[Federal Register Volume 76, Number 162 (Monday, August 22, 2011)]
[Rules and Regulations]
[Pages 52388-52440]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2011-20682]



[[Page 52387]]

Vol. 76

Monday,

No. 162

August 22, 2011

Part II





Environmental Protection Agency





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40 CFR Part 52





Approval and Promulgation of Implementation Plans; New Mexico; Federal 
Implementation Plan for Interstate Transport of Pollution Affecting 
Visibility and Best Available Retrofit Technology Determination; Final 
Rule

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

[[Page 52388]]


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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.

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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 (PM<INF>2.5</INF>) 
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 
(NO<INF>X</INF>) and sulfur dioxide (SO<INF>2</INF>) 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 NO<INF>X</INF> for SJGS. In addition, EPA is 
implementing sulfuric acid (H<INF>2</INF>SO<INF>4</INF>) 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, <a href="/cdn-cgi/l/email-protection#751e1a07110f1c5b1f1a10351005145b121a03"><span class="__cf_email__" data-cfemail="8ae1e5f8eef0e3a4e0e5efcaeffaeba4ede5fc">[email protected]</span></a>.

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 source-specific 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

[[Page 52389]]

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 NO<INF>X</INF> 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. NO<INF>X</INF> 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 NO<INF>X</INF> BART 
Determination
    B. Comments on our Proposed NO<INF>X</INF> BART Emission Limits
    C. Comments on our Proposed SO<INF>2</INF> Emission Limit
    D. Comments on our Proposed H<INF>2</INF>SO<INF>4</INF> 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 PM<INF>2.5</INF> 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 SO<INF>2</INF> and NO<INF>X</INF> emissions limits 
that will eliminate such interstate interference. For SO<INF>2</INF>, 
we proposed to require the SJGS to meet an emission limit of 0.15 
pounds per million British Thermal Units (lb/MMBtu). For 
NO<INF>X</INF>, we proposed to implement a NO<INF>X</INF> 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 Sec.  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 NO<INF>X</INF>. (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 NO<INF>X</INF> BART limits for the SJGS based on 
our proposed NO<INF>X</INF> BART determination. We proposed to require 
that the SJGS meet a NO<INF>X</INF> emission limit of 0.05 lb/MMBtu 
individually at Units 1, 2, 3, and 4. We noted this NO<INF>X</INF> 
limit is achievable by installing and operating Selective Catalytic 
Reduction (SCR).
    We proposed that both the NO<INF>X</INF> and SO<INF>2</INF> 
emission limits be measured on the basis of a 30 day rolling average. 
We also proposed hourly average emission limits of 1.06 x 
10<SUP>-4</SUP> lb/MMBtu for H<INF>2</INF>SO<INF>4</INF> 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 x 
10<SUP>-4</SUP> to 7.87 x 10<SUP>-4</SUP> lb/MMBtu for 
H<INF>2</INF>SO<INF>4</INF>. 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 PM<INF>2.5</INF> 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

[[Page 52390]]

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.)
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    \1\ CAA 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.
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    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 SO<INF>2</INF> and NO<INF>X</INF> emissions relied 
upon in the WRAP modeling for the SJGS, however, are not federally 
enforceable. Therefore, we are establishing federally enforceable 
SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> 
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.
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    \2\ See 74 FR 2392.
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    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.
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    \3\ A 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).
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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

[[Page 52391]]

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 
H<INF>2</INF>SO<INF>4</INF> emission limit of 2.6 x 10<SUP>-4</SUP> 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 NO<INF>X</INF>, SO<INF>2</INF>, ammonia, and 
H<INF>2</INF>SO<INF>4</INF> 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 NO<INF>X</INF>, SO<INF>2</INF>, and 
H<INF>2</INF>SO<INF>4</INF> 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.)
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    \4\ 76 FR 491, 504.
    \5\ See 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.
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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.
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    \6\ 76 FR 12305.
    \7\ 76 FR 1578.
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    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
------------------------------------------------------------------------


[[Page 52392]]

    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.<SUP>9 10</SUP> 
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\
---------------------------------------------------------------------------

    \8\ Revised 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.
    \9\ Comments submitted by United States Department of Interior, 
National Park Service, dated 3/31/11.
    \10\ New 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.
    \11\ See Exhibit 1, RTC Revised Cost Analysis.
    \12\ Please see our Complete Response to Comments for NM 
Regional Haze/Visibility Transport FIP document.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

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

    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-by-source 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

[[Page 52393]]

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.
---------------------------------------------------------------------------

    \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 NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \15\ Revised BART Cost Effectiveness Analysis for Selective 
Catalytic Reduction at the Public Service Company of New Mexico San 
Juan Generating Station, November 2010, p. 5.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> 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-
NO<INF>X</INF> burners with overfire air ports, a neural network 
system, and a pulse jet fabric filter. However, when making the 
NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \16\ ``You are expected to identify potentially applicable 
retrofit control technologies that represent the full range of 
demonstrated alternatives.'' 70 FR at 39164.
---------------------------------------------------------------------------

    Comment: EPA proposes to conclude that, because the SJGS currently 
is subject to a federally enforceable permit limit of 0.30 lb/MMBtu for 
NO<INF>X</INF>, which is less restrictive than the WRAP modeling's 
assumed NO<INF>X</INF> rates for those units (as characterized by EPA), 
additional NO<INF>X</INF> 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 cost-effectiveness 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 NO<INF>X</INF> control 
technologies.\17\
---------------------------------------------------------------------------

    \17\ 76 FR at 499.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> 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 NO<INF>X</INF> 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

[[Page 52394]]

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 cost-effectiveness) 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\
---------------------------------------------------------------------------

    \18\ 70 FR at 39158.

---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------

    \19\ 70 FR at 39131.

