[Federal Register Volume 76, Number 162 (Monday, August 22, 2011)]
[Rules and Regulations]
[Pages 52388-52440]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2011-20682]
[[Page 52387]]
Vol. 76
Monday,
No. 162
August 22, 2011
Part II
Environmental Protection Agency
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40 CFR Part 52
Approval and Promulgation of Implementation Plans; New Mexico; Federal
Implementation Plan for Interstate Transport of Pollution Affecting
Visibility and Best Available Retrofit Technology Determination; Final
Rule
Federal Register / Vol. 76 , No. 162 / Monday, August 22, 2011 /
Rules and Regulations
[[Page 52388]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 52
EPA-R06-OAR-2010-0846; FRL-9451-1
Approval and Promulgation of Implementation Plans; New Mexico;
Federal Implementation Plan for Interstate Transport of Pollution
Affecting Visibility and Best Available Retrofit Technology
Determination
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: EPA is disapproving a portion of the State Implementation Plan
(SIP) revision received from the State of New Mexico on September 17,
2007, for the purpose of addressing the ``good neighbor'' requirements
of section 110(a)(2)(D)(i) of the Clean Air Act (CAA or Act) for the
1997 8-hour ozone National Ambient Air Quality Standards (NAAQS or
standards) and the 1997 fine particulate matter (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 protected].
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
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extended the time for compliance with the nitrogen oxide pollution
emission limit from 3 years to 5 years, the maximum period allowed by
the Clean Air Act.
This investment will reduce the visibility impacts due to this
facility by over 50% at each one of the 16 national parks and
wilderness areas in the area, and promote local tourism by decreasing
the number of days when pollution impairs scenic views. Although
today's action is taken to address visibility impairments, PNM will
also reduce public health impacts by cutting NOX pollution
by over 80% by installing reliable pollution-control technology on its
four coal-fired power generation units over the next five years.
EPA will review the regional haze plan that the State submitted in
July 2011, and if there is significant new information that changes our
analysis, EPA will make appropriate revisions to today's decision.
Detailed Outline
I. Summary of Our Proposal
II. Final Decision
A. Interstate Transport
B. NOX BART Determination for the San Juan Generating
Station (SJGS)
C. Compliance Timeframe
III. Analysis of Major Issues Raised by Commenters
A. Comments on the Costs of the NOX BART
Determination
B. Comments on our Proposed NOX BART Emission Limits
C. Comments on our Proposed SO2 Emission Limit
D. Comments on our Proposed H2SO4 and
Ammonia Emission Limits and Other Pollutants
E. Comments on the Emission Limit Compliance Schedule
F. Comments on the Conversion of the SJGS to a Coal-to-Liquids
Plant With Carbon Capture as a Means of Satisfying BART
G. Comments on Health and Ecosystem Benefits, and Other
Pollutants
H. Miscellaneous Comments
I. Comments in Favor of Our Proposal
J. Comments Arguing Our Proposal Would Hurt the Economy and/or
Raise Electricity Rates
K. Comments Arguing Our Proposal Would Help the Economy
L. Comments Requesting an Extension to the Public Comment Period
M. Comments Requesting We Defer Action in Favor of a New Mexico
SIP Submittal
N. Comments Generally Against Our Proposal
O. Comments on Legal Issues
P. Modeling Comments
IV. Statutory and Executive Order Reviews
I. Summary of Our Proposal
On January 5, 2011, we published the proposal on which we are now
taking final action. 76 FR 491. We proposed to disapprove a portion of
the SIP revision received from the State of New Mexico on September 17,
2007, for the purpose of addressing the ``good neighbor'' provisions of
the CAA section 110(a)(2)(D)(i) with respect to visibility for the 1997
8-hour ozone NAAQS and the PM2.5 NAAQS. Having proposed to
disapprove these provisions of the New Mexico SIP, we proposed a FIP to
address the requirements of section 110(a)(2)(D)(i)(II) with respect to
visibility to ensure that emissions from sources in New Mexico do not
interfere with the visibility programs of other states. We proposed to
find that New Mexico's sources, other than the San Juan Generating
Station (SJGS), are sufficiently controlled to eliminate interference
with the visibility programs of other states, and for the SJGS, we
proposed specific SO2 and NOX emissions limits
that will eliminate such interstate interference. For SO2,
we proposed to require the SJGS to meet an emission limit of 0.15
pounds per million British Thermal Units (lb/MMBtu). For
NOX, we proposed to implement a NOX emission
limit of 0.05 lbs/MMBtu, based on our BART determination, as discussed
below.
Separate from our proposal under Section 110 of the CAA, we
simultaneously evaluated whether the SJGS met certain other related
requirements under the Regional Haze (RH) program under Sections 169A
and 169B of the CAA. Regional Haze SIPs were due December 17, 2007. In
January 2009, we made a finding that New Mexico had failed to submit a
RH SIP addressing the requirements of 40 CFR 51.309(d)(4) and (g). 74
FR 2392 (January 15, 2009). Under the CAA, we are required to
promulgate a FIP within two years of the effective date of a finding
that a State has failed to submit a SIP unless the State submits a SIP
and we approve that SIP within the two year period. CAA 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
[[Page 52390]]
most impaired days and ensures no degradation of the best days. (The
``Class I'' federal areas \1\ affected by the SJGS include 16 of our
most treasured parks, such as the Grand Canyon, Mesa Verde, and
Bandelier National Monument. Emissions from this power plant impact
four states including Arizona, Utah, Colorado, and New Mexico.)
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\1\ CAA 42 U.S.C. 7472(a). The list of mandatory class I federal
areas where visibility is an important value is codified at 40 CFR
part 81 subpart D.
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Because of the often significant impacts on visibility from the
interstate transport of pollutants, we interpret the ``good neighbor''
provisions of section 110 of the CAA described above as requiring
states to include in their SIPs measures to prohibit emissions that
would interfere with the reasonable progress goals set to protect Class
I areas in other states. This is consistent with the requirements in
the RH program which explicitly require each State to address its share
of the emission reductions needed to meet the reasonable progress goals
for surrounding Class I areas. 64 FR 35714, 35735 (July 1, 1999).
States working together through a regional planning process are
required to address an agreed upon share of their contribution to
visibility impairment in the Class I areas of their neighbors. 40 CFR
51.308(d)(3)(ii).
The States in the West, including New Mexico, worked through a
regional planning organization, the Western Regional Air Partnership
(WRAP), to develop strategies to address regional haze. To help the
State in establishing reasonable progress goals, the WRAP modeled
future visibility conditions. The WRAP modeling assumed emissions
reductions from each State, based on extensive consultation among the
States as to appropriate strategies for addressing haze. In setting
reasonable progress goals, States in the West generally relied on this
modeling. As explained in the notice of proposed rulemaking, we believe
that the analysis conducted by the WRAP provides an appropriate means
for designing a FIP that will ensure that emissions from sources in New
Mexico are not interfering with the visibility programs of other
states, as contemplated in section 110(a)(2)(D)(i)(II).
As a result of our disapproval of New Mexico's SIP, submitted to
meet the requirements of section 110(a)(2)(D)(i)(II) with respect to
visibility, we are promulgating a FIP to ensure that emissions from New
Mexico sources do not interfere with the visibility programs of other
states. We find that New Mexico sources, other than the SJGS, are
sufficiently controlled to eliminate interference with the visibility
programs of other states because the federally enforceable emission
limits for these sources are consistent with those relied upon in the
WRAP modeling. The 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
[[Page 52391]]
can be addressed prior to the installation of the emission controls
required to satisfy our FIP.
We are also finalizing our proposal requiring the SJGS to meet an
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
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[[Page 52392]]
We note, that as required by the BART Guidelines, ``[i]n order to
maintain and improve consistency, cost estimates should be based on the
OAQPS Control Cost Manual, [now renamed ``EPA Air Pollution Control
Cost Manual, Sixth Edition, EPA/452/B-02-001, January 2002] where
possible.'' 70 FR at 39166 (July 6, 2005). As explained more fully in
our Complete Response to Comments for NM Regional Haze/Visibility
Transport FIP document, we also agree with the USFS that owner's costs
are not an appropriate cost item to include in a BART cost estimate, as
owners costs are not included in the Cost Manual.
Comment: PNM and its consultants estimated the cost of retrofitting
SJGS with SCRs to be between $194 million and $261 million per unit
(depending on the unit) with a total cost of $908 million for all four
units. EPA maintains that SCRs can be purchased and installed for much
less--between $52 million and $63 million per unit for a total of about
$229 million. EPA's estimates of annual operating costs for the SCRs
are also much lower than PNM's estimate. PNM's analysis indicates
annual operating costs for all four SCRs would be approximately $114
million per year, whereas EPA expects PNM to be capable of operating
the SCRs for only about $28 million per year. In short, EPA believes
that SCRs cost $679 million less, or one quarter of the amount
estimated by PNM. The commenter calls our cost estimate into question,
since the disparity between these two estimates is large.
Response: B&V estimated it would cost between $446/kW and $559/kW
to retrofit SCR on the SJGS units. Five industry studies conducted
between 2002 and 2007 have reported the installed unit capital cost of
SCRs to be $79/kW to $316/kW, where the upper end of the range is for
very complex retrofits that are severely site constrained.\8\ Others
have noted the anomalously high costs reported for SJGS.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
[[Page 52393]]
United States. Accordingly, constructability issues are well
understood. Standard design and construction management methods have
been developed from these 300+ existing installations.\14\ This
experience would inform the design and construction of the SJGS SCR,
resulting in significant economies compared to the estimates presented
by B&V based on a very rough preliminary design that has not been
optimized for constructability. The record does not identify any
unusual site-specific conditions that would result in direct
installation costs for SJGS that are substantially higher than upper
bound direct installation costs reported by other SCR design firms for
similarly complex sites. In fact, B&V has provided no support in the
record for its assumptions. Finally, the design costs are not a direct
installation cost, but rather indirect costs discussed elsewhere in our
response to comments.
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\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.
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\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\
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\17\ 76 FR at 499.
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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
[[Page 52394]]
be appropriate to ``consider whether advanced combustion control
technologies such as rotating opposed fire air should be used to meet
these [presumptive] limits.'' Id. at 39172. Another commenter asserted
that a proper BART assessment would take the presumptive limits into
account by beginning with the assumption that the established
presumptive limit for these units is appropriate, and then would
proceed with an analysis of whether the least stringent control options
could achieve that limit. A five-factor BART analysis of increasingly
stringent control options could then properly assess incremental costs
(and cost-effectiveness) and any benefits of requiring more stringent
controls.
Response: We note the RHR states:
For each source subject to BART, 40 CFR 51.308(e)(1)(ii)(A)
requires that States identify the level of control representing BART
after considering the factors set out in CAA section 169A(g), as
follows:
States must identify the best system of continuous emission
control technology for each source subject to BART taking into
account the technology available, the costs of compliance, the
energy and non-air quality environmental impacts of compliance, any
pollution control equipment in use at the source, the remaining
useful life of the source, and the degree of visibility improvement
that may be expected from available control technology.\18\
---------------------------------------------------------------------------
\18\ 70 FR at 39158.
---------------------------------------------------------------------------
The RHR also states:
States, as a general matter, must require owners and operators
of greater than 750 MW power plants to meet these BART emission
limits. We are establishing these requirements based on the
consideration of certain factors discussed below. Although we
believe that these requirements are extremely likely to be
appropriate for all greater than 750 MW power plants subject to
BART, a State may establish different requirements if the State can
demonstrate that an alternative determination is justified based on
a consideration of the five statutory factors.\19\
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\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
[[Page 52395]]
$/ton.\21\ The commenters are correct in that the BART Guidelines list
the $/deciview ratio as an additional cost effectiveness measure that
can be employed along with $/ton for use in a BART evaluation. However,
the use of this metric further implies that additional thresholds of
acceptability, separate from the $/ton metric, be developed for BART
determinations for both single and multiple Class I analyses. We have
not used this metric because (1) We believe it is unnecessary in
judging the cost effectiveness of BART, (2) it complicates the BART
analysis, and (3) it is difficult to judge. We conclude it is
sufficient to analyze the cost effectiveness of potential BART controls
using $/ton, in conjunction with the modeled visibility benefit of the
BART control. We have addressed the commenter's statement that we
should not aggregate visibility improvement over Class I areas
elsewhere in our response to comments.
