[Federal Register Volume 76, Number 162 (Monday, August 22, 2011)]
[Rules and Regulations]
[Pages 52388-52440]
[FR Doc No: 2011-20682]

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

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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 (PM2.5)
NAAQS. In this action, EPA is disapproving the New Mexico Interstate
Transport SIP provisions that address the requirement of section
110(a)(2)(D)(i)(II) that emissions from New Mexico sources do not
interfere with measures required in the SIP of any other state under
part C of the CAA to protect visibility. We have found that New Mexico
sources, except the San Juan Generating Station, are sufficiently
controlled to eliminate interference with the visibility programs of
other states. EPA is promulgating a Federal Implementation Plan (FIP)
to address this deficiency by implementing nitrogen oxides
(NOX) and sulfur dioxide (SO2) emission limits
necessary at the San Juan Generating Station (SJGS), to prevent such
interference. EPA found in January 2009 that New Mexico had failed to
submit a SIP addressing certain regional haze (RH) requirements,
including the requirement for best available retrofit technology
(BART). The Clean Air Act required EPA to promulgate a FIP to address
RH requirements by January 2011. This FIP addresses the RH BART
requirement for NOX for SJGS. In addition, EPA is
implementing sulfuric acid (H2SO4) hourly
emission limits at the SJGS, to minimize the contribution of this
compound to visibility impairment. This action is being taken under
section 110 and part C of the CAA.

DATES: This final rule is effective on: September 21, 2011.

ADDRESSES: EPA has established a docket for this action under Docket ID
No. EPA-R06-OAR-2010-0846. All documents in the docket are listed in
the Federal eRulemaking portal index at http://www.regulations.gov and
are available either electronically at http://www.regulations.gov or in
hard copy at EPA Region 6, 1445 Ross Ave., Dallas, TX 75202-2733. To
inspect the hard copy materials, please schedule an appointment during
normal business hours with the contact listed in the FOR FURTHER
INFORMATION CONTACT section. A reasonable fee may be charged for
copies.

FOR FURTHER INFORMATION CONTACT: Joe Kordzi, EPA Region 6, (214) 665-
7186<EMAIL_ADDRESS>
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

extended the time for compliance with the nitrogen oxide pollution
emission limit from 3 years to 5 years, the maximum period allowed by
the Clean Air Act.
    This investment will reduce the visibility impacts due to this
facility by over 50% at each one of the 16 national parks and
wilderness areas in the area, and promote local tourism by decreasing
the number of days when pollution impairs scenic views. Although
today's action is taken to address visibility impairments, PNM will
also reduce public health impacts by cutting NOX pollution
by over 80% by installing reliable pollution-control technology on its
four coal-fired power generation units over the next five years.
    EPA will review the regional haze plan that the State submitted in
July 2011, and if there is significant new information that changes our
analysis, EPA will make appropriate revisions to today's decision.

Detailed Outline

I. Summary of Our Proposal
II. Final Decision
    A. Interstate Transport
    B. NOX BART Determination for the San Juan Generating
Station (SJGS)
    C. Compliance Timeframe
III. Analysis of Major Issues Raised by Commenters
    A. Comments on the Costs of the NOX BART
Determination
    B. Comments on our Proposed NOX BART Emission Limits
    C. Comments on our Proposed SO2 Emission Limit
    D. Comments on our Proposed H2SO4 and
Ammonia Emission Limits and Other Pollutants
    E. Comments on the Emission Limit Compliance Schedule
    F. Comments on the Conversion of the SJGS to a Coal-to-Liquids
Plant With Carbon Capture as a Means of Satisfying BART
    G. Comments on Health and Ecosystem Benefits, and Other
Pollutants
    H. Miscellaneous Comments
    I. Comments in Favor of Our Proposal
    J. Comments Arguing Our Proposal Would Hurt the Economy and/or
Raise Electricity Rates
    K. Comments Arguing Our Proposal Would Help the Economy
    L. Comments Requesting an Extension to the Public Comment Period
    M. Comments Requesting We Defer Action in Favor of a New Mexico
SIP Submittal
    N. Comments Generally Against Our Proposal
    O. Comments on Legal Issues
    P. Modeling Comments
IV. Statutory and Executive Order Reviews