    We followed the five statutory factors when assessing 
NO<INF>X</INF> 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 
NO<INF>X</INF> BART assessment for the SJGS.
---------------------------------------------------------------------------

    \20\ 76 FR 491, 499.
---------------------------------------------------------------------------

    We received a New Mexico RH SIP on July 5, 2011. This SIP does 
contain a revised BART analysis that concludes that NO<INF>X</INF> 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 
cost-effectiveness 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 cost-effectiveness 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 cost-
effectiveness 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

[[Page 52395]]

$/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.
---------------------------------------------------------------------------

    \21\ 70 FR 39167.
---------------------------------------------------------------------------

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:
    <bullet> Appropriateness of using the Cost Manual.
    <bullet> Problems in B&V's scaling of cost items from another 
project.
    <bullet> Ductwork and ammonia grid costs.
    <bullet> Reactor box and breaching.
    <bullet> Expansion joints.
    <bullet> Sonic horns.
    <bullet> Elevator.
    <bullet> Structural steel.
    <bullet> SCR bypass.
    <bullet> Catalyst.
    <bullet> NO<INF>X</INF> monitoring.
    <bullet> Auxiliary electrical system upgrades.
    <bullet> Instrumentation and control systems.
    <bullet> Air preheaters.
    <bullet> Balanced draft conversion.
    <bullet> Contingencies.
    <bullet> Operating Labor.
    <bullet> Reagent.
    <bullet> Auxiliary power demand.
    <bullet> Catalyst life.
    <bullet> Interest rate.
    <bullet> 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.
---------------------------------------------------------------------------

    \22\ B&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.
---------------------------------------------------------------------------

    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

[[Page 52396]]

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 (SO<INF>3</INF>) 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 SO<INF>3</INF> 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% 
NO<INF>X</INF> 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 generally-applicable 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 SO<INF>3</INF> 
and requested a sorbent injection cost analysis from PNM. However, we

[[Page 52397]]

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 SO<INF>2</INF> 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<SUP>-4</SUP> lb/MMBtu, compared to our original 
value of 1.06 X10<SUP>-4</SUP> 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

[[Page 52398]]

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.
---------------------------------------------------------------------------

    \23\ Based on our emission limit of 2.6x10<SUP>-4</SUP> lb/MMBtu 
and conservatively assuming each unit operates 100% of the year 
(8760 hr/yr).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \24\ See San Juan Generating Station Site Visit, 5/23/11.
---------------------------------------------------------------------------

    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.'' 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.
---------------------------------------------------------------------------

    \25\ S.M. Cho and S.Z. Dubow, Design of a Selective Catalytic 
Reduction System for NO<INF>X</INF> Abatement in a Coal-Fired 
Cogeneration Plant, Proceedings of the American Power Conference, 
April 13-15, 1992, pp. 717-722.
---------------------------------------------------------------------------

    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 
``site-specific 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,

[[Page 52399]]

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.
---------------------------------------------------------------------------

    \26\ 10/22/10 B&V Cost Analysis Update, Appendix B; 6/7/07 B&V 
San Juan BART Analysis, p. B-3.
    \27\ E-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.
    \28\ Sargent & 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).
---------------------------------------------------------------------------

    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

[[Page 52400]]

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 cost-effectiveness analyses.
---------------------------------------------------------------------------

    \29\ EPA Air Pollution Control Cost Manual, pdf 486, Table 2.5, 
E (Allowance for Funds During Construction) = 0.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \30\ 70 FR 39104, 39169.

    The BART Guidelines further clarify, ``[w]here this affects the 
BART determination, this date should be assured by a federally- or 
State-enforceable 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 NO<INF>X</INF> 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

[[Page 52401]]

B&V escalation index, on the other hand, is proprietary and not subject 
to public review.
---------------------------------------------------------------------------

    \31\ E-mail from Larry Sorrels (OAQPS) to Don Shepherd (Park 
Service) with cc to Anita Lee (EPA Region 9), dated 7/21/10, 
concerning the SRP Navajo Generating Station SCR cost estimate.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \32\ 70 FR 39104, 39166.

    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 cost-effectiveness 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.
---------------------------------------------------------------------------

    \33\ Id. at 39168.
---------------------------------------------------------------------------

    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,<SUP>38 39</SUP> 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.
---------------------------------------------------------------------------

    \34\ See San Juan Generating Station Site Visit, 5/23/11.
    \35\ Revised 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.
    \36\ Bob Ellis, Standing on the Shoulder of Giants, Modern Power 
Systems, July 2002.
    \37\ McIlvaine, NO<INF>X</INF> 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.
    \38\ Bill 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-retrofits-translates-into-broad-cost-variations.html.
    \39\ Escalated from $145/kW: ($145/kw) (560.3/401.7)-$202/kW. 
Chemical Engineering, April 2011.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> 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 NO<INF>X</INF> or SO<INF>2</INF> 
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

[[Page 52402]]

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.
---------------------------------------------------------------------------

    \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.
    \41\ E-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.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> 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\
---------------------------------------------------------------------------

    \43\ 70 FR 49104, 39172.

    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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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\
---------------------------------------------------------------------------

    \44\ Id.
---------------------------------------------------------------------------

    Comment: The U.S. Forest Service (USFS) expressed its support of 
our NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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

[[Page 52403]]

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 NO<INF>X</INF> 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 
low-oxidation 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.
---------------------------------------------------------------------------

    \45\ 6/7/07 B&V BART Analysis, Table ES-2, Table 2-3, Table 6-1, 
7-1.
---------------------------------------------------------------------------

    We note the NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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\
---------------------------------------------------------------------------

    \46\ 70 FR 39104, 39166.

    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 NO<INF>X</INF> 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 NO<INF>X</INF> emission limit of 0.05 lb/MMBtu 
at that time to meet NO<INF>X</INF> 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 NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \47\ Id. at 39172.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> CEMS data for the 
period 2009-2010 to identify the best performing retrofit units that 
operate year-round. We ranked the annual average NO<INF>X</INF> 
emissions for all units in the database for the years 2009 and 2010 
from the lowest to the highest NO<INF>X</INF> 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.