---------------------------------------------------------------------------
\21\ 70 FR 39167.
---------------------------------------------------------------------------
2. Comments on Specific Cost Line Items
The comments that follow have been summarized to capture each one's
main points and most of the references have been removed. The reader is
encouraged to refer to our Complete Response to Comments for NM
Regional Haze/Visibility Transport FIP for more details and references.
Comment: The NPS stated that PNM has improperly rejected use of the
Cost Manual in favor of methods not allowed by EPA. The NPS states the
SCR cost estimates submitted by PNM are severely lacking in the types
of specific information needed to give them credibility. The NPS goes
on to provide a great deal of detailed information that supports their
opinion that specific cost items were overestimated. This information
includes the following cost item categories:
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.
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\22\ B&V 10/22/10 Cost Analysis, Sec. 3.0 and 11/4/10 Norem E-
mail to Kordzi, Re: Questions on PNM's Revised Cost Estimate for the
SJGS SCR Project, Response to Question 3, Table 3 of attachment 1.
---------------------------------------------------------------------------
This comment advocates attributing 100% of the cost of the
auxiliary power system upgrade, recognized after the fact, to the last
project to be implemented, the SCR. We did not ``discount'' the cost of
the auxiliary power system by 80%, but rather distributed it among the
control projects planned around the same time that triggered its need
according to each control's contribution to draft pressure lost. This
recognizes that the upgrade provides benefits to the entire system and
includes elements that are more than strictly necessary because of the
installation of the SCR. Therefore, it is not appropriate to attribute
the entire cost of the upgrade to the SCR project. We believe our
approach is consistent with standard engineering practices.
Comment: EPA failed to account for additional costs associated with
protecting the air preheater following an SCR Installation. Ammonia
reacts with sulfur in the flue gas downstream of the SCR forming
ammonium bisulfate (ABS), which condenses in the air preheater. ABS is
an acidic substance that forms a sticky deposit on heat transfer
surfaces, resulting in both corrosion of the equipment and the
collection of fly ash that plug passages, which ultimately impairs the
efficiency and reliability of the unit. As such, the installation of a
retrofit SCR generally requires a modification to the air preheater to
allow for easier cleaning of the basket surfaces in order to protect
the heat transfer elements against the potential damage that might
otherwise result from ABS. EPA deleted the costs of protecting the air
preheater in its SCR cost analysis, ``pending compelling justification
that they are required for the SCR.'' EPA's cost analysis recognizes
that modifications to the air preheater are generally required for
``units that burn high sulfur coal,'' but EPA assumes that such
modifications are not necessary ``for a properly designed SCR on a
boiler that burns low sulfur coal.'' EPA is correct that, in spite of
the quoted discussion above, Sargent & Lundy did not recommend air
preheater modifications in the SCR cost analysis for the Navajo
Generating Station. However, that recommendation was based on the
specific emission characteristics at Navajo Generating Station, which
differ significantly from those at SJGS.
Response: This comment attempts to distinguish the emission
characteristics of Navajo Generating Station and the SJGS by pointing
to differences in the coal quality to support air preheater
modifications at SJGS but not at Navajo. We obtained and analyzed the
Navajo design basis coal quality. The
[[Page 52396]]
differences in coal quality are either not material (sulfur, heat
content) or mitigate the potential impacts of ammonium bisulfate
plugging (higher ash at SJGS). The key factors that determine whether
ammonium bisulfate plugging will occur are not coal quality, but rather
the amount of sulfur trioxide (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
[[Page 52397]]
disagreed and concluded that sorbent injection was not required due to
the low sulfur content of the coal, availability of low conversion SCR
catalyst, and our calculations. We see no reason to change that view.
The reasons advanced in this comment for requiring sorbent injection to
control sulfuric acid mist (SAM) are not applicable to the SJGS SCR.
Visible plume issues have only been experienced at units that burn high
sulfur coal, containing greater than 2+% sulfur and typically over 3%
sulfur, e.g., Gavin, Ghent. The coal burned at SJGS contains 0.77%
sulfur, much lower than the amount of sulfur that has resulted in
visible plume issues elsewhere and is considered to be low sulfur. No
explanation is provided for why the commenter believes a plume may
``materialize'' on installing SCR. If the SCR is properly designed to
address SJGS's coal, a plume should not materialize. Low conversion
catalysts capable of achieving an 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
[[Page 52398]]
implementation of SCR using a low reactivity catalyst that total
emissions of sulfuric acid will remain below 22 tons/year.\23\ In this
particular case, sorbent injection technology is unlikely to be cost-
effective on a cost per ton basis of sulfuric acid mist removed. Again,
we note that the New Mexico Environmental Department is the permitting
authority and has the primary responsibility to implement the New
Source Review program which includes the PSD permitting process, and
the issuance of the applicable permit. NMED will be responsible for
determining if PSD will be triggered for increases in sulfuric acid
emissions or other NAAQS pollutants and in determining the BACT for
such increases.
---------------------------------------------------------------------------
\23\ Based on our emission limit of 2.6x10-4 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,
[[Page 52399]]
which is at the upper end of the usual range of 3 to 10 in. w. g.
Fifth, the unit cost of electricity used by B&V, $0.06095/kWh, is much
higher than the auxiliary power cost commonly used in cost
effectiveness analyses, and thus was not justified. Auxiliary power is
the power required to run the plant, or power not sold. Cost
effectiveness analyses are based on the cost to the owner to generate
electricity, or the busbar cost, not market retail rates. The B&V
estimate is based on the average forecasted cost of replacement power
for 2007 to 2012.\27\ Thus, even if this is the correct site specific
cost, it is the wrong metric for a cost effectiveness analysis. We
further note that the use of forecast cost is inconsistent with the
BART methodology, which is based on current dollars. We conservatively
used the upper end of the range of costs assumed in BART cost
effectiveness analyses ($0.03/kWh to $0.05/kWh) \28\ or $0.050/kWh.
After our analysis was complete, PNM responded to a question from us
that its average cost of production is $0.047/kWh ($47.83/MWh). This
rounds up to 0.05/kWh, the number we used. Thus, we have made no
changes to our estimate of auxiliary power demand.
---------------------------------------------------------------------------
\26\ 10/22/10 B&V Cost Analysis Update, Appendix B; 6/7/07 B&V
San Juan BART Analysis, p. B-3.
\27\ E-mail from Norem to Kordzi, October 21, 2010, Re: PNM
Responses to Follow-Up Questions from October 14, 2010 Conference
Call Regarding BART Cost Estimate, October 21, 2010 (10/21/10
Responses), Response to Question 9, pp. 3-4.
\28\ Sargent & Lundy, Sooner Units 1 & 2, Muskogee Units 4 & 5
Dry Flue Gas Desulfurization (FGD) BART Analysis Follow-Up Report,
Prepared for Oklahoma Gas & Electric, December 28, 2009, Attach. C,
pdf 109; (Gerald Gentleman--$45.65/MWh; White Bluff--$47/MWh;
Boardman/Northeastern/Naughton--$50/MWh; Nebraska City--$30/MWh).
---------------------------------------------------------------------------
Comment: In its analysis, EPA recognized that the Cost Manual does
provide factors to estimate certain ``direct installation costs,''
namely foundation/supports, handling/erection, electrical, piping,
insulation, painting, demolition, and relocation. However, the Control
Cost Manual fails to provide factors to estimate these costs for SCR,
as recognized in EPA's analysis. EPA indiscriminately took the median
of the factors for other control technologies, which vary significantly
from SCRs. As a result, EPA's analysis slashes in half the direct
installation costs estimated by B&V. For example, the direct costs
assumed by EPA for Unit 1 are $8,799,917, but that amount would only
cover 159,998 man-hours, or 21 weeks of construction. EPA's own
schedule, even though insufficient itself, assumes 38 weeks of
construction, nearly double of the amount that EPA's analysis could
afford. Thus, EPA's estimate is insufficient for its own estimated
construction timeline, much less the 64 to 72 weeks of construction
that PNM's experienced consultants predict.
Response: We disagree with this comment. The B&V direct
installation costs were calculated by multiplying total purchased
equipment costs by various unsupported percentages, a rough estimating
practice referred to as ``factoring.'' B&V did not submit into the
record the basis for the various factors that they used. The
percentages that B&V used are demonstrably high. We compared each of
B&V's direct costs with those from a major SCR designer's (Babcock
Power) database and from similar SCR projects nationwide. Foundation
and supports, costed by B&V as 30% of purchased equipment cost, for
example, based on its estimate of purchased equipment cost, are two to
three times higher than upper bound costs reported by Babcock Power for
similar sized units ($8/MW compared with the B&V estimate of $18/MW to
$29/MW for SJGS). Based on these comparisons the B&V's costs were
excessive. No documentation has been provided to justify the higher B&V
costs.
The Cost Manual estimating procedure for direct installation costs
is based on the same factoring approach used by B&V. We tabulated the
factors for total direct installation costs for all controls reported
in the Manual. These ranged from 30% to 85% of the purchased equipment
cost. In comparison, B&V assumed direct installation costs were 103% to
113% of total purchased equipment cost.
We calculated direct installation costs for SJGS using the median
of this range or 62% of purchased equipment cost. This is consistent
with the upper bound Babcock Power estimate for actual retrofit SCR
installations and estimates made by others. The B&V estimate is also
high compared to direct installation costs that it reported for the
SJRPP SCR, which was otherwise used to extrapolate equipment costs to
SJGS. The direct installation costs for the SJRPP SCR were 95% of the
total purchased cost. We have revised our cost estimate to use this
percentage to conform to the balance of the B&V cost estimate.
The B&V estimate assumes a 150-man crew for the entire 21 weeks, a
50-hour workweek for the duration, and a wage of $55/hour. This
represents peak staffing and labor rates, even though the number of
workers would vary over time. Thus, our estimate of direct installation
costs corresponds to a longer duration than claimed. Regardless, it is
important to note that this duration corresponds to construction of a
much smaller project (less SCR bypass, preheater modifications, etc.)
than proposed by B&V. Further, for our proposal, we did not estimate
construction duration, but rather the length of time from the effective
date of the final rulemaking to startup of the SCR or 36 months. We
note that we have revised our proposal to allow 60 months from the
effective date of the rule allowing additional flexibility in deploying
workers. Thus, the basis of this comment's starting point, an EPA
estimate of 38 weeks, is incorrect. In addition, the B&V estimate does
not contain a schedule, which is required to estimate the staffing and
duration of construction.
Comment: EPA asserts that ``[t]he contingencies included in the B&V
cost estimates are double-counted and excessive,'' based on the
misimpression that there are three contingencies ``imbedded'' in the
analysis. However, two of the three allowances are for known costs, and
therefore are not ``contingencies.'' Specifically, the complexity
factor for structural steel costs of 1.2 (for Units 1 and 2) and 1.5
(for Units 3 and 4) are known, expected costs, and therefore do not
constitute a contingency factor, as noted previously. Also, the $2
million estimated for underground obstructions and the $500,000
estimated for on-site buildings are also known, and therefore do not
represent a duplicative contingency factor. Thus, EPA's claim that PNM
double-counted its contingency costs is incorrect and underestimates
the cost of SCRs at SJGS by $61,978,000.
Response: This comment explains that the ``complexity factor,''
site unknowns, and general building requirements are not contingencies,
but rather known factors. Based on this explanation and the information
we have about the SJGS, we concur that these complexity factors, and
the engineering estimates for underground obstructions and on-site
buildings, are reasonable and we have modified our cost estimates to
reflect B&V's estimates.