I. Summary of Our Proposal

    On January 5, 2011, we published the proposal on which we are now
taking final action. 76 FR 491. We proposed to disapprove a portion of
the SIP revision received from the State of New Mexico on September 17,
2007, for the purpose of addressing the ``good neighbor'' provisions of
the CAA section 110(a)(2)(D)(i) with respect to visibility for the 1997
8-hour ozone NAAQS and the PM2.5 NAAQS. Having proposed to
disapprove these provisions of the New Mexico SIP, we proposed a FIP to
address the requirements of section 110(a)(2)(D)(i)(II) with respect to
visibility to ensure that emissions from sources in New Mexico do not
interfere with the visibility programs of other states. We proposed to
find that New Mexico's sources, other than the San Juan Generating
Station (SJGS), are sufficiently controlled to eliminate interference
with the visibility programs of other states, and for the SJGS, we
proposed specific SO2 and NOX emissions limits
that will eliminate such interstate interference. For SO2,
we proposed to require the SJGS to meet an emission limit of 0.15
pounds per million British Thermal Units (lb/MMBtu). For
NOX, we proposed to implement a NOX emission
limit of 0.05 lbs/MMBtu, based on our BART determination, as discussed
below.
    Separate from our proposal under Section 110 of the CAA, we
simultaneously evaluated whether the SJGS met certain other related
requirements under the Regional Haze (RH) program under Sections 169A
and 169B of the CAA. Regional Haze SIPs were due December 17, 2007. In
January 2009, we made a finding that New Mexico had failed to submit a
RH SIP addressing the requirements of 40 CFR 51.309(d)(4) and (g). 74
FR 2392 (January 15, 2009). Under the CAA, we are required to
promulgate a FIP within two years of the effective date of a finding
that a State has failed to submit a SIP unless the State submits a SIP
and we approve that SIP within the two year period. CAA 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 NOX. (On July 5,
2011, New Mexico submitted a RH SIP, which we discuss later in this
Notice.) Based on our evaluation of the RH BART requirements of section
40 CFR 51.309(d)(4), we proposed to find that the SJGS is subject to
BART under section 40 CFR 51.309(d)(4), and/or 51.308(e). We proposed a
FIP which contained NOX BART limits for the SJGS based on
our proposed NOX BART determination. We proposed to require
that the SJGS meet a NOX emission limit of 0.05 lb/MMBtu
individually at Units 1, 2, 3, and 4. We noted this NOX
limit is achievable by installing and operating Selective Catalytic
Reduction (SCR).
    We proposed that both the NOX and SO2
emission limits be measured on the basis of a 30 day rolling average.
We also proposed hourly average emission limits of 1.06 x
10-4 lb/MMBtu for H2SO4 and 2.0 parts
per million volume dry (ppmvd) ammonia adjusted to 6 percent oxygen, to
minimize the contribution of these compounds to visibility impairment.
We solicited comments on a range of 2-6 ppmvd for ammonia, and 1.06 x
10-4 to 7.87 x 10-4 lb/MMBtu for
H2SO4. Additionally, we proposed monitoring,
record-keeping and reporting requirements to ensure compliance with
these emission limitations.
    Lastly, we proposed that compliance with the emission limits must
be within three (3) years of the effective date of our final rule. We
solicited comments on alternative timeframes, up to five (5) years from
the effective date our final rule. In our proposal, we did not address
whether the state had met other requirements of the RH program, which
we will address in later actions. Please see our proposal for more
details.

II. Final Decision

A. Interstate Transport

    We are disapproving the portion of the SIP revision received from
the State of New Mexico on September 17, 2007, for the purpose of
addressing the ``good neighbor'' provisions of the CAA section
110(a)(2)(D)(i) with respect to visibility for the 1997 8-hour ozone
NAAQS and the PM2.5 NAAQS. The 2007 SIP submission by New
Mexico anticipated that the State would submit a substantive RH SIP to
meet the requirements of section 110(a)(2)(D)(i)(II).
    Section 110(a)(2)(D)(i)(II) of the CAA requires that states have a
SIP, or submit a SIP revision, containing provisions ``prohibiting any
source or other type of emission activity within the state from
emitting any air pollutant in amounts which will * * * interfere with
measures required to be included in the applicable implementation plan
for any other State under part C [of the CAA] to protect visibility.''
States were required to submit a SIP by December 2007 with measures to
address regional haze--visibility impairment that is caused by the
emissions of air pollutants from numerous sources located over a wide
geographic area. Under the RH program, each State with a Class I area
must submit a SIP with reasonable progress goals for each such area
that provides for an improvement in visibility for the

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 SO2 and NOX emissions relied
upon in the WRAP modeling for the SJGS, however, are not federally
enforceable. Therefore, we are establishing federally enforceable
SO2 emissions limits that will address these discrepancies
and eliminate interstate interference based on current emissions that
satisfy the assumptions in the WRAP modeling. We are finalizing our
proposal to require the SJGS to meet an SO2 emission limit
of 0.15 lb/MMBtu, the rate assumed in the WRAP modeling. We proposed a
30 day rolling average for units 1, 2, 3, and 4 of the SJGS. However,
in response to a comment we received, we are changing our proposed
averaging period for these emission limits from a straight 30 day
calendar average to one calculated on the basis of a Boiler Operating
Day (BOD).
    Besides not being federally enforceable, the NOx emissions that
were assumed in the WRAP modeling cannot be achieved without additional
NOx controls for the SJGS to prevent interference with visibility
pursuant to the requirements of section 110(a)(2)(D)(i)(II) of the CAA.
We are choosing, however, not to use the WRAP assumptions to make a
determination on the enforceable NOx controls necessary to prevent
visibility interference, as we are doing for the SO2
controls. Instead, we are addressing NOx control for the SJGS by
fulfilling our duty under the BART provisions of the RH rule to
promulgate a RH FIP for New Mexico to address, among other elements of
the visibility program, the requirement for BART.\2\ We do not believe
it is prudent to delay a NOx BART determination for the SJGS, because
we have determined that the BART requirements are more stringent than
the visibility transport requirements. Separating the visibility
transport and BART rulemakings could result in near-term requirements
for the utility to install one set of controls and capital
expenditures, to only satisfy our obligation under section
110(a)(2)(D)(i)(II), followed shortly thereafter by different
requirements for controls and capital expenditures to satisfy our
obligation under BART. This could result in unnecessary costs and
confusion.
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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

can be addressed prior to the installation of the emission controls
required to satisfy our FIP.
    We are also finalizing our proposal requiring the SJGS to meet an
H2SO4 emission limit of 2.6 x 10-4 lb/
MMBtu to minimize its contribution to visibility impairment. We are
promulgating monitoring, record-keeping and reporting requirements to
ensure compliance with this emission limit. As discussed in our
response to comments, after careful consideration of the comments we
received concerning our proposal to require the SJGS to meet an hourly
average emission limit of 2.0 parts ppmvd for ammonia, we have
determined that neither an ammonia limit, nor ammonia monitoring is
warranted, and we are not finalizing ammonia limits or monitoring
requirements.