[[Page 52404]]

    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\
---------------------------------------------------------------------------

    \48\ Exhibit 2, Best Performing SCR Retrofit Installations, June 
8, 2011.
    \49\ 70 FR 39104, 39172.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> emission limits of 
0.05 lbs/MMBtu on a continuous basis.
    In addition, it is important to note that most of the 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> reductions. Consequently, a simple examination of the 
raw data will not always by itself reveal the NO<INF>X</INF> 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' NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> emissions are achievable from the existing fleet of SCR-
equipped units than are reflected by a simple examination of the CAMD 
data.
---------------------------------------------------------------------------

    \50\ We examine this data excerpt in detail in our Complete 
Response to Comments document.
---------------------------------------------------------------------------

    Comment: A commenter states that while the proposed NO<INF>X</INF> 
limit of 0.05 lbs/MMBtu as BART for SJGS would significantly reduce 
NO<INF>X</INF> emissions from the SJGS and have a positive impact on 
visibility and public health, a lower NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> emission limit aside, the additional costs 
associated with achieving such a limit, weighed against the additional 
mass of NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \51\ Exhibit 2, 30 Day Rolling Averages for Selected Best 
Performing SCR Retrofit Installations.
---------------------------------------------------------------------------

    To our knowledge, there are no air permits in the U.S. that require 
that a NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> emissions can be reduced by 90% with SCR 
installed at 0.05 lbs/MMBtu emission limit. The NPS included data it 
claims indicates

[[Page 52405]]

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 NO<INF>X</INF> 
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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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-NO<INF>X</INF> 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. NO<INF>X</INF> emissions can be reduced by 90% with 
SCR installed at 0.05 lbs/MMBtu emission limit. Given the SJGS's size 
and amount of NO<INF>X</INF> emissions, a more stringent emission limit 
than PNM's proposal is not only achievable, but it will provide for 
greater reduction in NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 
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 BART-eligible 
units that constitute BART-eligible source.'' \52\
---------------------------------------------------------------------------

    \52\ 70 FR, 39104, 39172.
---------------------------------------------------------------------------

    As we discuss elsewhere in our response to comments, we received 
another comment requesting that we revise our proposed NO<INF>X</INF> 
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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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, NO<INF>X</INF>, SO<INF>2,</INF> 
H<INF>2</INF>SO<INF>4</INF>, 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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

[[Page 52406]]

of start up, shut down, or malfunction events for NO<INF>X</INF>, 
SO<INF>2,</INF> and H<INF>2</INF>SO<INF>4</INF>, 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 NO<INF>X</INF> 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 NO<INF>X</INF> BART 
for other electric generating units. PNM submitted a table of the other 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> BART for the SJGS are far different from those that have 
been made in other states in determining NO<INF>X</INF> BART for other 
electric generating units. As the commenter's own table indicates, 
other states and EPA regions have made NO<INF>X</INF> 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 
NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \53\ 70 FR 39104, 39163.
---------------------------------------------------------------------------

C. Comments on Our Proposed SO<INF>2</INF> Emission Limit

    Comment: One commenter stated an SO<INF>2</INF> emission rate of 
0.15 lbs/MMBtu on a 30 day rolling average is not appropriate and does 
not ensure that SO<INF>2</INF> emissions from SJGS will not interfere 
with visibility in New Mexico or other states. This commenter believes 
an SO<INF>2</INF> 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 SO<INF>2</INF> limits significantly under 
0.15 lbs/MMBtu on a 30 day rolling average and concludes we should not 
set SO<INF>2</INF> emission rates in a Section 110 FIP that exceed the 
historic SO<INF>2</INF> emission rates at SJGS. The commenter requests 
that if we do set a non-BART SO<INF>2</INF> limit in our Section 110 
FIP, we set unit-specific limits at least consistent with the recent 
historic SO<INF>2</INF> emission identified in the table above, or 
issue formal SO<INF>2.</INF>BART determinations for each unit at SJGS 
under a Section 308 FIP.
    Response: We believe the SO<INF>2</INF> 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 
SO<INF>2</INF> 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 
SO<INF>2</INF> emissions simply means that the SO<INF>2</INF> 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 
SO<INF>2</INF> 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 SO<INF>2</INF> emission rate under the RHR 
requirements, the comments concerning BART are outside the scope of 
this action.

[[Page 52407]]

    Comment: In declining to find that its asserted SO<INF>2</INF> 
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 SO<INF>2</INF> 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 SO<INF>2</INF> BART emission limits. Our rationale for not 
proposing BART requirements for SO<INF>2</INF> in this action appears 
in our response just prior to this comment. Moreover, we note that the 
established SO<INF>2</INF> limits do not rely upon a nonexistent 
trading program. We will address New Mexico's obligation to address 
SO<INF>2</INF> under the RHR in a future separate action.

D. Comments on Our Proposed H<INF>2</INF>SO<INF>4</INF> 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, NO<INF>X</INF>, 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 
H<INF>2</INF>SO<INF>4</INF> and ammonia limits proposal for the SJGS, 
and the corresponding installation of CEMS. That commenter also urged 
us to set the H<INF>2</INF>SO<INF>4</INF> emission rate at the lowest 
rate of 1.06 x 10<SUP>-</SUP>\4\ lb/MMBtu for each unit at the SJGS, 
suggesting stack test monitoring for H<INF>2</INF>SO<INF>4</INF> 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 x10<SUP>-</SUP>\4\ lb/MMBtu 
based on an ammonia slip value of 0 ppm, compared to our original value 
of 1.06 x10<SUP>-</SUP>\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 
NO<INF>X</INF> 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 H<INF>2</INF>SO<INF>4</INF> emission 
limit of 2.6 x10<SUP>-</SUP>\4\ lb/MMBtu.
    Our intention in our proposal regarding the regulation and 
monitoring of ammonia was, like H<INF>2</INF>SO<INF>4</INF>, 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<INF></INF> control device 
(presumably, but not required to be SCR) must be designed to achieve a 
NO<INF>X</INF> 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 H<INF>2</INF>SO<INF>4</INF> 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 H<INF>2</INF>SO<INF>4</INF> on a more frequent basis 
than annual monitoring, we do not believe that an adequate continuous 
emissions monitor is available for H<INF>2</INF>SO<INF>4</INF> 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 H<INF>2</INF>SO<INF>4</INF> 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 
(SO<INF>3</INF>), and hence H<INF>2</INF>SO<INF>4</INF>, which is 
formed when SO3 combines with water in the flue gas to form 
H<INF>2</INF>SO<INF>4</INF>. In addition, SCR catalysts are available 
with a low SO<INF>2</INF> to SO3 conversion of 0.5%, further limiting 
the production of H<INF>2</INF>SO<INF>4</INF>. Therefore, we conclude 
we have struck the right balance.
---------------------------------------------------------------------------

    \54\ 76 FR 499.