Comment: EPA also claims that the Interest During Construction
included in the B&V cost estimates are not allowed by the Cost Manual.
Therefore, this cost was eliminated from the cost analysis underlying
the proposed FIP. However, this cost item is a real project cost, which
will be incurred by PNM to finance the project and must by recovered
from the SJGS customers. The rejection of costs associated with
Interest During Construction underestimates the cost of the project by
$78,300,000.
Response: The B&V cost analysis include a charge for interest
during construction of 7.41% of direct plus indirect costs. This charge
is generally
[[Page 52400]]
known as the Allowance for Funds Used During Construction (AFUDC) and
is specifically disallowed under the Cost Manual methodology and
specifically disallowed for SCRs.\29\ A cost effectiveness analysis is
a regulatory analysis that is based on current annual dollars without
any inflation. AFUDC is an accounting method. Assets under construction
do not provide service to current customers and thus associated
interest and allowed return on equity are not charged to current
customers. Instead, AFUDC capitalizes these costs and adds them to the
rate base so that they can be recovered from future customers when the
assets are used. Thus, these charges represent future cash income to
the utility. In other words, AFUDC is the accumulated cost of carrying
capital and holding it waiting to spend, so money can be made in the
future by selling electricity. Future income should not be charged
against the cost of a SCR in a BART cost-effectiveness analysis. These
costs are not part of the constant dollar approach found in the Cost
Manual and should not be included in BART cost-effectiveness analyses.
---------------------------------------------------------------------------
\29\ EPA Air Pollution Control Cost Manual, pdf 486, Table 2.5,
E (Allowance for Funds During Construction) = 0.
---------------------------------------------------------------------------
3. Concerns Over Possible Electricity Rate Increases
Comment: Both the CAA and EPA BART regulations require
consideration of the remaining useful life of a source. Requiring the
imposition of possibly $1 billion or more of control technology capital
costs at SJGS, a nearly 40-year old plant, presents a likely scenario
where the remaining useful life of SJGS is less than the time period
needed for amortizing the costs of the control technologies. As such,
it could make production at SJGS during its remaining useful life
uneconomical in comparison with other existing or future plants. If, in
light of SJGS' estimated remaining useful life, it is determined that
an investment of such magnitude does not make economic sense, owners of
SJGS must evaluate alternate long-term options for meeting obligations
to provide a cost-effective, reliable supply of electricity to
customers. As such, the significant cost of requiring such SCR at SJGS
will substantially increase the cost of electricity produced by SJGS.
Over two million electric customers in New Mexico and other western
states stand to be directly and adversely affected by the EPA proposal.
PNM estimates that the average residential customer will experience a
10 percent increase in rates due solely to EPA's proposed SCR
technology. As a result of the Proposed Rule, PNM has indicated that
possible sources of replacement power may be needed to ensure it can
fulfill its obligation to provide electricity to the citizens of New
Mexico.
Response: The commenter is correct that the remaining useful life
of a facility may impact the BART determination. As we note in the BART
Guidelines,
The ``remaining useful life'' of a source, if it represents a
relatively short time period, may affect the annualized costs of
retrofit controls. For example, the methods for calculating
annualized costs in EPA's OAQPS Control Cost Manual require the use
of a specified time period for amortization that varies based upon
the type of control. If the remaining useful life will clearly
exceed this time period, the remaining useful life has essentially
no effect on control costs and on the BART determination process.
Where the remaining useful life is less than the time period for
amortizing costs, you should use this shorter time period in your
cost calculations.\30\
---------------------------------------------------------------------------
\30\ 70 FR 39104, 39169.
The BART Guidelines further clarify, ``[w]here this affects the
BART determination, this date should be assured by a federally- or
State-enforceable restriction preventing further operation.''
As part of our review of PNM's BART determination for the SJGS, we
met with representatives of PNM and its contractor several times, and
communicated numerous times through e-mail and phone. At no point did
PNM indicate that it wished to constrain the amortization period for
financing BART controls based on the remaining useful life of the
facility through the use of a federally enforceable restriction.
Comment: Several local and county governments and municipal power
systems expressed concern that the proposed FIP would require a major
capital expenditure that could well exceed $750 million, according to
PNM. Such significant costs will drastically increase the cost of power
produced by the SJGS and have the potential to increase electricity
rates in the communities served by the SJGS. Another commenter stated
our 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
[[Page 52401]]
B&V escalation index, on the other hand, is proprietary and not subject
to public review.
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\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
[[Page 52402]]
assumptions that we felt were not applicable to SJGS and if used
anyway, would have resulted in lower cost estimates, but which were not
used in our analysis.
The lifetime of an SCR, which is a metal frame packed with catalyst
modules, is equal to the lifetime of the boiler, which might easily be
over 60 years. The lifetime of a retrofit SCR is generally set equal to
the remaining useful life of the facility. The record is silent on the
remaining useful life of the SJGS units. Further, USGS studies of the
coal reserves upon which the SJGS relies indicate that the local coal
supply is adequate to support a remaining useful life of 30 years.\40\
Many utilities routinely specify 30+ year lifetimes in requests for
proposal and to evaluate proposals. In fact, an analysis prepared by
B&V for another facility assumed a 40 year SCR lifetime.\41\ And
finally, Sargent & Lundy assumed a design life of 30 years \42\ for the
nearby Navajo Generating Station which burns a similar coal. We
conclude there is nothing in the record to support a 20 year lifetime
for the SCR and believe a 30 year lifetime is justified.
---------------------------------------------------------------------------
\40\ Gretchen K. Hoffman and Glen E. Jones, Coal Availability
Study--Fruitland Formation in the Fruitland and Navajo Fields,
Northwest New Mexico, USGS Open-File 464, January 24, 2002,
Available at: http://geoinfo.nmt.edu/publications/openfile/downloads/ofr400-499/451-475/464/ofr_464.pdf.
\41\ E-mail from O'Brien to Van Helvoirt, September 28, 2004,
Re: Cost Impact, WPS-011904 at WPS-011905.
\42\ 8/17/10 Salt River Project Navajo Generating Station Units
1, 2, 3 SCR and Baghouse Capital Cost Estimate Report (S&L Navajo
Cost Analysis), Appendix A, p. 6, Sec. 1.7.
---------------------------------------------------------------------------
Comment: EPA also justifies its refusal to consider additional line
items outside the scope of the Cost Manual on the grounds that ``PNM
had provided no documentation regarding unique circumstances related to
the BART determinations.'' That claim is incorrect. EPA's own analysis
cites the documentation PNM submitted to demonstrate the unique
circumstances at SJGS, referred to by EPA as B&V's ``Cost Analysis
Manual Commentary.'' That document was a response to the cost analysis
that was initially prepared by NMED in March 2008 as a response to
follow-up questions from NMED regarding the BART determination for
SJGS. In addition, PNM also provided significant evidence of the site-
specific challenges directly to EPA in response to its questions over
the several months during which EPA prepared its BART determination for
SJGS. Thus, the assertion by EPA that PNM has failed to sufficiently
document the site-specific challenges at SJGS is incorrect.
Response: The specific items in dispute are discussed elsewhere in
our response to comments. The information provided in the ``Cost
Analysis Manual Commentary'' and additionally provided to NMED and us
explains how B&V extrapolated costs that it estimated from other
facilities to apply to SJGS. The alleged unique, site-specific
constraints at SJGS, that would justify extrapolating costs from these
other facilities, the St. Johns River Power Project, which burns coke,
and Harding Street, were never explained. The record, for example, does
not contain any structural steel and duct layout drawings to justify
this high contingency and other factors, nor does it contain vendor
quotes specific to SJGS's coal and site constraints. In fact, as noted
elsewhere, we specifically asked PNM to document site specific
constraints but they did not respond.
B. Comments on Our Proposed NOX BART Emission Limits
We received a significant number of comments concerning our
proposed 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
[[Page 52403]]
systems (CEMS) data for existing units operating with retrofit SCRs, as
we explain elsewhere in our response to comments.
Comment: In contrast to EPA's 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.
[[Page 52404]]
As Exhibit 2 shows,\48\ the averaging conventions we used are: (1)
A conventional 30-day calendar rolling average; (2) a 30-day BOD
rolling average based on any operation in a given day counting toward
the average; and (3) a 30-day BOD rolling average based on only full
24-hour days. We believe that averaging scheme (2) complies with the
BART Guidelines, which defines a BOD to be ``any 24-hour period between
12:00 midnight and the following midnight during which any fuel is
combusted at any time at the steam generating unit.'' \49\
---------------------------------------------------------------------------
\48\ Exhibit 2, Best Performing SCR Retrofit Installations, June
8, 2011.
\49\ 70 FR 39104, 39172.
---------------------------------------------------------------------------
The Havana Unit 9 data shows that it has operated under 0.05 lbs/
MMBtu from mid-2009 to the end of 2010 on a continuous basis. In fact,
this unit has operated under 0.035 lbs/MMBtu for much of that time. The
Parish Unit 7 data shows that it has operated under 0.05 lbs/MMBtu from
mid-2006 to mid 2010 on a continuous basis. In fact, this unit has
operated for months at approximately 0.035 lbs/MMBtu, and for
approximately 2 years at approximately 0.04 lbs/MMBtu. The Parish Unit
8 data show that it has operated almost continuously under 0.045 lbs/
MMBtu since the beginning of 2006. Other units' data show months of
continuous operation below 0.05 lbs/MMBtu. We believe this data
demonstrates that similar coal fired units that have been retrofitted
with SCRs are capable of achieving NOX emission limits of
0.05 lbs/MMBtu on a continuous basis.
In addition, it is important to note that most of the
NOX CEMS data in the CAMD database is generated under cap
and trade programs, such as the Acid Rain Program, Clean Air Interstate
Rule (CAIR), and the NOX SIP Call or to comply with elevated
permit limits, such as from netting out of NSR review. Therefore, these
reporting units are not subject to regulatory requirements that compel
the continuous operation of SCRs to achieve best available
NOX reductions. Consequently, a simple examination of the
raw data will not always by itself reveal the NOX reduction
these limits are capable of achieving.
This is demonstrated by the Parish units in Texas, which are likely
the best performing SCR units over the long term. The units operate to
maintain a system wide cap, rather than to meet unit by unit limits.
The Parish results may not, therefore, reflect the maximum capacity of
the SCRs to reduce the plants' NOX emissions. The Parish SCR
acceptance tests indicate that they can operate at design levels, or
0.03 lb/MMBtu. This is evidenced by examination of an excerpt from the
hourly NOX data for Parish Unit 8, which typically operates
at a 30-day rolling average of about 0.044 lb/MMBtu and was run for
extended periods at 0.03 lb/MMBtu from August 5, 2006 to September 20,
2009 and then at 0.035 lb/MMBtu from September 21, 2006 to December 1,
2006 to demonstrate its capability.\50\ In other words, lower
NOX emissions are achievable from the existing fleet of SCR-
equipped units than are reflected by a simple examination of the CAMD
data.
---------------------------------------------------------------------------
\50\ We examine this data excerpt in detail in our Complete
Response to Comments document.
---------------------------------------------------------------------------
Comment: A commenter states that while the proposed NOX
limit of 0.05 lbs/MMBtu as BART for SJGS would significantly reduce
NOX emissions from the SJGS and have a positive impact on
visibility and public health, a lower NOX limit of 0.035
lbs/MMBtu is not only technically feasible, but legally-required for
SJGS under the CAA. The commenter points to our proposal language that
the State of New Mexico ``noted the potential for greater control rates
as low as 0.03 lbs/MMBtu'' for SJGS. This commenter references our TSD
for the proposed FIP, that SCR technologies ``are routinely designed
and have routinely achieved a NOX control efficiency of
90%.'' Therefore, assuming a 90% removal efficiency, based on SJGS's
current rate of emissions (under 0.30 lbs/MMBtu), the commenter
concludes modern SCR technology would bring controlled emissions down
to 0.03 lbs/MMBtu. The commenter proposed an emission limit of 0.035
lbs/MMBtu, based on a report performed by its own contractor. This
report includes vendor guarantees for 90% controls, and presents
information that an emission limit of 0.035 lbs/MMBtu is being achieved
at other units. The commenter further states that we must present
specific circumstances to preclude the application of this emission
limit. Lastly, the commenter makes a case that, the feasibility of a
lower NOX emission limit aside, the additional costs
associated with achieving such a limit, weighed against the additional
mass of NOX that would be removed, make such a limit cost
effective.