C. Compliance Timeframe

    We originally proposed a compliance schedule of 3 years for SJGS
for the NOX, SO2, ammonia, and
H2SO4 emission limits, and solicited comments on
alternative timeframes of less than 3 years and up to 5 years (the
maximum allowed under the statute).\4\ As noted above, we are no longer
requiring an ammonia emission limit. Also, as discussed in our response
to comments, we carefully considered comments urging a longer
compliance schedule due to site-specific issues such as the congestion
of existing equipment (which could slow the retrofit process),
historical information on SCR installation times, and our own
observation of the site conditions,\5\ and we now conclude that a
longer compliance schedule is more appropriate. Consequently,
compliance with the NOX, SO2, and
H2SO4 emission limits will now be required within
5 years--rather than 3 years--of the effective date of our final rule.
(This issue is discussed in further detail in Section III.E., below.)
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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
------------------------------------------------------------------------

    We note, that as required by the BART Guidelines, ``[i]n order to
maintain and improve consistency, cost estimates should be based on the
OAQPS Control Cost Manual, [now renamed ``EPA Air Pollution Control
Cost Manual, Sixth Edition, EPA/452/B-02-001, January 2002] where
possible.'' 70 FR at 39166 (July 6, 2005). As explained more fully in
our Complete Response to Comments for NM Regional Haze/Visibility
Transport FIP document, we also agree with the USFS that owner's costs
are not an appropriate cost item to include in a BART cost estimate, as
owners costs are not included in the Cost Manual.
    Comment: PNM and its consultants estimated the cost of retrofitting
SJGS with SCRs to be between $194 million and $261 million per unit
(depending on the unit) with a total cost of $908 million for all four
units. EPA maintains that SCRs can be purchased and installed for much
less--between $52 million and $63 million per unit for a total of about
$229 million. EPA's estimates of annual operating costs for the SCRs
are also much lower than PNM's estimate. PNM's analysis indicates
annual operating costs for all four SCRs would be approximately $114
million per year, whereas EPA expects PNM to be capable of operating
the SCRs for only about $28 million per year. In short, EPA believes
that SCRs cost $679 million less, or one quarter of the amount
estimated by PNM. The commenter calls our cost estimate into question,
since the disparity between these two estimates is large.
    Response: B&V estimated it would cost between $446/kW and $559/kW
to retrofit SCR on the SJGS units. Five industry studies conducted
between 2002 and 2007 have reported the installed unit capital cost of
SCRs to be $79/kW to $316/kW, where the upper end of the range is for
very complex retrofits that are severely site constrained.\8\ Others
have noted the anomalously high costs reported for SJGS.9 10
We revised our cost estimates based on some comments highlighted in
comments, but even with those changes, our revised costs for SCR are
from $165/kW to $234/kW,\11\ still well within the accepted range of
expected costs for such controls.\12\
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    \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.
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    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

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 NOX Emissions from Fossil
Fuel-Fired Electric Power Plants, May 2009, EPA-R09-OAR-2009-0598-
0032 and Walter Nischt and others, Update of Selective Catalytic
Reduction Retrofit on a 675 MW Boiler at AES Somerset, ASME
International Joint Power Generation Conference, July 24-25, 2000,
available at: http://www.babcock.com/library/pdf/br-1703.pdf.
---------------------------------------------------------------------------

    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 NOX BART evaluation,
consider the controls previously installed by PNM as a result of its
March 10, 2005 consent decree with the Grand Canyon Trust, Sierra Club,
and NMED. These controls included the installation of low-
NOX burners with overfire air ports, a neural network
system, and a pulse jet fabric filter. However, when making the
NOX BART determination, we are obligated by the RHR to
examine additional retrofit technologies.\16\ In so doing, we have
determined that SCR is cost effective and results in significant
visibility improvements at a number of Class I areas, over and above
the existing pollution controls currently installed.
---------------------------------------------------------------------------

    \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
NOX, which is less restrictive than the WRAP modeling's
assumed NOX rates for those units (as characterized by EPA),
additional NOX emission controls are required. EPA, however,
proposes on this basis to determine that the BART emission limit for
units 1 through 4 at SJGS is not 0.27 (or 0.28) lb/MMBtu but is instead
0.05 lb/MMBtu based on the application of SCR technology. As a result,
EPA discontinues its evaluation of other technologies before fully
assessing their relative 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 NOX 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 NOX emission rate for the SJGS of between 0.23 to
0.39 lb/MMBtu, as opposed to our proposed FIP of 0.05 lb/MMBtu, which
requires costly SCR technology. One commenter stated the presumptive
limits should be required ``unless you [the BART-determining authority]
determine that an alternative control level is justified based on
consideration of the statutory factors.'' 70 FR at 39171. Except for
cyclone boilers (which are not present at SJGS), this commenter noted,
our presumptive NOX BART limits are not based on application
of SCR; as noted above, they are instead based on the use of combustion
controls. Further, EPA determined that when current combustion control
technology would be insufficient to meet the presumptive limits, it
would

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
NOX BART at the SJGS, in determining that a different level
of BART control was warranted.\20\ This analysis included an
examination of whether other technologies should be BART for the SJGS.
We also performed our BART evaluation on the basis of increasingly
stringent levels of control and assessed incremental costs and cost
effectiveness. Thus, we do not believe we improperly truncated the
NOX BART assessment for the SJGS.
---------------------------------------------------------------------------