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[[Page 52408]]

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 cost-effectiveness 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:
    <bullet> 13 months for 675 MW Somerset Station;
    <bullet> 18 months for Harding Street;
    <bullet> 19 months for two 900 MW units at Keystone.
    <bullet> 26 months for Asheville Power Station with a reported 
normal range of 27 to 30 months.
    <bullet> 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\
---------------------------------------------------------------------------

    \55\ ClearSkies: http://www.epa.gov/clearskies/03technical_package_sectiong.pdf.
---------------------------------------------------------------------------

    <bullet> 36 months for St John River Power Park, from contract 
award to startup.
    <bullet> 42 months for 14 SCRs installed to comply with the Texas 
Nonattainment SIP.
    <bullet> 60 months estimated by B&V for 5 units at Four Corners.
    <bullet> 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.
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    \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.
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    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 NO<INF>X</INF> burners, and new SO<INF>2</INF> 
scrubbers on seven units. Construction was completed faster than the 
Consent Decree schedule, however, and all of the controls were 
operating by May 2010.
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    \57\ U.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.
    \58\ U.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.
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    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.
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    \59\ Michael 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-plant-project-wins-award.html?nav=5010.
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    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

[[Page 52409]]

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 three-year 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 pre-construction 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 five-year, 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 NO<INF>X</INF> emissions, but would 
do little to reduce SO<INF>X</INF> or carbon dioxide (CO<INF>2</INF>) 
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 petroleum-based 
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 CO<INF>2</INF> are half those of a NGCC plant.
    The commenter calculates that a 50,000 barrel per day CTL plant can 
co-produces 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, NO<INF>X</INF> emissions would be 
reduced by 50 to 1, SO<INF>X</INF> emissions would be reduced by 20 to 
1, and CO<INF>2</INF> 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

[[Page 52410]]

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 (air-cooled condenser in conjunction with a 
cooling tower).
    The commenter points out that KinderMorgan has an existing 
CO<INF>2</INF> pipeline in the vicinity. The CO<INF>2</INF> 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 re-utilization of 
much of the plant, including coal handling equipment, steam turbines, 
condensers, cooling towers, and transmission lines. The re-utilization 
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 NO<INF>X</INF> 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 NO<INF>X</INF> 
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\
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    \60\ 70 FR 39104, 39164.
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    We agree with the commenter that the NO<INF>X</INF> BART 
determination in our proposal would reduce NO<INF>X</INF> emissions, 
yet would do little to reduce SO<INF>2</INF> and CO<INF>2</INF> 
emissions from the SJGS. SO<INF>2</INF> 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 NO<INF>X</INF> 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 (N<INF>2</INF>O) 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 PM<INF>2.5</INF> 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 NO<INF>X</INF> 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,. N<INF>2</INF>O--a GHG--does not belong to the 
NO<INF>X</INF> family, nor is it considered a visibility impairing 
pollutant.
    Comment: One commenter states that power plants are responsible for 
approximately one-quarter of the NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> emissions from power plants such as the SJGS. We agree 
that these emissions are detrimental to human health and the 
environment, with NO<INF>X</INF> 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

[[Page 52411]]

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 PM<INF>2.5</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> for 
SJGS.
    We disagree with the commenter's belief that our proposal is 
counter-productive. 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-NO<INF>X</INF> 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 NO<INF>X</INF> from our NO<INF>X</INF> BART 
determination and the SO<INF>2</INF> emission limits will serve to 
ensure there are enforceable mechanisms in place to prohibit New Mexico 
NO<INF>X</INF> and SO<INF>2</INF> 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

[[Page 52412]]

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
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    \61\ States must consider the following factors in making BART 
determinations: (1) The costs of compliance; (2) the energy and 
nonair quality environmental impacts of compliance; (3) any existing 
pollution control technology in use at the source; (4) the remaining 
useful life of the source; and (5) the degree of improvement in 
visibility which may reasonably be anticipated to result from the 
use of such technology. 40 CFR 51.308(e)(1)(ii)(A).
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    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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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

[[Page 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 NO<INF>X</INF>, SO<INF>2,</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> and SO<INF>2</INF> 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 NO<INF>X</INF>.
    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 NO<INF>X</INF> and SO<INF>2</INF> 
emission limits at the SJGS to prevent interference with other states' 
visibility SIPs as well as requiring BART

[[Page 52414]]

for NO<INF>X</INF> 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 visibility-causing 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.
---------------------------------------------------------------------------

    \62\ WildEarth Guardians v. Lisa Jackson, Case No. 4:09-CV-
02453-CW.
---------------------------------------------------------------------------

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 PM<INF>2.5</INF> 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 NO<INF>X</INF> 
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

[[Page 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 NO<INF>X</INF> 
(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 PM<INF>2.5</INF> 
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 NO<INF>X</INF> 
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 PM<INF>2.5</INF> 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 3\1/2\ 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

[[Page 52416]]

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.
---------------------------------------------------------------------------

    \63\ See, ``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 PM<INF>2.5</INF> 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'').
---------------------------------------------------------------------------

    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 NO<INF>X</INF> 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 
PM<INF>2.5</INF> 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

[[Page 52417]]

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 NO<INF>X</INF> 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 NO<INF>X</INF> emissions used in the WRAP 
photochemical modeling and that federally enforceable emission limits 
are required in order to meet the SO<INF>2</INF> 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 NO<INF>X</INF> BART requirements 
for the SJGS. To meet this separate requirement, we have determined 
that specific NO<INF>X</INF> 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

[[Page 52418]]

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.
---------------------------------------------------------------------------

    \64\ See, 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).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \65\ Subsequent 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.
---------------------------------------------------------------------------