Response: We have reviewed the information presented in the
commenter's contractor's report. As we discuss elsewhere in our
response to comments, we agree there are SCR retrofits that are meeting
NOX emission limits below 0.05 lbs/MMBtu. Our analysis also
indicates there are a few SCR retrofits that have demonstrated the
ability to do this on the basis of a 30 day BOD average. The
commenter's contractor has presented monthly emission data for a number
of units which appear to indicate that some are occasionally able to
meet monthly emission limits below 0.05 lbs/MMBtu. The Havana 9 unit is
particularly highlighted, which appears to indicate that unit has even
met such a limit for perhaps 4-5 months at a time. However, in our
view, we conclude this is not enough time to demonstrate that the units
of the SJGS are able to meet a NOX limit of 0.035 lbs/MMBtu
on the basis of a 30 day rolling average year round.
We further agree that it may be technically feasible, considering
both vendor performance guarantees, and the data discussed above, for
some SCR retrofits to reliably meet an NOX limit of 0.035
lbs/MMBtu on a 30 day rolling average (especially if figured on the
basis of a BOD). However, we see no data, presented either by the
commenter or from our own research,\51\ which we have discussed
elsewhere in our response to comments, which would lead us to conclude
that such a limit has been sufficiently demonstrated in practice.
---------------------------------------------------------------------------
\51\ Exhibit 2, 30 Day Rolling Averages for Selected Best
Performing SCR Retrofit Installations.
---------------------------------------------------------------------------
To our knowledge, there are no air permits in the U.S. that require
that a NOX emission limit of 0.035 lbs/MMBtu be met for a
coal-fired unit such as SJGS with retrofitted SCRs on the basis of a 30
day rolling average. Furthermore, the existence of a permit limit is
not the only indicator of the technical feasibility of achieving a
particular emission limit. However, its absence, combined with no
documented instance of an SCR retrofit achieving this level of control
on a continuous basis, causes us to conclude that a 30 day rolling
average NOX emission limit of 0.035 lbs/MMBtu for the units
of the SJGS is not BART.
Comment: The NPS and the USFS separately stated they believe PNM
has underestimated the ability of SCR to reduce emissions. For example,
the NPS states that B&V assumed that SCR could achieve 0.05 lbs/MMBtu
(annual average) when evaluating retrofitting of SCR at the Craig power
plant in Colorado. Both the NPS and the USFS stated that EPA's Clean
Air Markets data, and vendor guarantees show that SCR can typically
meet 0.05 lb/MMBtu (or lower) on an annual average basis. The USFS
stated NOX emissions can be reduced by 90% with SCR
installed at 0.05 lbs/MMBtu emission limit. The NPS included data it
claims indicates
[[Page 52405]]
that SCR can achieve year-round emissions of 0.05 lbs/MMBtu or lower at
26 coal-fired EGUs, eleven of which are dry-bottom, wall-fired units
like SJGS. The USFS also referenced this data. The NPS believes PNM has
not provided any documentation or justification to support the higher
values used in its analyses. They also present information from
industry sources that supports their understanding that SCR can achieve
90% reduction and reduce emissions to 0.05 lb/MMBtu or lower on coal-
fired boilers.
Response: We agree with the NPS that PNM has underestimated the
ability of SCR to reduce emissions. As discussed elsewhere in our
response to comments, we are requiring that the units of the SJGS meet
an emission limit of 0.05 lbs/MMBtu on the basis of a 30 day rolling
BOD average.
Comment: PNM requested that we reevaluate the cost effectiveness of
SCRs at SJGS because they feel that our proposed NOX
emission limit of 0.05 lbs/MMBtu on the basis of a 30 day rolling
average is not achievable. They reason that we therefore overestimated
the emission reductions that the SCRs would achieve, thus
underestimating the cost per ton of pollutant removed. In addition,
they requested we reevaluate the visibility improvement that it assumed
the SCRs would provide. They reason that at a higher NOX
emission limit, the SCRs would not achieve nearly the level of
visibility improvement that we expect.
Response: As explained elsewhere in our response to comments, we
believe the units of the SJGS can achieve a NOX emission
limit of 0.05 lbs/MMBtu on the basis of a 30 day BOD average.
Therefore, we do not believe there is any need to revise either the
visibility modeling or the cost analysis on that basis.
Comment: The USFS feels that PNM has underestimated the achievable
emission limit that would result with Low-NOX burners with
overfire air, combined with SCR. Based on data from EPA's Clean Air
Markets, SCR usually meets an annual average emission limit of 0.05
lbs/MMBtu or lower. Based on the same data, 26 electric generating
units have met this emission limit, eleven of which are similar in
design as the SJGS. NOX emissions can be reduced by 90% with
SCR installed at 0.05 lbs/MMBtu emission limit. Given the SJGS's size
and amount of NOX emissions, a more stringent emission limit
than PNM's proposal is not only achievable, but it will provide for
greater reduction in NOX emissions.
Response: We agree with the USFS that PNM has underestimated the
emissions reductions achievable with the addition of SCR. However, we
draw a distinction between units that have met an emission limit of
0.05 lbs/MMBtu and those that have reliably demonstrated the ability to
continuously meet that emission limit. Therefore, although we agree
there are many SCR installations that are capable of meeting an annual
NOX emission limit of 0.05 lbs/MMBtu, we extended our
analysis. As we discuss elsewhere in our response to comments, we also
analyzed the ability of some of the better controlled SCR retrofits to
meet this same limit on a 30 BOD average and found that it was feasible
for the SJGS to do so.
Comment: EPA proposes to require the SJGS to meet a NOX
emission limit of 0.05 lbs/MMBtu individually at each of the plant's
four units. EPA's own BART rules, however, expressly authorize
application of BART emission limits on a plant wide basis, and the
proposal offers no justification for deviating from that established
and reasonable practice. Because it makes no difference, in terms of
visibility impact or visibility improvement, as to which unit or units
within a facility the emissions--or the emission reductions--occur at,
there is no rational basis for the Agency to preclude the plant wide
averaging that is contemplated in EPA's own BART rules.
Response: The commenter correctly notes that the BART Guidelines
state that the BART determining authority ``should consider allowing
sources to `average' emissions across any set of BART-eligible emission
units within a fenceline, so long as the emission reductions from each
pollutant being controlled for BART would be equal to those reductions
that would be obtained by simply controlling each of the BART-eligible
units that constitute BART-eligible source.'' \52\
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\52\ 70 FR, 39104, 39172.
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As we discuss elsewhere in our response to comments, we received
another comment requesting that we revise our proposed NOX
BART limit, which was calculated on the basis of a rolling 30 day
calendar average, and adopt instead a limit calculated on the basis of
a rolling 30 day BOD average. We agree, and are finalizing our action
in accordance with that request. Combining a plant wide average with a
BOD average in which individual units may be on different 30 day
periods, adds an additional level of complexity to the calculation of a
plant wide average. We believe it is possible to integrate the 30 day
BOD and plant wide averaging concepts, but due to our consent decree
deadline, we do not have the time to construct the algorithm that could
be used to guarantee practical enforceability. Therefore, as we discuss
elsewhere in our response to comments, we condition the NOX
limit for the units of the SJGS on the basis of a rolling 30 day BOD
average. We leave the issue of a plant wide average to a possible
future SIP revision that includes a verifiable, workable and
enforceable algorithm that ensures the resulting emissions are equal to
those reductions that would be obtained by simply controlling each of
the BART-eligible units that constitute BART-eligible source.
Comment: One commenter requested we exclude emissions occurring
during startup, shutdown, and malfunctions events from having to comply
with our proposed NOX limit of 0.05 lbs/MMBtu because post-
combustion controls equipment such as SCRs cannot operate effectively
during those events. Alternatively, this commenter requested we
consider setting a different standard that is more representative of
the emission characteristics of the units during those events or
consider requiring work practice standards to minimize such emissions.
Another commenter requested that we specifically include startups and
shutdowns in this language, making clear that any emission in excess of
an applicable emission limit during any such event constitutes a
violation of the applicable emission limit. That commenter also
requested that we clarify that this provision applies to all pollutants
controlled by this FIP, including, NOX, SO2,
H2SO4, ammonia, and particulate matter (PM).
Response: As we have discussed in our response to other comments,
we are changing the rolling averaging period for our proposed
NOX emission limit of 0.05 lbs/MMBtu from one based on 30
calendar days, to one based on a 30 BODs. The CEMS data indicate that
our proposed NOX BART limit can be achieved without
separately limiting startups, shutdowns, and malfunctions. Further, the
startup, shutdown, and malfunction events cited in this comment are a
characteristic of current SCR operating modes, i.e., under trading
programs with no incentive to optimize design and operation to achieve
a permit limit. These spikes result when flue gas temperatures fall
below the operating temperature range of the SCR catalyst, or when the
ammonia injection system malfunctions. We believe that startup and
shutdown spikes are minimized by using the BOD metric, which we assume
was why it was requested that we employ it. As there is no explicit
provision for the exclusion
[[Page 52406]]
of start up, shut down, or malfunction events for NOX,
SO2, and H2SO4, all data will be used
in determining compliance with this limit. As explained elsewhere in
our response to comments, we are not setting an emission for PM for the
units of the SJGS at this time, and we have determined that neither an
ammonia limit, nor ammonia monitoring is warranted. We do not see a
need to further clarify that the limits we are finalizing must be
continuously met.
We also agree with the comment that work practice standards should
be developed and used to minimize such emissions. These should include
proactive measures such as SCR reactor preheating during a cold start;
selecting catalyst to maximize ramp rates and NOX reduction
at low temperatures; and use of both tunable ammonia injection grids
(AIGs) and static mixers. We encourage PNM to develop and employ those
measures.
Comment: PNM contends our conclusions differ greatly from those
that have been made in other states in determining NOX BART
for other electric generating units. PNM submitted a table of the other
NOX BART determinations that have been made by 13 different
states as they have developed the proposed RH SIPs that are awaiting
EPA approval. PNM stated that in comparison to the determinations made
by every other state, the EPA proposal concludes that SJGS must be
required to install, (i) the most effective SCR in the nation, (ii) at
the cheapest price, and (iii) in the shortest amount of time. PNM
concludes that if our proposal is a true indication of our
interpretation of the RH program, we will be faced with disapproving
every other state RH implementation plan in the country and replacing
those plans with FIPs.
Response: As explained in our responses to other comments, we have
made adjustments in our NOX BART determination for the SJGS
that pertain to this comment. We have adjusted our cost basis for the
installation of SCR on the units of the SJGS, which slightly increased
the cost of the controls versus the tonnage of NOX removed.
In addition, we have modified the schedule for compliance with the
emission limits to now require compliance within 5 years--rather than 3
years--from the effective date of our final rule. Also discussed in our
responses to other comments, although we find that our proposed
NOX BART emission limit should remain at 0.05 lbs/MMBtu, we
have modified the averaging time from a straight 30 day calendar
rolling average, to a 30 day BOD average.
We disagree with the statement that our conclusions regarding
NOX BART for the SJGS are far different from those that have
been made in other states in determining NOX BART for other
electric generating units. As the commenter's own table indicates,
other states and EPA regions have made NOX BART
determinations that will be met or are proposed to be met with the
addition of SCR, including the Four Corners Power Plant (EPA Region 9),
Hayden Units 1 & 2 (CO), Otter Tail Big Stone 1 (although this is a
cyclone boiler) (SD), and Naughton Unit 2.
Also, we initially note two points regarding the costs of the
controls, while accepting the values listed on the chart at face value.