    \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 NOX BART
for the SJGS should be SNCR and an emission rate of 0.23 lb/MMBtu on a
30-day rolling average. We will review the State RH SIP submittal, and
if there is significant new information that changes our analysis, we
will make appropriate revisions to today's decision. However, the State
RH SIP recommends SNCR as BART, and we have considered that technology
in the context of responding to other comments in this notice. For the
reasons discussed in our proposal (76 FR 491), and in other responses
to comments, we have concluded that BART for the SJGS is an emission
limit of 0.05 lbs/MMBtu, based on a 30 BOD average, more stringent than
the levels achievable by the SNCR technology recommended by the State.
    Comment: To meet a three-year deadline, PNM would have to
prefabricate as much of the SCRs as possible. In addition, a three-year
deadline would also require significant overtime hours, expedited
material costs, double ``heavy long-lift'' crane costs, and a larger
construction workforce overall. Because these costs would never be
incurred in the normal course of installing SCRs, PNM did not include
these costs in its analysis, but they would be unavoidable in the event
a three-year deadline is required. Such a short construction deadline
would also exacerbate the shortage of skilled labor caused by the
significant number of similar projects that are either ongoing or
planned for the near future in the region. The failure to account for
the additional labor costs associated with such a short timeframe,
particularly given other factors affecting the market for skilled
labor, renders both the three-year deadline and the cost estimate
prepared by EPA unrealistic.
    Response: The information in the record does not demonstrate a
shortage of labor necessary to complete the installation of SCRs at the
SJGS. However, as stated elsewhere in our response to comments, we have
modified the schedule for compliance with the emission limits to now
require compliance within 5 years--rather than 3 years--from the
effective date of our final rule. We believe this compliance schedule
will provide adequate time to schedule the necessary labor resources
for the installation of controls at the SJGS.
    Comment: The NPS recommends that in addition to the $/ton metric,
we evaluate the visibility metric $/deciview as an additional tool to
report the benefits of emissions controls. The NPS contends that BART
is not necessarily the most cost-effective solution. Instead, it
represents a broad consideration of technical, economic, energy, and
environmental (including visibility improvement) factors. The NPS notes
that one of the options suggested by the BART Guidelines to evaluate
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

$/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:
     Appropriateness of using the Cost Manual.
     Problems in B&V's scaling of cost items from another
project.
     Ductwork and ammonia grid costs.
     Reactor box and breaching.
     Expansion joints.
     Sonic horns.
     Elevator.
     Structural steel.
     SCR bypass.
     Catalyst.
     NOX monitoring.
     Auxiliary electrical system upgrades.
     Instrumentation and control systems.
     Air preheaters.
     Balanced draft conversion.
     Contingencies.
     Operating Labor.
     Reagent.
     Auxiliary power demand.
     Catalyst life.
     Interest rate.
     Effect on cost of PNM's assumption of an emission rate of
0.07 lbs/MMBtu.
    The NPS concluded their critique of PNM's cost estimate with their
own estimate of an average cost of $2,600/ton for the four units of the
SJGS.
    Response: We agree with the general contention that many individual
cost items for the installation of SCR on the units of the SJGS were
overestimated by PNM. Please see elsewhere in our response to comments
for our opinion regarding the appropriate estimated costs for these and
other cost items. We note that the NPS estimate of an average cost of
$2,600/ton for the four units of the SJGS closely agrees with our own
revised estimate.
    Comment: EPA failed to account for the costs associated with
ensuring sufficient auxiliary power to operate SCRs at SJGS. EPA
discounted by nearly 80 percent the estimated cost of the auxiliary
power upgrades needed to power the SCRs. The theory behind this sharply
discounted cost estimate is that the SCRs will only be responsible for
approximately 20 percent of the total draft pressure of the units and
that therefore the cost of the auxiliary power upgrades should be
allocated in similar fashion. Without SCRs, no additional auxiliary
power would be needed. As such, those costs must be included in the
cost of the SCRs, as they represent one of the site-specific concerns
that could make the installation of SCR at SJGS more difficult than
other units. The decision by EPA to exclude these costs underestimates
the cost of SCRs for SJGS by $73,175,000.
    Response: We disagree that installing SCRs would by itself trigger
the need to upgrade the auxiliary power system, especially to the
extent proposed by PNM. The upgrade benefits the entire auxiliary power
system. The modifications, for example, include new transformers,
switchgear, and motor control centers that will serve the entire fan
auxiliary loads of both the Consent Decree projects and the SCR.\22\
The modifications also include replacing the existing fans with
upgraded units. These fans will service more than just the SCRs.
---------------------------------------------------------------------------