    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

[[Page 52419]]

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 NO<INF>X</INF> 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 SO<INF>2</INF> limit and a NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> BART 
determination for the SJGS. To prevent a possible conflict between a 
NO<INF>X</INF> visibility transport emission limitation FIP for the 
SJGS and the NO<INF>X</INF> RH BART emission limitation FIP for the 
SJGS, we chose to promulgate now, rather than later, the NO<INF>X</INF> 
RH BART determination for the SJGS. We are combining the requirements 
of section 110(a)(2)(D)(i)(II) for NO<INF>X</INF> with a NO<INF>X</INF> 
BART evaluation (40 CFR 51.308) to be efficient and provide greater 
certainty to the source as to the appropriate NO<INF>X</INF> controls 
needed to meet those two separate but related requirements.
    This FIP also will impose a federally enforceable limit on the 
emissions of SO<INF>2</INF> from the SJGS based upon the WRAP 
determination of each member state's contribution to visibility 
impairment of SO<INF>2</INF> emissions, of which New Mexico is a 
member. The SJGS's existing SO<INF>2</INF> permit does not provide the 
necessary emission limits and enforceable mechanisms to ensure the 
SO<INF>2</INF> emissions used in the WRAP photochemical modeling for 
the SJGS units will be met. Therefore, we assumed the SO<INF>2</INF> 
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 NO<INF>X</INF> emissions sufficiently. The commenter also 
argued that pollutants other than NO<INF>X</INF> cause interference 
with other states' visibility programs and should be considered instead 
of reducing NO<INF>X</INF> emissions under BART because the commenter 
believes NO<INF>X</INF> 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 NO<INF>X</INF> and 
SO<INF>2</INF> emission limits necessary at the SJGS to prevent such 
interference, as well as to meet the requirement for BART for 
NO<INF>X</INF> 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

[[Page 52420]]

states' measures to protect visibility, and to implement NO<INF>X</INF> 
and SO<INF>2</INF> emission limits necessary at one source, the SJGS, 
to prevent such interference, as well as BART for NO<INF>X</INF> for 
this source.
    We determined that enacting a NO<INF>X</INF> BART determination for 
SJGS was necessary because the WRAP analyses showed that NO<INF>X</INF> 
emissions in general and SJGS NO<INF>X</INF> emissions, specifically, 
contribute significantly to haze in the West. SJGS is by far the 
largest source of NO<INF>X</INF> emissions in NM. Our FIP requires 
substantial reductions in NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> for the SJGS, because 
NO<INF>X</INF> emissions from SJGS are a significant source of 
NO<INF>X</INF> 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 
NO<INF>X</INF> reductions and federally enforceable SO<INF>2</INF> 
limits at SJGS.
    We also specifically disagree with the commenter's statement that 
NO<INF>X</INF> 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 NO<INF>X</INF> BART 
modeling demonstrates, reducing NO<INF>X</INF> 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 
NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \66\ 70 FR 39104, 39120.
---------------------------------------------------------------------------

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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 decision-
making 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

[[Page 52421]]

properly implement the programs under both sections.
    Response: We are not requiring NO<INF>X</INF> BART for the SJGS 
under section 110 of the CAA. We are requiring NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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 site-specific, plant-wide manner 
employed by Region 9.
    Another commenter states the proposal fails to consider other BART-
eligible 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 
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 NO<INF>X</INF> 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\
---------------------------------------------------------------------------

    \67\ Supplemental Proposed Rule of Source Specific Federal 
Implementation Plan for Implementing Best Available Retrofit 
Technology for Four Corners Power Plant: Navajo Nation, 76 FR 10530.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> BART determinations for 
Oklahoma \68\ and the NO<INF>X</INF> 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 NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \68\ Id.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> BART 
determination for the SJGS and promulgate a NO<INF>X</INF> 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

[[Page 52422]]

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.
---------------------------------------------------------------------------

    \69\ See Exhibit 1 RTC Revised Cost Analysis, lines 91, Cost 
Analysis Fox.
---------------------------------------------------------------------------

    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 re-establishes 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

[[Page 52423]]

necessary long term strategies and BART requirements for stationary 
source PM and NO<INF>X</INF> emissions. Any such BART provisions may be 
submitted pursuant to either Sec.  51.308(e)(1) or Sec.  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 NO<INF>X</INF> 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 NO<INF>X</INF> 
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 SO<INF>2</INF> and NO<INF>X</INF> 
from the SJGS are interfering with efforts to protect visibility in 
other states, as well as impacting Class I areas within NM.
---------------------------------------------------------------------------

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

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-
to-BART 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 SO<INF>2</INF>, 
NO<INF>X</INF>, 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 
SO<INF>2</INF>, NO<INF>X</INF>, and PM emissions was above the 0.5 dv 
significance threshold (i.e., PNM's SJGS Boilers <greek-i>1-4). Of the 
10 other sources, none were above a 0.33 dv impact. Consequently, only 
the PNM's SJGS Boilers <greek-i>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

[[Page 52424]]

sources. These 10 sources are sufficiently controlled to eliminate 
interference with other states' visibility programs.
---------------------------------------------------------------------------

    \71\ BART-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.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> 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 
NO<INF>X</INF>/MMBtu on a longer-term basis (30 day rolling average) as 
currently reflected in their permit and 0.33 lb of NO<INF>X</INF>/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 NO<INF>X</INF> 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

[[Page 52425]]

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 NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \73\ NMED 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.
---------------------------------------------------------------------------

    In the photochemical modeling, the emission rate used in the 
baseline inventory was based on a NO<INF>X</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF>/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 
NO<INF>X</INF> 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 NO<INF>X</INF> 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