First, the cost effectiveness of all the BART controls, which depending
on the facility range from combustion (e.g., OFA, LNB) to post
combustion (e.g., SCR, SNCR), are frequently much worse (more
expensive) than the cost effectiveness we calculated for SCR on the
units of the SJGS. Second, the cost effectiveness values listed for
SCR, are frequently similar to the cost effectiveness we calculated for
SCR on the units of the SJGS (especially if compared to our revised
cost effectiveness).
Lastly, although we strive to ensure that the regulated community
is treated equitably with regard to the RHR, the nature of the BART
five factor analysis is designed to consider site-specific issues. For
instance, we note that the chart does not contain any information, nor
is any presented elsewhere, concerning a visibility impact analysis. As
required by the BART Guidelines, this must be included in a BART
analysis.\53\ Without such an analysis, there is no way to justify any
control even if it has a very low cost. Conversely, even controls that
have either a relatively high capital cost or cost effectiveness in
terms of dollars per ton may be justified if they result in a
significant visibility benefit. In the case of the SJGS, our BART FIP
NOX emission limit of 0.05 lbs/MMBtu is predicted to result
in a combined visibility improvement on 16 Class I areas of 21.69 dv,
which we consider very significant.
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\53\ 70 FR 39104, 39163.
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C. Comments on Our Proposed SO2 Emission Limit
Comment: One commenter stated an SO2 emission rate of
0.15 lbs/MMBtu on a 30 day rolling average is not appropriate and does
not ensure that SO2 emissions from SJGS will not interfere
with visibility in New Mexico or other states. This commenter believes
an SO2 emission rate of 0.15 lbs/MMBtu does not reflect the
level of emissions reductions achievable under BART for wet limestone
scrubbers. This commenter also points out that the units of the SJGS
are all currently achieving SO2 limits significantly under
0.15 lbs/MMBtu on a 30 day rolling average and concludes we should not
set SO2 emission rates in a Section 110 FIP that exceed the
historic SO2 emission rates at SJGS. The commenter requests
that if we do set a non-BART SO2 limit in our Section 110
FIP, we set unit-specific limits at least consistent with the recent
historic SO2 emission identified in the table above, or
issue formal SO2.BART determinations for each unit at SJGS
under a Section 308 FIP.
Response: We believe the SO2 emission rate of 0.15 lbs/
MMBtu is appropriate to meet the requirements of section
110(a)(2)(D)(i)(II) to ensure that these emissions from SJGS will not
interfere with visibility in other states. As discussed in our
proposal, we believe that emissions reductions consistent with the
assumptions used in the WRAP modeling will ensure that emissions from
New Mexico sources do not interfere with the measures designed to
protect visibility in other states. We are aware that the
SO2 controls currently installed on the SJGS are in fact
achieving greater control than would be evidenced by an emission limit
of 0.15 lbs/MMBtu. The commenter's observation of the SJGS's current
SO2 emissions simply means that the SO2 emissions
from the SJGS are better controlled than what we require to prevent
interference with visibility under section 110(a)(2)(D)(i)(II). We
agree with the commenter that the 0.15 lbs/MMBtu emission limit does
not reflect the level of emissions reductions achievable through the
use of a wet limestone scrubber and that a source specific BART
determination for the SJGS might well result in a determination
requiring the installation of scrubber to meet a more stringent
limitation. We did not propose to address the BART requirements for
SO2 from the SJGS in this action because SJGS will not be
installing new control equipment to meet the 0.15 lbs/MMBtu emission
limits. As a result, the issue of requiring different capital
expenditures to meet the requirements of section 110(a)(2)(D)(i)(II) as
compared to those of the RH program's BART requirement does not arise.
Since we did not propose the SO2 emission rate under the RHR
requirements, the comments concerning BART are outside the scope of
this action.
[[Page 52407]]
Comment: In declining to find that its asserted SO2
limits satisfy BART, EPA's proposal improperly relies on a RH trading
program under 40 CFR 51.309 that does not yet exist. Putting aside
EPA's legal obligation to make a formal BART determination in its
proposed FIP at this time, any emissions trading program that is
proposed to replace a BART limit ``must achieve greater reasonable
progress than would be achieved through the installation and operation
of BART.'' 40 CFR 51.308(e)(2). Because EPA cannot make the required
demonstration that New Mexico's future, theoretical trading program
will be ``better than BART,'' EPA is illegally sidestepping its current
BART obligations under 40 CFR 51.308 (e)(2)(i).
Response: We disagree with the commenter. In accordance with our
proposal, we are finalizing SO2 limitations under section
110(a)(2)(D)(i)(II), not under the RHR. We disagree with commenter's
view that we are sidestepping our BART obligations by not proposing to
establish SO2 BART emission limits. Our rationale for not
proposing BART requirements for SO2 in this action appears
in our response just prior to this comment. Moreover, we note that the
established SO2 limits do not rely upon a nonexistent
trading program. We will address New Mexico's obligation to address
SO2 under the RHR in a future separate action.
D. Comments on Our Proposed H2SO4 and Ammonia
Emission Limits and Other Pollutants
Comment: The League of Women Voters, Montezuma County, Colorado
supports the EPA determination that SCR is cost-effective for all units
of the SJGS. They defer to our judgment on the proposed final limit for
sulfuric acid emissions. They request that we choose the lower limit of
2 ppmvd, adjusted to 6 percent oxygen for the regulation of ammonia
emissions. Their justification for this request is the deterioration in
visibility at Class I areas such as Mesa Verde National Park, and the
imperative to achieve improvements in visibility as rapidly as
possible.
Response: We appreciate the support of the League of Women Voters,
Montezuma County, Colorado. As explained elsewhere, we have determined
that neither an ammonia limit, nor ammonia monitoring is warranted.
Comment: One commenter stated the same pollutants, including PM
2.5, NOX, and VOCs (contributing to ground level ozone) that
contribute to visibility impairment also harm public health. This
commenter also noted that ozone concentrations in parks in the Four
Corners region approach the current health standards, and likely
violate anticipated lower standards. In fact, ozone levels in many
parts of New Mexico, Colorado, and Utah are already in the range of
ozone levels deemed to be harmful to human health.
Response: We agree that the same pollutants that contribute to
visibility impairment can also harm public health. Although we note
public health benefits, we did not rely on these benefits in
establishing controls necessary to meet BART in today's action.
Comment: One commenter expressed support for our proposed
H2SO4 and ammonia limits proposal for the SJGS,
and the corresponding installation of CEMS. That commenter also urged
us to set the H2SO4 emission rate at the lowest
rate of 1.06 x 10-\4\ lb/MMBtu for each unit at the SJGS,
suggesting stack test monitoring for H2SO4 on a
more frequent basis than annual monitoring. The commenter also
supported our proposed ammonia emission limit at the lower range of 2.0
ppm, with CEMS. Further, this commenter requested we clarify these
emission limits are required under the RH program as part of a BART
determination for the facility and must be complied with within 3 years
of the date of the final rule. Lastly, we were requested to set a BART
PM emission limit of 0.012 lb/MMBtu on a 6-hour block average, and a
10% opacity limit at each unit at SJGS, also within 3 years of the date
of the final rule.
Another commenter questioned our authority to regulate ammonia
through the RH rule.
Response:
In our response to comments on the assumed ammonia slip level used
to estimate sulfuric acid emissions, we have recalculated the expected
sulfuric acid emissions rate with no ammonia slip. The sulfuric acid
emission rate was recalculated to be 2.6 x10-\4\ lb/MMBtu
based on an ammonia slip value of 0 ppm, compared to our original value
of 1.06 x10-\4\ lb/MMBtu at 2ppm ammonia slip. The actual
ammonia slip will vary over the life of a catalyst layer. We conclude
an assumption of ammonia slip up to 2.0 ppm as the catalyst ages is
reasonable for an SCR system that is designed to achieve a
NOX emission limit of 0.05 lbs/MMBtu on a rolling 30 BOD
basis, considering the coal the SJGS burns. We also note PNM assumed an
ammonia slip of 2.0 ppm in its SCR cost estimation. As the ammonia slip
increases, the sulfuric acid emissions will decrease. This revised
sulfuric acid emission rate remains significantly lower than that
estimated by NMED and is a minimal level of sulfuric acid emissions.
Based on these updated calculations and in response to comments, we are
requiring the SJGS to meet an H2SO4 emission
limit of 2.6 x10-\4\ lb/MMBtu.
Our intention in our proposal regarding the regulation and
monitoring of ammonia was, like H2SO4, to
minimize the contribution of this compound to visibility impairment.
After careful consideration of the comments we received concerning our
proposal to require the SJGS to meet an hourly average emission limit
of 2.0 parts ppmvd for ammonia, we have determined that neither an
ammonia limit, nor ammonia monitoring is appropriate. Instead, we will
approach the issue of the impact of ammonia slip on visibility
impairment though proper upfront design, rather than after-the-fact
regulation. We are requiring that the NO control device
(presumably, but not required to be SCR) must be designed to achieve a
NOX emission limit of 0.05 lbs/MMBtu on a rolling 30 BOD
basis with an ammonia slip of 2.0 ppm. We believe this strikes the
proper balance between the additional cost of ammonia monitoring and
reporting and the need to have a reasonable expectation of the amount
of ammonia emitted by the SJGS.
The H2SO4 emission limit is being required
under the RH program as part of a BART determination for the SJGS and
must be complied with at the same time as the NOx limits for each unit.
With regard to the commenter's request that if emission monitors are
truly unavailable for this pollutant, we should require stack test
monitoring for H2SO4 on a more frequent basis
than annual monitoring, we do not believe that an adequate continuous
emissions monitor is available for H2SO4 and will
continue to rely on stack testing. We do not agree that more frequent
stack testing is appropriate, due to a consideration of the cost of
that testing in comparison to the value of having a greater certainty
of the H2SO4 emissions that may result. As we
discussed in our proposal,\54\ we have concluded that the low sulfur
coal burned at the SJGS generates very little sulfur trioxide
(SO3), and hence H2SO4, which is
formed when SO3 combines with water in the flue gas to form
H2SO4. In addition, SCR catalysts are available
with a low SO2 to SO3 conversion of 0.5%, further limiting
the production of H2SO4. Therefore, we conclude
we have struck the right balance.
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\54\ 76 FR 499.
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[[Page 52408]]
E. Comments on the Emission Limit Compliance Schedule
Comment: We received a number of comments both for and against our
proposal to require compliance with our proposed emission limits within
three years following the effective date of our final action. The
League of Women Voters, Montezuma County, Colorado opposed extending
the deadline to five years for achieving the proposed emission limits.
They stated SCR was first patented in the U.S. in 1957 and has been an
operational pollution control technology for over 30 years at large
scale facilities like the SJGS. They believe allowing an extra two
years may provide the opportunity for ambiguity and technological
changes to enter into arguments about engineering solutions and
controls, which potentially could feed appeals and litigation by the
operator of the SJGS, and thus delay cleanup efforts. The Navajo Nation
expressed concern that the proposed compliance schedule is too
stringent for SJGS to reasonably meet and could result in a reduction-
in-force of a significant number of employees, including Navajo
workers, thereby contributing to family hardships and limiting the
ability of affected employees, contractors, and subcontractors to meet
their financial obligations.
Another commenter asked if there is a smarter way to phase the
installation of controls over a longer period of time.
Another commenter stated any proposed truncation of the five-year
compliance period should be persuasively justified by a specific
analysis of the feasibility and cost-effectiveness of such a schedule
in light of the circumstances at the facility in question. According to
the commenter, no such justification appears in the proposed rule. The
proposal simply asserts that a three year compliance deadline would be
applicable because similar compliance schedules have been met at some
other facilities.