    \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

differences in coal quality are either not material (sulfur, heat
content) or mitigate the potential impacts of ammonium bisulfate
plugging (higher ash at SJGS). The key factors that determine whether
ammonium bisulfate plugging will occur are not coal quality, but rather
the amount of sulfur trioxide (SO3) and ammonia in the
exhaust gases that reach the air preheater and the air preheater
temperature regime. The formation of ammonium bisulfate depends on the
relative amounts of ammonia and SO3 in the exhaust gases.
When the molar ratio is more than 2:1, ammonium sulfate (not ammonium
bisulfate) is preferentially formed. The average molar ratio for both
SJGS and Navajo over the catalyst lifetime is much higher than 2:1.
Thus, ammonium sulfate would be preferentially formed. Ammonium sulfate
is a dry powder at all air preheater operating temperatures and does
not create a fouling problem. Thus, consistent with Sargent & Lundy's
conclusion for the nearby Navajo Station, which burns a similar coal,
ammonium bisulfate fouling would not be expected and we do not believe
that upgrades are justified for the air preheaters due to SCR
installation.
    Comment: The installation of SCR at SJGS would increase the
resistance in the flue gas path for the units. To overcome that
additional resistance, PNM would need to install new higher capacity
fan rotors and motors because the SCRs will add an additional pressure
drop in the system of 10 inches of water gauge (w.g.). This change in
pressure and higher fan pressure ratings would increase the potential
risk of a boiler implosion during transient (upset or malfunction)
conditions. The analysis prepared by B&V of the expected cost of an SCR
retrofit includes the costs to mitigate the implosion risk by
converting to balanced draft and stiffening the boiler and associated
flue gas path. EPA concludes that additional boiler stiffening would
not be required, stating simply that ``a balance draft conversion with
the proposed stiffening is not part of an SCR project.''
    Response: The basis for selecting 10 in. w.g. for a 77%
NOX removal SCR is not explained or documented in the
record. The overall SCR system pressure drop consists of losses from
the SCR catalyst, static mixers, and duct work. Determining the
pressure drop due to the SCR requires a more advanced design than
presented in the B&V BART analysis. Instead, B&V appears to have
assumed that the pressure drop due to the SCR would be 10 in. w.g.,
which is at the upper end of the usual range of 3 to 10 in. w.g. The
B&V record, for example, contains no duct arrangement drawings; no
catalyst vendor quotes; does not identify the type of catalyst, e.g.,
honeycomb or plate; does not specify the catalyst pitch; and is silent
as to static mixers, all important factors in determining the pressure
drop due to the SCR. Thus, we do not believe there is a basis for the
10 in. w.g. used to cost boiler stiffening and to justify balanced
draft conversion. This pressure drop likely has not been optimized and
could be significantly reduced by catalyst selection (e.g., by using
honeycomb with large pitch) and ductwork design. Therefore, we do not
concur that the record supports a pressure drop of 10 in w.g. for the
SCR.
    Comment: Installation of SCR's at SJGS will increase boiler and
duct implosion potential due to increased draft system requirements and
fan pressure ratings. SCRs will trigger the need to choose between
either designing to the general standard of +/- 35 inches w.g. (which
is typical for a newly designed power plant) or performing a ``more
complete and rigorous analysis'' to determine whether PNM will qualify
for an exception from the 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 SO3
and requested a sorbent injection cost analysis from PNM. However, we

disagreed and concluded that sorbent injection was not required due to
the low sulfur content of the coal, availability of low conversion SCR
catalyst, and our calculations. We see no reason to change that view.
The reasons advanced in this comment for requiring sorbent injection to
control sulfuric acid mist (SAM) are not applicable to the SJGS SCR.
Visible plume issues have only been experienced at units that burn high
sulfur coal, containing greater than 2+% sulfur and typically over 3%
sulfur, e.g., Gavin, Ghent. The coal burned at SJGS contains 0.77%
sulfur, much lower than the amount of sulfur that has resulted in
visible plume issues elsewhere and is considered to be low sulfur. No
explanation is provided for why the commenter believes a plume may
``materialize'' on installing SCR. If the SCR is properly designed to
address SJGS's coal, a plume should not materialize. Low conversion
catalysts capable of achieving an SO2 conversion as low as
0.1% per layer of catalyst in the high dust, hot (>650 F) position and
0.5% across the entire SCR reactor are common in higher sulfur and
other applications. Even lower levels can be achieved if the catalyst
is regenerated.
    Comment: EPA's calculation of sulfuric acid emissions is incorrect.
EPA estimated sulfuric acid mist emission levels based on a document
prepared by the Electric Power Research Institute (EPRI), which
describes a formula used by many utilities to estimate sulfuric acid
emissions. However, in applying that formula, EPA assumed an ammonia
slip value of 2.0 parts per million (ppm), even though actual ammonia
slip varies over the life of a catalyst layer from very low values up
to 2.0 ppm as the catalyst ages. A more appropriate assumption for
ammonia slip is the 0.75 ppm value recommended by the EPRI formula,
which better represents the expected ammonia slip over the life of a
catalyst. Using that assumption, the sulfuric acid emissions from SJGS
are calculated to be twice that assumed by EPA. As a result, EPA's
attempt to justify its decision to delete the costs of sorbent
injection based on minimal sulfuric acid mist emissions is incorrect.
    Response: The commenter is correct in that the EPRI report does
suggest that a value of 0.75 ppm should be used. We note that the
ammonia slip of an SCR is minimal when the catalyst is new and
increases as the catalyst ages. In order to be conservative, we
recalculated the sulfuric acid emission rate, based on zero ammonia
slip, to be 2.6 X10-4 lb/MMBtu, compared to our original
value of 1.06 X10-4 lb/MMBtu at 2ppm ammonia slip. The 2.0
ppm we selected in our proposed visibility modeling was based on the
maximum slip from PNM's design specifications. This revised sulfuric
acid emission rate remains significantly lower than that estimated by
NMED and is a minimal level of sulfuric acid emissions. We continue to
conclude that sorbent injection is not required due to the low sulfur
content of the coal, availability of low conversion SCR catalysts,
removal by existing control equipment and our revised calculations.
    Comment: The EPA also cites to the results of a stack test
performed at the Navajo Generating Station in November 2009 to conclude
that actual sulfuric acid mist emissions are lower than would be
estimated using the EPRI Method. However, the air quality control
industry generally considers sulfuric acid testing to be very prone to
inaccuracy because the test methods used are susceptible to bias. Also,
sulfuric acid emissions vary significantly from unit to unit because
emissions removal is dependent on many variables including temperature,
moisture, process operation, air quality control equipment, ambient
conditions, and the quality of the testing. As mentioned above, SJGS
and the Navajo Generating Station differ significantly in many of these
respects. Therefore, it is not appropriate to use test results from
Navajo Generating Station to make assumptions about SJGS.
    Response: We believe this comment mischaracterizes our analysis. We
did not use test results from the Navajo Generating Station to make
assumptions about the SJGS. Rather, we compared sulfuric acid mist
emissions calculated for Navajo using the EPRI procedure with a stack
test at Navajo in accordance with EPA Method 8A procedures. Thus, we
compared Navajo EPRI estimates with Navajo test data to judge the
accuracy of the EPRI procedure. This comparison suggests that the EPRI
method may overestimate sulfuric acid mist emissions when firing a
similar coal if PNM's assumptions are used. This analysis supports the
conclusion that the EPRI method and parameters we used provide a better
estimation of sulfuric acid emissions than the methodology and
parameters utilized by PNM and NMED in their analysis, which
overestimates these emissions. We also note that PNM estimates for
sulfuric acid emissions that were reported to the Toxic Release
Inventory in recent years are much lower than those estimated by PNM
for their BART analysis.
    Comment: It is appropriate to include sorbent injection costs in
the SCR cost analysis because sorbent injection may be required by law.
The Prevention of Significant Deterioration (PSD) program under the CAA
requires major sources to install additional controls to address any
significant net emissions increases resulting from a physical change to
an emissions unit. Because the SCR will constitute a physical change to
the SJGS emission units, and could have the potential to result in a
significant net emissions increase in sulfuric acid mist, additional
controls could be required by the PSD program. If triggered, the PSD
program would require the installation of ``best available control
technology,'' which for sulfuric acid mist emission increases would
likely include a sorbent injection system. Although there remains some
uncertainty as to whether the SCR would trigger PSD permitting
requirements, PNM believes it is appropriate to include the cost of the
system in the SCR cost analysis, and the failure to include those costs
underestimates the cost of the SCRs by $12,118,000.
    Response: For the reasons outlined elsewhere in our response to
comments, we believe the level of sulfuric acid generated at the SJGS
will be so low that sorbent injection will not be needed. However, it
is possible that the installation of SCR on all four units of the SJGS
could generate enough additional sulfuric acid that a PSD review could
be triggered. EPA is not the permitting authority for sources in New
Mexico but we believe it is reasonable to anticipate that a subsequent
BACT analysis for sulfuric acid emissions at the SJGS will determine
that no additional controls are required because despite the projected
increase in sulfuric acid emissions, emissions are expected to remain
low. In considering SCR for controlling NOx, EPA specifically
considered the issues of sulfuric acid formation. In our review, we
believe that the emission limits for NOx can be achieved through the
use of lower reactivity catalyst, thus mitigating the formation of
sulfuric acid across the catalyst bed. We have set an emission limit
for emissions of sulfuric acid that restricts the increase of sulfuric
acid. According to the two most recent Toxic Release Inventory (TRI)
reports submitted by SJGS, the total sulfuric acid emissions are very
low (17.77 TPY for 2009, and 27.5 TPY for 2008). Based on our
calculations, we believe the current emissions of sulfuric acid to be
significantly lower than these reported values due to the low sulfur
content of the coal and the removal of sulfuric acid in the installed
control equipment, including wet scrubbers and fabric filters. We
project, with the