[[Page 52426]]

that source was determined to be subject to BART. The 10,500 tpy 
NO<INF>X</INF> reduction mentioned by the commenter refers to the 
reduction in NO<INF>X</INF> 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 
NO<INF>X</INF> 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 Sec.  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 NO<INF>X</INF> and 
SO<INF>2</INF> emission limits necessary at the SJGS to prevent such 
interference, as well as to meet the requirement for BART for 
NO<INF>X</INF> 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 SO<INF>2</INF> 
baseline and future emission rate of 0.15 lbs/MMBtu was incorrect, and 
that an SO<INF>2</INF> 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 SO<INF>2</INF> rate is that the lower rate is expected 
in the future. The commenter argues that utilizing the current 
SO<INF>2</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> BART proposed controls, we included 
the SO<INF>2</INF> emissions as relied upon in the WRAP modeling in our 
CALPUFF modeling. The SO<INF>2</INF> emission limit of 0.15 lb/MMBtu 
that we input into the NO<INF>X</INF> BART visibility modeling is based 
upon what was relied upon in the WRAP modeling. Our FIP makes this 
WRAP-relied upon SO<INF>2</INF> limit of 0.15 lb/MMBtu federally 
enforceable. PNM's requested baseline emission rate of 0.18 lb/MMBtu of 
SO<INF>2</INF> is not what was relied upon in the WRAP modeling.
---------------------------------------------------------------------------

    \74\ Memo 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
---------------------------------------------------------------------------

    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 SO<INF>2</INF> control technology installed and has 
current actual SO<INF>2</INF> emissions below our proposed FIP limit. 
As a result, the facility will not have to install additional controls 
to meet our SO<INF>2</INF> FIP limit. As we are setting the 0.15 lb/
MMBtu SO<INF>2</INF> emission limit in the FIP for SJGS, we modeled an 
emission rate of 0.15 lb/MMBtu for SO<INF>2</INF> for both the baseline 
(current) and control (future) cases in estimating the anticipated 
visibility improvement due to installation of the NO<INF>X</INF> BART 
proposed controls. By holding the SO<INF>2</INF> emissions constant in 
the revised baseline (current) and future (control) cases, the modeled 
predicted improvements in visibility due to the NO<INF>X</INF> BART 
proposed controls are kept separate from any potential changes in 
visibility due to changes in SO<INF>2</INF> emissions. This means the 
final CALPUFF analysis reflects only the benefits due to the additional 
NO<INF>X</INF> reductions beyond the baseline. This also reflects the 
SJGS's flexibility to increase its SO<INF>2</INF> emissions up to the 
SO<INF>2</INF> FIP limit of 0.15 lb/MMBtu. It provides a more 
representative estimate of anticipated visibility improvements from 
installation of NO<INF>X</INF> controls.
---------------------------------------------------------------------------

    \75\ Page 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.
---------------------------------------------------------------------------

    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 SO<INF>2</INF> (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 NO<INF>X</INF> 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 NO<INF>X</INF>. 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

[[Page 52427]]

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 NO<INF>X</INF> BART, we 
conducted our own visibility impact analysis (the degree of visibility 
improvement reasonably anticipated due to NO<INF>X</INF> BART at SJGS). 
In conducting modeling for our proposed NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF> BART emission limit, ranging from 38 to 56% improvement, 
depending on the background ammonia and post-processing 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 SO<INF>2</INF> and 
NO<INF>X</INF> 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 
NO<INF>X</INF> burners installed on all four units at SJGS during the 
environmental upgrade project between 2007 and 2009 meet the 
requirements for NO<INF>X</INF> BART.
    Response: Our technical modeling analysis accounted for the 
visibility improvements achieved by existing controls at the SJGS by 
incorporating the SO<INF>2</INF> and NO<INF>X</INF> 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 NO<INF>X</INF> 
controls as part of our proposal reflected the visibility improvement 
due to installation of additional NO<INF>X</INF> 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 
NO<INF>X</INF> BART analysis including a CALPUFF modeling analysis 
performed by B&V prior to the installation of controls under the 2005 
consent decree. Low-NO<INF>X</INF> burners do not satisfy the 
requirements for NO<INF>X</INF> BART for the SJGS; they are not 
supported by the NO<INF>X</INF> BART five-factor analysis.
    Comment: We received comments suggesting that modeling should be 
performed using an emission rate of 0.07lbs NO<INF>X</INF>/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 NO<INF>X</INF> 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 
NO<INF>X</INF> 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 
NO<INF>X</INF> 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 less-than-
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

[[Page 52428]]

may still be determined to be significant.
    Comment: A commenter asserted that EPA's proposed reductions of 
NO<INF>X</INF> 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 
NO<INF>X</INF> 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, side-
by-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 
NO<INF>X</INF> and SO<INF>2</INF> 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 
NO<INF>X</INF> emissions were 312,193 tpy (Plan02d) and SJGS 
corresponding emissions were 30,353 tpy of NO<INF>X</INF>, only the 
amount of EPA's adjustment could significantly impact out-of-state 
visibility impairment when the State's total NO<INF>X</INF> 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 NO<INF>X</INF> reductions in the WRAP modeling 
for the SJGS as 10,590 tpy and then approximated the amount of 
NO<INF>X</INF> emission reductions from SJGS under EPA's scheme to 
prevent New Mexico's ``interference'' as approximately 2,200 tpy of 
NO<INF>X</INF> after considering the consent decree reductions of 8,411 
tpy since 2002. They then commented that if SJGS's current (Plan02d) 
2002 NO<INF>X</INF> 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 NO<INF>X</INF> reduction needed 
by 2018 to prevent interference. Commenter indicated that EPA's 
proposal under Sec.  110(a)(2)(D)(i)(II) to retrofit SJGS's generating 
units with SCR could achieve roughly 4 times the amount of 
NO<INF>X</INF> emission reductions actually required and EPA's proposed 
NO<INF>X</INF> emission reductions from the SJGS are excessive.
    Response: We disagree with the assertion that EPA must separate the 
required NO<INF>X</INF> emission reductions required by SJGS to meet 
section 110(a)(2)(D)(i)(II) requirements from the NO<INF>X</INF> 
emission reductions required to meet the NO<INF>X</INF> BART 
determination for SJGS. EPA also disagrees that we are required to 
conduct a modeling analysis to determine if the NO<INF>X</INF> 
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 NO<INF>X</INF> 
emissions in the WRAP modeling were not being achieved by SJGS, and how 
NO<INF>X</INF> 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 NO<INF>X</INF> 
emission limits that will eliminate interstate interference and at the 
same time address the RH BART requirement for NO<INF>X</INF> 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 NO<INF>X</INF>/MMBtu and 0.15 lb of SO<INF>2</INF>/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 
NO<INF>X</INF> without installing additional NO<INF>X</INF> controls. 
PNM claims that the actual emission rate was approximately 0.30 lb of 
NO<INF>X</INF>/MMBtu on a longer-term basis as reflected in the permit 
and 0.33 lb of NO<INF>X</INF>/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\
---------------------------------------------------------------------------