Another commenter stated that a compliance deadline of three years
will result in significant additional costs that we did not account for
in our analysis. They stated the proposed FIP attempts to justify a
three-year compliance deadline by citing two studies, but those studies
do not reflect a realistic schedule for installing SCRs at SJGS. This
commenter made several points concerning two studies on SCR timelines
we cited in our proposal that the commenter feels call our use of the
information into question. The commenter then cites another report it
believes is more representative and concludes the site congestion and
other site-specific challenges at SJGS will demand an implementation
schedule that is similar to SCR installations at Units 6 and 7 of First
Energy's Sammis facility, which required 60 and 62 months to complete,
respectively.
Response: We have decided, based on our review of several comments,
to finalize a schedule for compliance with the emission limits of 5
years--rather than 3 years--from the effective date of our final rule.
We view the B&V cost analysis as being a very preliminary, low-level
estimate, that is missing much of the information required to develop a
site-specific schedule. This estimate does not include, for example,
plot plans, a diagram showing SCR layout, an analysis of
constructability, construction site plan, or an implementation
schedule, which are required to develop a site-specific schedule. Thus,
we selected an average compliance time, based on a review of a number
of sources, including the following:
13 months for 675 MW Somerset Station;
18 months for Harding Street;
19 months for two 900 MW units at Keystone.
26 months for Asheville Power Station with a reported
normal range of 27 to 30 months.
30 months for 4 units based on 21 months typical for 1
unit, each additional unit at same facility adds 2-3 months. Findings
for typical installations.\55\
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\55\ ClearSkies: http://www.epa.gov/clearskies/03technical_package_sectiong.pdf.
---------------------------------------------------------------------------
36 months for St John River Power Park, from contract
award to startup.
42 months for 14 SCRs installed to comply with the Texas
Nonattainment SIP.
60 months estimated by B&V for 5 units at Four Corners.
69 months estimated by Sargent & Lundy for 3 units at
Navajo.
The median of these estimates is 33 months and the average is 37
months. The UARG report \56\ cited in this comment was published around
the same time (October 1, 2010) that we did most of our SCR analysis
and was unknown to us at that time. PNM and B&V did not identify it in
discussions with us in October-November 2010. That report confirms the
information we found through independent investigation, summarized
above. It indicates that it took 28 to 62 months to design and install
the 14 SCRs in its sample (compared to 18-69 months for the 9
facilities (greater than 33 units) in our sample). The average design/
build time for the units in the report is 43 months, compared to an
average of 37 months for our retrofit SCR timeframes. None of the units
in these two collections overlap. We agree, based on the information we
have from the site, that site congestion will require a longer total
installation time for all four units than the average found in both of
these collections. Please see our Complete Response to Comments for NM
Regional Haze/Visibility Transport FIP document for more detail
concerning our response to this question.
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\56\ ``Implementation Schedule for Selective Catalytic Reduction
(SCR) and Flue Gas Desulfurization (FGD) Process Equipment'' October
1, 2010, prepared by J. Edward Cichanowicz for the Utility Air
Regulatory Group.
---------------------------------------------------------------------------
However, we do not believe there is a basis in the record for
concluding that installation of SCRs would require a timeframe as long
as claimed for Sammis Units 6 and 7. The seven Sammis units were
subject to an enforcement action,\57\ and the SCRs were installed
pursuant to a Consent Decree.\58\ The Consent Decree allowed 5+ years,
from the date of the Decree in March 2005, to install SCR on two units,
SNCR on five units, low NOX burners, and new SO2
scrubbers on seven units. Construction was completed faster than the
Consent Decree schedule, however, and all of the controls were
operating by May 2010.
---------------------------------------------------------------------------
\57\ U.S., et al., v. Ohio Edison Company, et al., Opinion and
Order, Case No. 2:99-CV-1181, In the U.S. District Court for the
Southern District of Ohio, Eastern Division, available at: http://www.4cleanair.org/OhioEdison.pdf.
\58\ U.S. v. Ohio Edison and Pennsylvania Power Company, Consent
Decree, March 18, 2005, available at: http://www.epa.gov/compliance/resources/decrees/civil/caa/ohioedison-cd.pdf.
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The Sammis retrofit project at this 2,200 MW plant is generally
recognized as the largest air quality control retrofit in the history
of the United States and is considered to be ``the most difficult in
the country because of the extremely limited space for installation of
the new air emission control equipment and systems.''\59\ This project
is not comparable to SCR retrofits at SJGS, neither in scope, nor
complexity, nor site congestion.
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\59\ Michael D. McElwain, Sammis Energy Plant Project Wins
Award, Herald-Star, December 13, 2010, available at: http://www.hsconnect.com/page/content.detail/id/552039/Sammis-energy-plant-project-wins-award.html?nav=5010.
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Based on an examination of site conditions and available data on
historical SCR installation timeframes as described above, we find that
a change to our proposed compliance schedule is appropriate. We believe
that a longer time frame than the median time frame for construction
identified in our survey of SCR retrofits is justified due to site
[[Page 52409]]
congestion. We do not believe a timeframe as long as that allowed for
the Sammis units is warranted, nor is it allowed by the RHR.
Consequently, we are finalizing a schedule which requires compliance
with the emission limits within 5 years--rather than 3 years--from the
effective date of our final rule.
Comment: A commenter objected to the proposed compliance schedule
of 3 years and was concerned that SCR installations often trigger PSD
permitting requirements because they constitute physical changes to an
existing emission unit that may result in increased emissions of
sulfuric acid mist. The commenter stated that obtaining a PSD permit
for an SCR can take up to 18 months or more and even if the SCRs do not
trigger PSD permitting requirements projects could still trigger state
permitting requirements, which can require several months to satisfy.
The commenter further stated that the installation of an SCR will
involve a significant capital expenditure that will require approval
from the New Mexico Public Regulation Commission. The commenter alleged
that we failed to take these requirements into account resulting in an
unachievable deadline for compliance.
Response: As stated elsewhere in our response to comments, we have
modified the compliance schedule. We are finalizing a schedule which
requires compliance with the emission limits within 5 years--rather
than 3 years--from the effective date of our final rule. We conclude
this is adequate time for the inclusion of any possible permitting
requirements.
Comment: A commenter stated that our compliance schedule of three
years from the effective date of our final rule did not allow time for
competitive bidding. To meet a three-year schedule, the commenter
argued, PNM would have to simply offer the work to a single vendor,
eliminating the opportunity to identify other qualified vendors or
provide any incentive to encourage competitive pricing. Therefore, the
failure to account for this renders the three-year compliance date
unrealistic, and calls into question the underlying cost estimates,
which are based on contracts entered into by other utilities that most
likely were allowed sufficient time to complete a proper competitive
bidding process.
Response: We believe this comment is incorrect. The 3 year schedule
we proposed did include time to prequalify bidders. However, as stated
elsewhere in our response to comments, we have extended the compliance
schedule to 5 years.
Comment: A commenter stated that our cost estimate does not appear
to account for the need to have two units offline at the same time to
install the SCRs, and the commenter expresses the view that PNM would
not be able to meet a three-year deadline for compliance without taking
two units offline at once. The commenter listed a number of things that
would have to occur in the construction process, such as engineering,
vendor procurement, and catalysts procurement, and finally, the fact
that construction on each unit needs to take place during an outage. In
addition, the commenter argues, a three-year deadline would likely
eliminate the ability of PNM to plan the outages for off-peak seasons,
when the demand for power and the cost for replacement power are lower.
Also, a three-year period would require PNM to prefabricate as much of
the SCRs as possible, which would require extremely large
prefabrication yards and prefabrication crews, significant overtime
hours, expedited material costs, double ``heavy long-lift'' crane
costs, and a larger construction workforce overall. The commenter
states these costs were not included in its analysis. The commenter
lists other complications such as a shortage of skilled labor, air
permitting requirements, and other pre-construction activities, the
possible need to purchase electricity at higher prices, and strain on
PNM's other generating assets. The commenter requests we consider these
costs and constraints in its setting a three- to five-year, compliance
schedule and set the deadline for compliance to the five years allowed
by law, or even longer if PNM is required to respond with a ``Better
than BART Alternative.''
Response: As stated elsewhere in our response to comments, we have
modified the compliance schedule. We find that compliance with the
emission limits must be within 5 years of the effective date of our
final rule. A longer schedule will allow PNM to tie in the SCRs during
routinely scheduled maintenance outages and to plan outages for off-
peak seasons. We have not received any request from PNM that we
consider a ``better than BART alternative.''
F. Comments on the Conversion of the SJGS to a Coal-to-Liquids Plant
With Carbon Capture as a Means of Satisfying BART
We received comments encouraging us to consider coal-to-liquids
(CTL) technology with integrated power generation as an option in
determining BART for SJGS. The commenter states that our BART
determination proposal would reduce NOX emissions, but would
do little to reduce SOX or carbon dioxide (CO2)
emissions, leaving SJGS far from compliance with new or future
standards. The commenter states our BART proposal could cost $750
million or more (based on PNM's figures), and would have an adverse
effect on the cost of electricity. Based on 2006-generation numbers of
12.5 million MWh's, amortized over a 20-year period at 8% interest, and
a $750 million modification price, the commenter calculates the cost of
electricity would increase by approximately $6 per MWh or 0.6 cents per
kWh.
The commenter states that although natural gas fired combined
cycle, and integrated gasification combined cycle, have merit no option
offers more benefits than a CTL plant with integrated power generation.
According to the commenter, the synthetic fuels produced are drop-in
replacements for diesel and jet fuel, and contain virtually no sulfur.
The US military has conducted extensive tests on these fuels, and finds
that they produce far lower emissions than conventional petroleum-based
fuels.
According to the commenter, the conversion of the SJGS into a CTL
plant with integrated power generation would retain jobs in the mining
and plant operations, will create ultra-clean biodegradable synthetic
fuels in the CTL process, and will use the waste heat and byproduct
gases from the process to cogenerate electric power. The commenter
states that emissions of criteria pollutants from the CTL plant
manufactured by his company approach those of a NGCC plant and
emissions of CO2 are half those of a NGCC plant.
The commenter calculates that a 50,000 barrel per day CTL plant can
co-produces 1200 MW of clean, efficient, low carbon power. This would
be baseload generation, the commenter argues, that would be produced
24/7 and could be sold into the California marketplace. The size of the
facility could be scaled to meet greater energy needs. The commenter
states a plant of this size would consume approximately 30,000 tons per
day of coal, which is nominally twice as much coal as is currently
consumed, so more jobs will be needed at the mine.
According to the commenter, NOX emissions would be
reduced by 50 to 1, SOX emissions would be reduced by 20 to
1, and CO2 emissions would be reduced by 5 to 1. The
commenter also notes that ash in the coal is melted in the gasification
process, and can be used as an aggregate for paving roadways. In
addition, the sulfur from the process can
[[Page 52410]]
be collected as elemental sulfur, and sold as a byproduct. Water
consumption would be reduced by about \1/2\ in comparison to a
conventional power plant of the same MW output, due to the use of a
hybrid cooling system (air-cooled condenser in conjunction with a
cooling tower).
The commenter points out that KinderMorgan has an existing
CO2 pipeline in the vicinity. The CO2 from the
plant could be sold to KinderMorgan and used for enhanced oil recovery.
A plant of this scale, according to the commenter, would cost
approximately $8 billion to construct, assuming all new equipment.
However, this cost could be substantially reduced by re-utilization of
much of the plant, including coal handling equipment, steam turbines,
condensers, cooling towers, and transmission lines. The re-utilization
of existing equipment could reduce the capital cost by an estimated 25
to 35% as compared to a totally new facility. The commenter suggests
this could be a BART (retrofit) solution. The commenter argues the
revenues from this plant would provide a return on investment that
exceeds all other considered options by a wide margin. The commenter
encourages us to consider conversion to a CTL plant with integrated
power generation to be BART for SJGS.
Response: We appreciate the commenter's suggestion that we consider
CTL technology with integrated power generation as an option in
determining NOX BART for the SJGS. Although we encourage PNM
and the other owners of the SJGS, and the Navajo Nation to examine this
concept in detail, we cannot consider it as a potential NOX
BART technology as it would involve a complete redesign of the plant.
