine the NOX

emission rates shall be in compliance 

with the requirements in part 75 of this 

chapter. For each unit on each boilerVerDate Mar<15>2010 19:58 Aug 19, 2011 Jkt 223001 PO 00000 Frm 00053 Fmt 4701 Sfmt 4700 E:\FR\FM\22AUR2.SGM 22AUR2

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52440 Federal Register / Vol. 76, No. 162 / Monday, August 22, 2011 / Rules and Regulations 

operating-day, the hourly SO2 emissions 

measured in lbs/MMBtu, shall be 

averaged over the hours the unit was in 

operation to obtain a daily boileroperating-day average. Each day, the 30- 

day-rolling average SO2 emission rate 

for each unit (in lbs/MMBtu) shall be 

determined by averaging the daily 

boiler-operating-day average emission 

rate from that day and those from the 

preceding 29 days. 

(4) Sulfuric Acid (H2SO4) emission 

rate limit: Emissions of H2SO4 from each 

unit shall be limited to 2.6 × 10¥4 lb/ 

MMBtu on an hourly basis. 

(e) Testing and monitoring. 

Notwithstanding any language to the 

contrary, the paragraphs in this section 

apply at all times to Units 1, 2, 3, and 

4 at the plant. 

(1) By the applicable compliance date 

in paragraph (b) of this section, the 

owner or operator shall install, calibrate, 

maintain and operate Continuous 

Emissions Monitoring Systems (CEMS) 

for NOX, SO2, stack gas flow rate, and 

O2 on Units 1, 2, 3, and 4 in accordance 

with part 75 of this chapter. The owner 

or operator shall also comply with the 

applicable quality assurance procedures 

in part 75 of this chapter for these 

CEMS. Continuous monitoring systems 

for NOX, SO2, stack gas flow rate, and 

O2 that have been certified for use under 

the Acid Rain Program, and that are 

continuing to meet the on-going qualityassurance requirements of that program, 

satisfy the requirements of this 

paragraph (e)(1). Compliance with the 

emission limits for NOX and SO2 shall 

be determined by using data from these 

CEMS. 

(2) The CEMS required by this rule 

shall be in continuous operation 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, and O2

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. Each required CEMS must 

obtain valid data for at least 90.0 

percent of the unit operating hours, on 

an annual basis. 

(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). 

Note to paragraph (e)(3): EPA Test Method 

8A is available at: http://www.epa.gov/ttn/

emc/ctm/ctm-013.pdf. 

(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. 

(1) The owner or operator shall keep 

records of all CEMS data, stack test data, 

and CEMS quality-assurance tests 

required under this section for a period 

of at least 3 years. 

(2) For each unit subject to the 

emission limitations for SO2, and NOX, 

in this section, the owner or operator 

shall comply with the excess emission 

reporting requirements in §§ 60.7(c) and 

(d) of this chapter, on a semiannual 

basis, unless more frequent (e.g., 

quarterly) reporting is requested by the 

Regional Administrator. For SO2 and 

NOX, any day on which the 30-day 

rolling average emission limit in 

paragraph (d) of this section is not met 

shall be counted as an excess emissions 

day. The duration of the excess 

emissions period shall be the number of 

unit operating hours on that day. Any 

hour in which a CEMS is out-of-service 

(excluding hours in which required 

calibrations and QA tests are performed) 

shall be counted as an hour of monitor 

downtime. 

(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 

unit including associated air pollution 

control equipment in a manner 

consistent with good air pollution 

control practices for minimizing 

emissions. Determination of whether 

acceptable operating and maintenance 

procedures are being used will be based 

on information available to the Regional 

Administrator which may include, but 

is not limited to, monitoring results, 

review of operating and maintenance 

procedures, and inspection of the unit. 

(h) Enforcement. (1) Notwithstanding 

any other provision in this 

implementation plan, any credible 

evidence or information relevant as to 

whether the unit would have been in 

compliance with applicable 

requirements if the appropriate 

performance or compliance test had 

been performed, can be used to establish 

whether or not the owner or operator 

has violated or is in violation of any 

standard or applicable emission limit in 

the plan. 

(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. 

■ 3. Section 52.1629 is added to read as 

follows: 

§ 52.1629 Visibility protection. 

The portion of the State 

Implementation Plan revision received 

on September 17, 2007, from the State 

of New Mexico for the purpose of 

addressing the visibility requirements of 

Clean Air Act section 110(a)(2)(D)(i)(II) 

for the 1997 8-hour ozone and the 1997 

fine particulate matter National 

Ambient Air Quality Standards is 

disapproved. 

[FR Doc. 2011–20682 Filed 8–19–11; 8:45 am] 

BILLING CODE 6560–50–P 


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