    \76\ Id.
---------------------------------------------------------------------------

    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 SO<INF>2</INF> and NO<INF>X</INF> emissions 
relied upon in the

[[Page 52429]]

WRAP modeling for the SJGS, however, are not federally enforceable. 
Therefore, we are establishing federally enforceable emission limits 
for SO<INF>2</INF> and NO<INF>X</INF> 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 NO<INF>X</INF> and 0.15 lb/MMBtu SO<INF>2</INF> was 5.15dv at 
Mesa Verde Class I area. We also modeled visibility impacts using 0.33 
lb/MMBtu NO<INF>X</INF> and 0.18 lb/MMBtu SO<INF>2</INF> in our initial 
modeling to compare model results with those presented by PNM and NMED. 
We note that reducing SO<INF>2</INF> 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 SO<INF>2</INF> emissions compared to the large changes in 
visibility due to decreasing NO<INF>X</INF> emissions at SJGS, as shown 
in our modeling of the 0.05 lb of NO<INF>X</INF>/MMBtu emission rate 
(SCR case). The use of 0.15 lb/MMBtu SO<INF>2</INF> emission rate is 
discussed in a separate response to comment. Considering that the 0.33 
lb/MMBtu NO<INF>X</INF> value is approximately 20% greater than the 
0.27/0.28 rate, the significant visibility impacts, and the 
NO<INF>X</INF> sensitivity demonstrated by the modeling, it is clear 
this difference in emission rates can have a significant impact on 
visibility. Even on a long-term 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 
NO<INF>X</INF> and SO<INF>X</INF> 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 NO<INF>X</INF> 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 
NO<INF>X</INF>, compared to a much greater tonnage of NO<INF>X</INF> 
emissions from a variety of sources that are 100s of kilometers away. 
Much of the New Mexico NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 
NO<INF>X</INF> 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

[[Page 52430]]

individually and significantly impacted by emissions from the SJGS. The 
number of days per year significantly impacted by the facility's 
NO<INF>X</INF> emissions is expected to decrease drastically at each 
Class I area (Table 6-8 of the TSD) as the result of installation of 
NO<INF>X</INF> BART emission controls at the SJGS. Clearly, the 
visibility benefits from NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \78\ 70 FR 39170.
---------------------------------------------------------------------------

    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 NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \79\ 70 FR 39118. Impacts of 1 deciview or greater are 
considered to cause a visibility impairment.
---------------------------------------------------------------------------

    In fully considering the visibility benefits anticipated from the 
use of an available control technology as one of the factors in 
selection of NO<INF>X</INF> 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 
NO<INF>X</INF> 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 NO<INF>X</INF> 
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 
NO<INF>X</INF> BART modeling analysis is internally inconsistent 
because we rely on Method 6 for SO<INF>2</INF> (using the WRAP 
modeling) and on Method 8 modeling for NO<INF>X</INF>. 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 NO<INF>X</INF>. 
We believe that this, however, more accurately reflects real visibility 
conditions.
---------------------------------------------------------------------------

    \80\ Revised 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).
---------------------------------------------------------------------------

    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

[[Page 52431]]

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 NO<INF>X</INF> BART. However, regardless of which IMPROVE equation 
is used, New Mexico did not provide federally enforceable limitations 
on SJGS' SO<INF>2</INF> and NO<INF>X</INF> 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 NO<INF>X</INF> 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 NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \81\ U.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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \82\ 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, available at http://www.nature.nps.gov/air/Pubs/pdf/flag/FLAG_2010.pdf.
---------------------------------------------------------------------------

    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 non-guideline 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

[[Page 52432]]

credence to the need for a full review of the revised modeling systems 
before considering the modeling results for any decision 
making.<SUP>84 85</SUP> 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.
---------------------------------------------------------------------------

    \83\ Comparison of model results presented by commenter with 
values in our TSD Chapter 6.
    \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.''
    \85\ 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).
---------------------------------------------------------------------------

    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 post-processing 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 
Bridger-Teton 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

[[Page 52433]]

Other Analyses for Demonstrating Attainment of Air Quality Goals for 
Ozone, PM<INF>2.5</INF>, 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 
well-recognized 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\
---------------------------------------------------------------------------

    \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.
    \87\ Comment Letter from EPA Region 6 to TCEQ dated February 13, 
2007 regarding TCEQ Final Report ``Screening Analysis of Potential 
BART-Eligible Sources in Texas'', December 2006.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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, PM<INF>2.5</INF> 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.
---------------------------------------------------------------------------

    \89\ Personal communications with Mr. Tyler Fox to verify 
guidance given at meeting pertaining to alternate CALPUFF versions. 
July 29, 2011.
---------------------------------------------------------------------------

    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.