We note the BART guidelines state that ``[w]e do not consider BART as a
requirement to redesign the source when considering available control
alternatives.'' \60\
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\60\ 70 FR 39104, 39164.
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We agree with the commenter that the NOX BART
determination in our proposal would reduce NOX emissions,
yet would do little to reduce SO2 and CO2
emissions from the SJGS. SO2 emissions under the RHR are
covered by the New Mexico submittal, which we received on July 5, 2011.
We will address the adequacy of that submission in a future action. As
discussed in our proposal, we disagree with PNM's cost estimate for
installing SCR on the four units of the SJGS. Although PNM estimated
the total cost to be in excess of $900 million, we estimated that cost
to be approximately $250 million. As discussed elsewhere in our
response to comments, in light of information provided by commenters,
we have refined our estimate to be $344,542,604. We note that this
estimate, being about one-third that of PNM's, will result in
significantly lower costs being passed on to rate payers than what has
been estimated by PNM.
G. Comments on Health and Ecosystem Benefits, and Other Pollutants
Comment: Several conservation organizations jointly submitted a
comment letter pointing out that the same pollutants that contribute to
visibility impairment also harm public health and have negative
ecosystem impacts. They note that these same pollutants also harm
terrestrial and aquatic plants and animals, soil health, and moving and
stationary bodies of water by contributing to acid rain, ozone
formation, and nitrogen deposition. Another commenter, a retired
pediatrician, notes that NOX as a precursor to ozone, causes
numerous respiratory problems and adversely affects children in
particular; he supports our action. Another commenter urges us to take
into consideration the health impacts of toxic emissions from the SJGS.
Two commenters state there are high levels of mercury pollution
originating from the SJGS. A commenter also points out that nitrous
oxide (N2O) is a greenhouse gas (GHG) that contributes to
climate change. According to the commenter, PNM has accumulated many
air quality violations, and no amount of money is worth the poisoning
of our air, water, and soil. Another commenter points out that a recent
study of the 2010 health impacts of the SJGS estimated 33 deaths, 50
heart attacks, 600 asthma attacks, and over 30 hospital admissions,
resulting in an estimated $255 million in health care costs in 2010. A
commenter also expresses concern that if EPA lowers the ozone standard
in 2011, La Plata County, CO, would not be attaining the standard.
Response: We appreciate the commenters' concerns regarding the
negative health impacts of emissions from the SJGS. We agree that the
same PM2.5 emissions that cause visibility impairment can be
inhaled deep into lungs, which can cause respiratory problems,
decreased lung function, aggravated asthma, bronchitis, and premature
death. We also agree that the same NOX emissions that cause
visibility impairment also contribute to the formation of ground-level
ozone, which has been linked with respiratory problems, aggravated
asthma, and even permanent lung damage. We agree that these pollutants
can have negative impacts on plants and ecosystems, damaging plants,
trees, and other vegetation, and reducing forest growth and crop
yields, which could have a negative effect on species diversity in
ecosystems. Therefore, although our action concerns visibility
impairment, we note the potential for significant improvements in human
health and the ecosystem.
Although we appreciate the commenter's concern regarding the
negative health impacts of toxic emissions from the SJGS, we note that
toxic emissions are not considered to be visibility impairing
pollutants. Similarly, Mercury is not a visibility impairing
pollutant,. N2O--a GHG--does not belong to the
NOX family, nor is it considered a visibility impairing
pollutant.
Comment: One commenter states that power plants are responsible for
approximately one-quarter of the NOX emitted in the U.S.
each year, and therefore urges us to adopt a plan with stricter
standards to regulate the toxic air emissions from the SJGS to protect
public health, decrease emergency room visits and asthma. According to
the commenter, the SJGS is one of the greatest NOX polluters
in the nation, contributing to the formation of harmful particulate
matter, ground level ozone smog, and acid rain.
Response: We appreciate the commenters' concerns regarding the
NOX emissions from power plants such as the SJGS. We agree
that these emissions are detrimental to human health and the
environment, with NOX being a precursor to ground-level
ozone and also leading to the formation of acid rain. Although we
appreciate the commenter's encouragement that we adopt even stricter
standards, after considering all the comments we received, as we have
stated elsewhere in this notice, we believe that the standards proposed
in our proposal establish BART and will prevent visibility impairment
from the SJGS.
H. Miscellaneous Comments
Comment: A commenter stated that it is appropriate and necessary
for us to promulgate a FIP that addresses interstate transport of air
pollutants from New Mexico, pointing out that the SJGS is located a
short distance from several state boundaries. They also state we should
have presented a clearer explanation of the events that have taken
place related to New Mexico's work on the SIP in the 2003-2010
timeframe. The commenter believes including more detail in the
background section of the proposal about the
[[Page 52411]]
intermediate actions taken by us and NMED in the given timeframe in
regards to New Mexico's SIP would have added clarity for the public.
Response: We believe the level of detail we included in the
``Background'' section of our proposal is appropriate and sufficient to
give the public a clear picture of the events leading up to our
proposal. In particular, the subsection titled Statutory and Regulatory
Framework Addressing Interstate Transport and Visibility provides
detailed information to give the public a clear picture of what we
received from New Mexico in terms of the RH SIP and the Interstate
Transport SIP.
Comment: A commenter is concerned with degradation of visibility in
Mesa Verde National Park over the last decade. The commenter believes
that in the Interstate Transport SIP we received on September 17, 2007,
New Mexico's statement that no sources in New Mexico impact the
protection of visibility in neighboring states seems to be unsupported
by the evidence presented by NMED.
Response: We note that it appears that the commenter may have a
misconception of what NMED submitted in terms of the Interstate
Transport SIP. As explained in our proposal, we received a SIP from New
Mexico to address the interstate transport provisions of CAA section
110(a)(2)(D)(i) for the 1997 8-hour ozone and PM2.5 NAAQS on
September 17, 2007. New Mexico did not state in this Interstate
Transport SIP that no sources in New Mexico impact the protection of
visibility in neighboring states. Instead, New Mexico's Interstate
Transport SIP stated that the requirement under section
110(a)(2)(D)(i)(II) that the state not interfere with the visibility
programs of other states would be addressed by the submittal of a RH
SIP by December 2007. As we state elsewhere in our response to comments
and in our proposal, because New Mexico had not submitted a RH SIP or
an alternative means of demonstrating that emissions from its sources
would not interfere with the visibility programs of other States at the
time of our proposal, we proposed disapproval of the September 17, 2007
SIP, and proposed a FIP to fill that gap. We are now finalizing our
proposed FIP to ensure that emissions from New Mexico do not interfere
with the visibility programs of other States. We received New Mexico's
RH SIP under section 51.309 on July 5, 2011, long after statutory and
regulatory deadlines. We will review that submission, and address it in
a future action.
Comment: A commenter generally agrees with our proposed
determination that all the air pollution sources in New Mexico are
achieving the emission levels assumed by the WRAP modeling except for
the SJGS, but would like to know what data and modeling supports it.
Response: We based our conclusion that all sources in New Mexico
are achieving the emission levels assumed by the WRAP in its modeling
except for the SJGS by reviewing the WRAP photochemical modeling
emission projections used in the demonstration of reasonable progress
towards natural visibility conditions and comparing these emission
projections to current emission levels from sources in New Mexico.
Comment: A commenter stated that there must be balance in the
proposals and regulations that are presented by the federal and state
governments. The commenter indicated that although this is an issue of
visibility, he is sure we have somehow taken health impacts into
consideration in formulating our proposal. The commenter also expressed
his belief that our proposal is counter-productive and has a better
than average potential to harm the local and state economies. The
commenter stated that the technology we are proposing is costly and
seems unnecessary, as PNM recently completed a project that put it in
compliance with all current health requirements, and only considers
visibility in the surrounding national parks and wilderness areas while
ignoring the economic impact to the local community. The commenter
expressed his belief that cost estimates from the private sector tend
to be more accurate than government estimates. The commenter stated
that our proposal calls into question the continued viability of the
SJGS as an asset to the Public Service Company of New Mexico. The
commenter stated that this is not an issue that requires emergency
action, and suggests allowing tomorrow's technology provide a solution
to today's problems.
Response: We understand the commenter's concern regarding the need
for balance in the regulations promulgated by state and federal
governments. This decision is based on the RH requirements of the CAA.
We have not relied on any potential health impacts in reaching our
decision, although we note the potential for significant improvements
in public health. The SJGS is one of the largest sources of
NOX in the western U.S. and is within 300 kilometers of 16
Class I areas. Finalizing our proposal is necessary to satisfy CAA
requirements, including section 110(a)(2)(D)(i)(II) with respect to
preventing emissions from New Mexico sources from interfering with
other states' measures to protect visibility. As previously stated, we
have an obligation to promulgate a FIP to address the requirements of
section 110(a)(2)(D)(i) with respect to visibility and a FIP to address
the requirements of RH. The purposes and requirements of these programs
are intertwined. As such, we consider it appropriate to promulgate one
FIP that addresses the requirements of section 110(a)(2)(D)(i) with
respect to visibility and the BART requirements for NOX for
SJGS.
We disagree with the commenter's belief that our proposal is
counter-productive. As presented in our proposal, our modeling analysis
demonstrates significant visibility improvement at numerous Class I
areas from installation of SCR at the SJGS. As we discuss elsewhere in
our response to comments, our estimate of the cost of installing SCR is
approximately \1/3\ what PNM estimated. Regarding the commenter's
belief that the technology we proposed seems unnecessary since PNM
recently completed a project that ``put it in compliance with all
current health requirements,'' we note that as part of our visibility
impairment and BART evaluation, we did consider the controls previously
installed by PNM as a result of its consent decree with the Grand
Canyon Trust, Sierra Club, and NMED on March 10, 2005. These controls
included the installation of low-NOX burners with overfire
air ports, a neural network system, and a pulse jet fabric filter.
However, as we discuss elsewhere in our response to comments, these
controls were not sufficient to prevent New Mexico sources from
interfering with measures required in the SIP of any other state to
protect visibility, pursuant to section 110(a)(2)(D)(i)(II) of the CAA.
The reduction in NOX from our NOX BART
determination and the SO2 emission limits will serve to
ensure there are enforceable mechanisms in place to prohibit New Mexico
NOX and SO2 emissions from interfering with
efforts to protect visibility in other states. In addition, the RHR
requires us to examine additional retrofit technologies. We have
determined that SCR is cost effective and results in significant
visibility improvements at a number of Class I areas, over and above
the existing pollution controls currently installed. With regard to the
commenter's belief that cost estimates from the private sector tend to
be more accurate than government estimates, we note that we take our
duty to estimate the cost of controls very seriously and
[[Page 52412]]
make every attempt to make a thoughtful and well-informed
determination. With regard to the commenter's belief that this is not
an issue that requires emergency action and that we should allow
tomorrow's technology provide a solution to today's problems, we note
that Congress added the BART requirements to the CAA in 1977 to focus
attention on the visibility impacts from sources such as SJGS. We
therefore believe it is appropriate to take action now, and our FIP is
necessary to satisfy the requirements of CAA section
110(a)(2)(D)(i)(II) with respect to visibility for the 1997 8-hour
ozone standard and the 1997 PM2.5 standard, and to satisfy certain
related RH requirements. We also note that as described elsewhere in
this preamble, New Mexico has only recently submitted a RH plan that
addresses the interstate provisions of the CAA with respect to
visibility, and as also explained we cannot review it as part of this
action. The FIP clocks of both statutory requirements have expired and
we therefore have an obligation to act now under the CAA.