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 2.6x10-4 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 NOX 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,

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

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 NOX BART proposal for the SJGS would cost New Mexico or
Albuquerque ratepayers $10.20 more a year, or 85 cents a month, which
is the price of a candy bar, so cleaning up this decades old air
pollution is affordable and now is the time to do it.
    Response: As discussed in our proposal, we disagree with PNM's cost
estimate for installing SCR on the four units of the SJGS. Although PNM
estimated the total cost to be in excess of $1 Billion, we estimated
that cost to be approximately $250 Million. As discussed elsewhere in
this notice, taking into consideration various comments, we have
refined our estimate to be $344,542,604. In light of the visibility
benefits we predict will occur, we consider this to be cost effective.
We take our duty to estimate the cost of controls very seriously, and
make every attempt to make a thoughtful and well informed
determination. However, we do not consider a potential increase in
electricity rates to be the most appropriate type of analysis for
considering the costs of compliance in a BART determination.
Nevertheless, we note that our cost estimate, being about \1/3\ that of
PNM's will result in significantly less costs being passed on to rate
payers.
4. Comments That Opined on Our Reliance on the EPA Air Pollution
Control Cost Manual
    Comment: The rejection of PNM's escalation factors is unrealistic.
By relying too heavily on the Cost Manual, EPA's analysis not only
omits the specific line items, it also omits or alters various
estimating factors utilized by B&V in PNM's analysis. EPA relied on the
Chemical Engineering Plant Cost Index (CEPCI) to escalate costs from
the Cost Manual. However, although that index may be a reasonable tool
for a chemical plant, it does not properly account for escalation of
costs at power plants. In contrast, B&V developed an appropriate
escalation factor with the help of an outside consulting firm
specializing in financial analysis and forecasting, which incorporates
the complete B&V database of ``as-built'' costs, the Bureau of Labor
Statistics indices, and the consulting firm's database of costs and
indices, all tailored specifically to the power generation industry.
    Response: The CECPI, which is published monthly by the magazine,
Chemical Engineering, has been used for decades in regulatory cost
effectiveness analyses and is one of the factors that allows a
comparison to be made between cost effectiveness analyses at different
facilities. This method was selected by EPA's Office of Air Quality
Planning and Standards for use in regulatory cost effectiveness
analyses because ``this index specifically covers cost items that are
pertinent to pollution control equipment (materials, construction
labor, structural support, engineering & supervision, etc.).'' \31\ The