[[Page 52434]]

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 
NO<INF>X</INF> and SO<INF>2</INF> 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.
---------------------------------------------------------------------------

    \90\ Sather, 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'').
---------------------------------------------------------------------------

    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 SO<INF>2</INF> 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

[[Page 52435]]

modeling to support our action on SO<INF>2</INF> 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 BART-eligible 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 
NO<INF>X</INF> 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.
---------------------------------------------------------------------------

    \91\ CALMET/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/
regionalstatelocalmodelingworkshop/archive/2007/presentations/
Wednesday%20[dash]%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/regionalstatelocalmodelingworkshop/archive/2008/presentations/BRODE_CA.pdf).
---------------------------------------------------------------------------

    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 NO<INF>X</INF> 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 
NO<INF>X</INF>/MMBtu (NMED/PNM modeling used an emission rate of 0.07 
lb of NO<INF>X</INF>/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

[[Page 52436]]

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 non-approved 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 NO<INF>X</INF> 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

[[Page 52437]]

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 NO<INF>X</INF> 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 H<INF>2</INF>SO<INF>4</INF> and NH<INF>3</INF> emissions 
from the SJGS. The commenter indicated that if EPA has not shown that 
limits on emissions of H<INF>2</INF>SO<INF>4</INF> and NH<INF>3</INF> 
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 Sec.  169A to require the proposed 
emission limits on those pollutants from SJGS. The commenter also 
alleged that if EPA has not shown interference from 
H<INF>2</INF>SO<INF>4</INF> or NH<INF>3</INF> 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 
visibility-impairment 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 SO<INF>2</INF>, NO<INF>X</INF> and PM. 
The commenter concluded that any proposal by EPA to limit emissions of 
either H<INF>2</INF>SO<INF>4</INF> or NH<INF>3</INF> 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 H<INF>2</INF>SO<INF>4.</INF> If a power plant is installing 
SCR at an existing facility in an area where a state has a concern 
about PM<INF>2.5</INF> and regional haze impacts, it would be normal 
for a state to consider the imposition of limits on 
H<INF>2</INF>SO<INF>4</INF> 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 
(SO<INF>3</INF>), and hence H<INF>2</INF>SO<INF>4</INF>, which is 
formed when SO<INF>3</INF> combines with water in the flue gas to form 
H<INF>2</INF>SO<INF>4</INF>. In addition, SCR catalysts are available 
with a low SO<INF>2</INF> to SO<INF>3</INF> conversion of 0.5%, further 
limiting the production of H<INF>2</INF>SO<INF>4</INF>. Nevertheless, 
we conducted several modeling runs with different 
H<INF>2</INF>SO<INF>4</INF> emission levels and that modeling indicated 
that increases in H<INF>2</INF>SO<INF>4</INF> did result in some 
visibility degradation at Class I areas in New Mexico and surrounding 
states. The H<INF>2</INF>SO<INF>4</INF> runs can be found in the TSD 
and its appendices or in the RTC for this action. Some of the 
H<INF>2</INF>SO<INF>4</INF> runs were not used in the final decision 
modeling analysis, but provided a basis for being concerned about 
potential H<INF>2</INF>SO<INF>4</INF> impacts and thus limiting the 
amount of growth in H<INF>2</INF>SO<INF>4</INF> from our action.
    In summary, we conclude that emissions of 
H<INF>2</INF>SO<INF>4</INF> 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 H<INF>2</INF>SO<INF>4</INF> are not limited in 
an enforceable manner. We do not wish to allow a growth in emissions to 
occur that would undermine the NO<INF>X</INF> 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 H<INF>2</INF>SO<INF>4</INF> to a reasonable level verified 
by annual stack testing. We are controlling H<INF>2</INF>SO<INF>4</INF> 
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

[[Page 52438]]

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

[[Page 52439]]

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]

0
1. The authority citation for part 52 continues to read as follows:

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

Subpart GG--[Amended]

0
2. Section 52.1628 is added to read as follows:


Sec.  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) SO<INF>2</INF>: No later than 5 years after September 21, 2011.
    (ii) NO<INF>X</INF>: No later than 5 years after September 21, 
2011.
    (iii) H<INF>2</INF>SO<INF>4</INF>: 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 NO<INF>X</INF>, 
SO<INF>2</INF>, or H<INF>2</INF>SO<INF>4</INF> 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 O<INF>2</INF> 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 NO<INF>X</INF> control device included in this plan shall 
be designed to meet the NO<INF>X</INF> 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 NO<INF>X</INF> emission rate limit 
for each unit in the plant, expressed as nitrogen dioxide 
(NO<INF>2</INF>), shall be 0.05 pounds per million British thermal 
units (lbs/MMBtu), as averaged over a rolling 30 boiler-operating-day 
period. The hourly NO<INF>X</INF> and O<INF>2</INF> data used to 
determine the NO<INF>X</INF> emission rates shall be in compliance with 
the requirements in part 75 of this chapter. For each unit on each 
boiler-operating-day, the hourly NO<INF>X</INF> emissions measured in 
lbs/MMBtu, shall be averaged over the hours the unit was in operation 
to obtain a daily boiler-operating-day average. Each day, the 30-day-
rolling average NO<INF>X</INF> 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 SO<INF>2</INF> 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 boiler-
operating-day period. The hourly NO<INF>X</INF> and O<INF>2</INF> data 
used to determine the NO<INF>X</INF> emission rates shall be in 
compliance with the requirements in part 75 of this chapter. For each 
unit on each boiler-

[[Page 52440]]

operating-day, the hourly SO<INF>2</INF> emissions measured in lbs/
MMBtu, shall be averaged over the hours the unit was in operation to 
obtain a daily boiler-operating-day average. Each day, the 30-day-
rolling average SO<INF>2</INF> 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 
H<INF>2</INF>SO<INF>4</INF> from each unit shall be limited to 2.6 x 
10<SUP>-</SUP>\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 
NO<INF>X</INF>, SO<INF>2</INF>, stack gas flow rate, and O<INF>2</INF> 
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 NO<INF>X</INF>, SO<INF>2</INF>, stack 
gas flow rate, and O<INF>2</INF> that have been certified for use under 
the Acid Rain Program, and that are continuing to meet the on-going 
quality-assurance requirements of that program, satisfy the 
requirements of this paragraph (e)(1). Compliance with the emission 
limits for NO<INF>X</INF> and SO<INF>2</INF> 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 
SO<INF>2</INF>, NO<INF>X</INF>, and O<INF>2</INF> 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 H<INF>2</INF>SO<INF>4</INF> shall be measured 
within 180 days of start up of the NO<INF>X</INF> 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 
SO<INF>2</INF>, and NO<INF>X</INF>, in this section, the owner or 
operator shall comply with the excess emission reporting requirements 
in Sec. Sec.  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 SO<INF>2</INF> and NO<INF>X,</INF> 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.


0
3. Section 52.1629 is added to read as follows:


Sec.  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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