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,38 39 compared to cost estimates of $423/kW to
$567/kW for SJGS. B&V's estimates of capital cost to retrofit SCR at
SJGS ($446/kW-$599/kW) are higher than actual installed cost for Gibson
and many other existing retrofit SCRs, including those with extreme
retrofit difficulty. The record including the information we have about
the site does not document any unusual circumstances that would justify
the unusually high costs claimed by B&V for SJGS. Thus, we do not
believe that unusual circumstances are warranted.
---------------------------------------------------------------------------

    \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, NOX Market Update, August 2004. SCR
was retrofit on Gibson Units 2-4 in 2002 and 2003 at $179/kW.
Assuming 2002 dollars, this escalates to ($179/kW)(550.7/395.6) =
$249/kW. http://www.mcilvainecompany.com/sampleupdates/NoxMarketUpdateSample.htm.
    \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 NOX controls at
all. According to the introduction to the Manual, EPA was at that time
``entering new and uncharted territory for part of the Manual'' because
``previous editions did not discuss NOX or SO2
controls, and [the 2002] edition starts the process of correcting that
oversight.'' Finally, EPA also admits in the Manual that it had
difficulty obtaining information on control costs because most of the
information is proprietary--the very type of information to which B&V
has ready access.
    Response: As discussed elsewhere in our response to comments, the
Cost Manual contains two types of information, general cost analysis
methodology and control-specific costing information. This comment
addresses the latter. The information on SCR in Chapter 2 of the Cost
Manual contains general information on SCR, design procedures, and some
cost information. We agree that the cost information does not reflect
current market costs. Thus, cost data should be escalated to current
dollars using the CECPI before it is used or replaced with site-
specific vendor quotes. We did not use any SCR costs data from this
chapter in our analysis.
    Comment: The EPA cost estimate only differs from the Cost Manual
where doing so would serve to reduce the amount of the cost estimate.
For example, EPA applied an SCR life span of 30 years instead of the 20
year life span provided in the Cost Manual. The justification for
choosing a different life span than provided for in the Manual is that
other facilities have requested 30 year life spans in requests for
proposal and some unidentified SCRs in Europe have lasted that long. If
such general, anecdotal information were sufficient to convince EPA to
stray from the Cost Manual, the EPA analysis should be replete with
variations from the outdated Cost Manual. The use of a 30-year lifespan
underestimates the cost estimate of SCR by $15,268,000.
    Response: We disagree with this comment and we used the Cost Manual
appropriately, as directed by the RHR. We used it for cost factors that
for reasons expressed elsewhere in our response to comments, we feel
were miscalculated by B&V, but were not otherwise available in the
public domain. We did not use any actual cost data from the Cost
Manual. In the case of SCR lifetime, the Cost Manual does not recommend
a lifetime for an SCR, but rather sets out a calculation example that
uses a lifetime of 20 years. In fact, this same calculation makes many
other

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 NOX BART emission limit of 0.05 lbs/MMBtu for the
SJGS. We have summarized our responses to these comments, but refer the
reader to our Complete Response to Comments for NM Regional Haze/
Visibility Transport FIP document for more detail.
    Comment: PNM stated the BART limit should not be based on daily
averages of thirty (30) calendar days, as we proposed, because it
believes it would be inconsistent with the BART Guidelines. If calendar
days are used, they argue, the average could include as little as one
hour of operation if the unit is offline for an outage that lasts
longer than thirty days because the first hour of operation would be
the only data recorded in the last thirty calendar days. Instead, PNM
requested that we consider changing ``calendar days'' to boiler
operating days (BODs) which are days in which the unit ran for at least
one hour. That approach would be consistent with the BART Guidelines,
which include the following advice to states:

    For EGUS, specify an averaging time of a 30-day rolling average,
and contain a definition of ``boiler operating day'' that is
consistent with the definition in the proposed revisions to the NSPS
for utility boilers in 40 CFR part 60, subpart Da.\43\
---------------------------------------------------------------------------

    \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
NOX emission limit should be based on BODs, rather than a
straight calendar average. In response to this comment, we have
reanalyzed our proposed determination that the units of the SJGS can
achieve a NOX emission limit of 0.05 lbs/MMBtu on a
continuous basis, using the BOD concept. We have done this because we
believe the same metric should be used to both determine BART and to
determine compliance with BART. The results of that analysis are
presented in response to another comment. In summary, we continue to
believe that NOX BART for the units of the SJGS is an
emission limit of 0.05 lbs/MMBtu. We have concluded that emission limit
should be based on a 30-day BOD rolling average based on any operation
in a given day counting toward the average. We believe that averaging
scheme complies with the BART Guidelines, which defines a BOD to be
``any 24-hour period between 12:00 midnight and the following midnight
during which any fuel is combusted at any time at the steam generating
unit.'' \44\
---------------------------------------------------------------------------

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

    Comment: The U.S. Forest Service (USFS) expressed its support of
our NOX BART emission limit of 0.05 lb/MMBtu. The USFS
believe this emission limit is adequate and will improve visibility at
Class I areas throughout the Four Corners region. Additionally, the
USFS feels SCR has already been determined to be BART at several other
coal-fired power plants across the United States.
    Response: We agree with the USFS.
    Comment: EPA predetermined the cost-effectiveness of SCR at SJGS
``assuming an outlet NOX of 0.05 lb/MMBtu.'' EPA then
proposed that assumed rate as the BART emission limit for SJGS. EPA's
assumption is unfounded--the installation of SCRs at SJGS will not
enable the units to achieve 0.05 lb/MMBtu on a continuous basis. As
such, the proposed 0.05 lb/MMBtu limit cannot be BART for SJGS.
    Response: We disagree with this comment. We initially estimated the
cost effectiveness of SCR, assuming an outlet NOX of 0.07
lb/MMBtu, to provide a direct comparison with B&V's analysis. Following
this, we determined that a BART emission limit of 0.05 lb/MMBtu was
appropriate and then refined the cost effectiveness on that basis. The
BART level of 0.05 lb/MMBtu was selected based on an examination of
continuous emission monitoring

systems (CEMS) data for existing units operating with retrofit SCRs, as
we explain elsewhere in our response to comments.
    Comment: In contrast to EPA's NOX emission limit
assumption of 0.05 lbs/MMBtu, B&V, who has extensive practical
experience in actually designing and installing retrofit SCRs
determined that a retrofit SCR would only be capable of achieving 0.07
lb/MMBtu on a continuous basis, particularly if required to use the
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 NOX design basis was 0.05 lbs/MMBtu for the
SCR retrofit for the nearby Navajo Generating Station, a facility of a
similar age that burns a similar coal, with a more constrained site. As
explained elsewhere in our response to comments, we present data that
demonstrates that retrofit SCR installations are capable of achieving a
NOX limit of 0.05 lbs/MMBtu on a continuous basis.
Therefore, we believe the statement that a retrofit SCR would only be
capable of achieving 0.07 lb/MMBtu on a continuous basis, is factually
incorrect.
    Comment: Several commenters stated that our claim that many
facilities are using SCR to actually achieve lower emission rates than
0.07 lb/MMBtu (including the Havana Unit 9, Amos Units 1 and 2,
Chesterfield Unit 6, Cardinal Units 2 and 3, Colbert Unit 5, Ghent
Units 3 and 4, and Mill Creek Unit 3) is incorrect. This commenter
states that while these units have shown the ability to reach 0.05 lb/
MMBtu or lower at times, those units are unable to do so on a
continuous basis. Thus, the commenter claims, if the units cited by us
were in fact subject to a 0.05 lb/MMBtu emission limit, those limits
would have been violated many times at each unit.
    Response: We disagree with this comment and continue to believe
that the NOX emission limit we proposed for the four units
of the SJGS, 0.05 lbs/MMBtu, is achievable on a continuous basis. In
reaching this conclusion, we followed the language in the BART
Guidelines:

    It is important, however, that in analyzing the technology you
take into account the most stringent emission control level that the
technology is capable of achieving. You should consider recent
regulatory decisions and performance data (e.g., manufacturer's
data, engineering estimates and the experience of other sources)
when identifying an emissions performance level or levels to
evaluate.
    In assessing the capability of the control alternative, latitude
exists to consider special circumstances pertinent to the specific
source under review, or regarding the prior application of the
control alternative. However, you should explain the basis for
choosing the alternate level (or range) of control in the BART
analysis. Without a showing of differences between the source and
other sources that have achieved more stringent emissions limits,
you should conclude that the level being achieved by those other
sources is representative of the achievable level for the source
being analyzed.\46\
---------------------------------------------------------------------------

    \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 NOX emission
limit of 0.05 lbs/MMBtu. Second, we examined the record to determine if
there existed ``special circumstances pertinent to the specific source
under review'' that would prevent the units of the SJGS from achieving
this limit, and found none. Third, concluding there was no ``showing of
differences between the source and other sources that have achieved
more stringent emissions limits'' that would preclude the application
of this limit, we ``conclude[d] that the level being achieved by those
other sources is representative of the achievable level for the source
being analyzed.'' The following discussion expands on these points.
    In our Complete Response to Comments for NM Regional Haze/
Visibility Transport FIP document, we provide a detailed discussion of
why we believe the commenter, PNM, misquotes our cost evaluation
report, which was incorporated into our proposal's TSD. In summary,
that report contained a previous study of SCR performance during the
ozone season for the period 2003-2006. This study showed that several
units were achieving a NOX emission limit of 0.05 lb/MMBtu
at that time to meet NOX SIP Call regulations that were then
in force. These SCRs only operated from May to October of each year,
the ozone season. The SCRs were bypassed during the remainder of the
year as they were not required to meet the NOX SIP Call.
    PNM presents graphs for each of the ozone season 2003-2006 units
for the period January 2008 to November 2010. These graphs suggest that
0.05 lb/MMBtu is exceeded on numerous occasions and imply this was due
to a limitation of the equipment to maintain control. However, these
graphs appear to be based on calendar operating days. This distinction
is significant, as the BOD convention discussed by the BART Guidelines
\47\ smoothes out the 30-day rolling average outage spikes. Also, these
charts include large blocks of time during which the SCRs were turned
off because they were not required under the trading programs then in
force. Lastly, these charts connect the dots across outage periods,
when the SCRs are not in use and improperly include the zero hour days
in the averages at elevated levels.
---------------------------------------------------------------------------

    \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 NOX CEMS data for the
period 2009-2010 to identify the best performing retrofit units that
operate year-round. We ranked the annual average NOX
emissions for all units in the database for the years 2009 and 2010
from the lowest to the highest NOX emissions. We then
selected those facilities that had at least one unit in the top 30
group in both years to identify retrofits achieving best performance.
    We then developed a spreadsheet program that used the CAMD data and
calculated and graphed three types of 30-day rolling averages for most
of these best performing units, plus those additional units graphed by
PNM for the period 2008-2010 for the Ozone Transport Assessment Group
(OTAG) units and 2006-2010 for the Texas units (Parish 7, 8). All of
the units we analyzed were retrofitted with SCR.

    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