Comment: An owner participant of Units 1 and 2 at the SJGS
indicates that our proposal presents significant challenges and risks
to its resource planning by handicapping its ability to cost
effectively respond to changing conditions. The commenter states that
uncertainties such as the impact of potential future regulations,
future fuel prices, and customer load growth/decline, have the
potential to change the economic viability of their generating
resources. The commenter points out that implementation of our proposal
would require it to make a significant capital investment in the plant,
the cost of which could only be recovered through long-term operation
of that asset. This would likely have the effect of ``locking'' SJGS
into the generation portfolio for a considerable period of time or risk
stranding those investments. According to the commenter, this loss of
flexibility would hamper its ability to respond to future scenarios
such as changes in the economic viability of coal resources, changes in
acceptance of coal resources by State utility commissions, and reduced
demand for coal resources. The commenter states that this loss of
flexibility is completely unnecessary given that the RH program is
intended to make gradual reductions in emissions over a decades-long
period of time. The commenter asks us to recognize the significant
reductions already made at SJGS or to defer to the SIP submitted by
NMED to the Environmental Improvement Board. The commenter suggests
that further reductions could be made at the plant, including the
possible installation of SCR, over subsequent planning periods. Such an
approach would reduce the immediate financial burden on the power
plant's customers, allow time for greater certainty in terms of
potential carbon limits and customer demand, and retain greater
flexibility in future resource decisions.
Response: Regarding costs, EPA reevaluated projections based on
comments received to increase them to $344,542,604, which is still much
less than industry projections and cost effective. Cost is one of the
five factors considered in making BART determinations.\61\ Regarding
the utility's loss of flexibility, the emission limits we select today
are the result of a schedule in the 1977 Clean Air Act to make gradual
reductions in emissions over a decades-long period of time
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\61\ States must consider the following factors in making BART
determinations: (1) The costs of compliance; (2) the energy and
nonair quality environmental impacts of compliance; (3) any existing
pollution control technology in use at the source; (4) the remaining
useful life of the source; and (5) the degree of improvement in
visibility which may reasonably be anticipated to result from the
use of such technology. 40 CFR 51.308(e)(1)(ii)(A).
---------------------------------------------------------------------------
With regard to the commenter's request that we recognize the
emissions reductions already made at SJGS or to defer to the SIP
recently that was submitted by NMED to the Environmental Improvement
Board near the time of the comment, we note that as part of our
NOX BART evaluation for SJGS, we did consider the controls
previously installed by PNM as a result of its consent decree with the
Grand Canyon Trust, Sierra Club, and NMED on March 10, 2005. However,
in making the NOX BART determination, we were obligated by
the RHR to examine additional retrofit technologies. EPA will give
priority to the review of New Mexico's recently submitted Haze SIP;
however, it was received too late to be taken into consideration in
this rule making.
Comment: The Navajo Nation submitted comments stating that the
Navajo Nation Environmental Protection Agency is concerned that non-air
quality impacts have not been adequately considered in the proposed
rule. The commenter states that 20% of the plant workers at the SJGS
and 41% of the mine workforce at the San Juan Mine are Navajo Nation
tribal members. The commenter is concerned that we have provided no
information or analyses to explain how the SJGS will fund the SCR
installation costs within the limited timeframe without resorting to a
reduction-in-force that would potentially impact Navajo workers,
contractors, and subcontractors.
Response: Because SJGS has not proposed to shut down, we do not
believe that jobs at the facility will be threatened. EPA's decision to
lengthen the compliance deadline from 3 to 5 years should also provide
some increases in local employment during that time associated with the
installation of pollution controls. The RHR requires that the costs of
compliance and the non-air quality environmental impacts of compliance
be considered [40 CFR 51.308(e)(1)(ii)(A)]. As described in our
proposal, we found that PNM did not identify any significant or unusual
environmental impacts associated with the control alternatives that had
the potential to affect the selection or elimination of that control
alternative. For SCR and SCR/SNCR hybrid technologies, the non-air
quality environmental impacts EPA evaluated included the consideration
of water usage and waste generated from each control technology.
Comment: A commenter argues that things like wood burning stoves,
wood burning fireplaces, and natural occurrences such as dust, wind,
fires, and humidity, impair visibility just as much as utilities. The
commenter asks us to explain how we propose to control those events
that affect air quality.
Response: Natural haze factors are recognized in the current degree
of visibility impairment in Class 1 areas. The purpose of this decision
is to significantly decrease impairment from the largest man made
sources. In addition, the emissions resulting from wood burning stoves
and fireplaces are typically included in the emission inventory, which
is part of the RH SIP New Mexico recently submitted to us under 40 CFR
51.309. We will review the adequacy of this SIP submission in a
separate future proposal.
Comment: The commenter asks us to explain how we intend to analyze
the cost benefits to businesses and individuals.
Response: The CAA requires us to consider the cost of installing
controls and the visibility benefits as part of the BART analysis, and
we have done that. The commenter may wish to consult the Statutory and
Executive Orders Review section of this action, which includes our
determination that the FIP does not contain a Federal mandate that may
result in expenditures that exceed the inflation-adjusted Unfunded
Mandates Reform Act of 1995 (UMRA) threshold of $100 million by State,
local, or Tribal
[[Page 52413]]
governments or the private sector in any 1 year.
I. Comments in Favor of Our Proposal
Comment: Overall, we received more than 12,000 comment letters in
support of our rulemaking from members representing states, tribes,
local governments, various organizations and concerned citizens in
support of this rulemaking: These comments were received at the Public
Hearing in Farmington, New Mexico, by Internet, and through the mail.
Each of these commenters was generally in favor of our proposed
decision for the SJGS. These comments include urging us to require
appropriate retrofit technology at the SJGS for emission control, and
limiting NOX, SO2, sulfuric acid and ammonia
currently or potentially released by the facility. A number of
representative comments from this group are summarized below. The
Complete Response to Comments for NM Regional Haze/Visibility Transport
FIP document includes the full text received by these commenters.
We received many letters which were similar in content and format,
and are represented by thirteen types of positive comment letters in
the docket for this rulemaking. Each of these comment letters supports
our proposed decision for the San Juan Generation Station in New
Mexico. More than 7,000 of these letters specifically urge us to keep
or lower our proposed numeric limits on nitrogen oxides, ammonia, and
sulfuric acid pollution in our final decision and urge us to require
compliance with the limits within three years.
We received a letter from the State of Colorado in support of this
rulemaking. These comments include support for our careful evaluation
of NOX emission control costs for the SJGS, and our proposed
promulgation of cost effective emission control for this facility to
improve visibility and provide other environmental benefits. The State
of Colorado also encouraged us to work closely with the State of New
Mexico in selecting the most appropriate NOX control
technology.
We received a letter from the Southern Ute Indian Tribe in support
of this rulemaking. The Tribe's comments include support for our
proposed action to prevent emissions from New Mexico sources from
interfering with other state's measures to protect visibility, and to
implement NOX and SO2 emissions limits at the
SJGS to prevent interference. In addition, the Tribe supports our
proposal to regulate emissions sources in neighboring areas that could
undermine the Tribes' efforts to maintain air quality on the
Reservation. The Tribe is concerned about the impacts of emissions from
SJGS on visibility on the Reservation; therefore the Tribe is in favor
of reducing the regional transport of ozone and ozone precursors such
as NOX.
We received two resolutions which generally support this
rulemaking, one from the City of Durango, Colorado, and another from
the Town of Ignacio Colorado. These resolutions include support for
requiring the use of BART at the San Juan Generating Station.
Another commenter expressed support of our proposal. The commenter
states that for the past 30-40 years, the SJGS has had a largely
unrestricted use of the large common air-shed shared by Montezuma
County, Colorado and San Juan County, New Mexico. During this
timeframe, the residents of Montezuma County and their neighbors have
been continually exposed to the air pollution arising from the SJGS,
yet the residents of Montezuma County receive no benefit from operation
of the plant in terms of electricity (aside from 40 MW purchased from
SJGS), tax revenues, and community support.
Another commenter supported all aspects of our proposed rule. The
commenter volunteers at Mesa Verde National Park and mentions that many
park visitors express disappointment over the degraded air quality and
limited vistas from the Park. The commenter states that the 2.88
deciview of visibility improvement we predicted at Mesa Verde National
Park with SCR installed at SJGS, would be readily noticed by both
residents and visitors to the region. The commenter notes that PNM's
Web site claims that SCR is ``unnecessary'' and would ``raise
electricity prices for the SJGS's two million customers,'' yet PNM
offers no data or other support for its conclusion. The commenter also
notes that no significant improvement in Four Corners RH has been seen
since PNM completed installation of emission controls pursuant to the
2009 consent decree. The commenter also states that it is legally,
socially, and economically appropriate for PNM's customers to pay the
full costs of the power they consume, including the air pollution
created while generating it. The commenter also states that although
PNM characterizes the SJGS as a ``low cost'' producer of power, it
fails to acknowledge that a substantial cost of its power, in the form
of regional air quality degradation, is borne by the people of the Four
Corners region, many of whom do not consume SJGS power and derive no
economic benefit from the facility. The commenter believes a three-year
implementation schedule for SCR at the SJGS is both appropriate and
achievable at a reasonable cost.
Response: We note that several of the specific emissions and
timeframe limitations supported by these commenters in the proposal
have been modified slightly in this final action based on all of the
information received during the comment period. Please see the docket
associated with this action for additional detail.
J. Comments Arguing Our Proposal Would Hurt the Economy and/or Raise
Electricity Rates
Comment: A commenter stated that if the FIP is adopted, the owners
of the SJGS will have three options: compliance, plant shutdown, or
plant modification. The commenter states that compliance would result
in a capital expense not justified by the likely results of that
investment, and would be a terrible, indefensible waste of resources.
Plant shutdown would result in the loss of hundreds of jobs in direct
plant employment, coal mining, and other support and service sectors.
The commenter also points out that plant shutdown would result in the
SJGS customers losing their investment in the plant, which they have
paid for through rate payment. SJGS customers would have to pay for the
development of new generation facilities and fuel contracts or would
have to buy power on the open market, and they would also be
responsible for the reclamation of the plant site and any coal mine
that might be abandoned as a result of plant closure. The commenter
states that plant modification would likely take the form of conversion
from coal-fired to natural gas-fired, which would also result in loss
of jobs, as there would be no need for coal. The commenter indicates
that all three options would result in an increase in the cost of
electricity to customers, which should be avoided or eliminated in
light of the weakened and unstable economic conditions at the national,
state, and local levels.
Another part owner of Unit 4 at the SJGS, submitted comments
stating that the impact from imposing its share of the costs of
installing SCR at the SJGS, may require it to raise electric rates, cut
back on planned clean energy investments, or both, all for what appear
to be insignificant benefits.
Response: EPA's evaluation of capital expenses by the
implementation of the FIP shows them to be justified by the degree of
improvement in visibility in relationship to the cost of
implementation. The FIP calls for NOX and SO2
emission limits at the SJGS to prevent interference with other states'
visibility SIPs as well as requiring BART
[[Page 52414]]
for NOX at this source. BART requires that we evaluate (1)
cost of compliance, (2) the energy and non-air quality environmental
impacts of compliance, (3) any existing pollution control technology in
use at the source, (4) remaining useful life of source, and (5) degree
of improvement in visibility which may reasonably be anticipated to
result from the use of such technology.
After careful cost review EPA has determined that the significant
benefits in visibility resulting from the implementation of the FIP
outweigh the increase in costs for the facility.
K. Comments Arguing Our Proposal Would Help the Economy
Comment: We received several comments stating that the proposed FIP
would help local economies by creating new and different jobs in the
Region and by increasing tourism. In particular, one commenter stated
reducing visibility-causing pollutants have far-reaching impacts on
local economies, human health, and ecosystems. The commenter stated
that decreasing these pollutants will benefit all of these important
areas of concern. This commenter noted that tourism is critical to the
economy of New Mexico and the Four Corners region, and made several
points: Utah's five Class I areas, all of which are national parks,
generate a significant portion of this sustainable tourism economy: in
2008, these areas were responsible for 5.7 million recreation visits,
over $400 million in spending, and nearly 9,000 jobs. Parks attract
businesses and individuals to the local area, resulting in economic
growth in areas near parks that is an average of 1 percent per year
greater than statewide rates over the past three decades. National
parks also generate more than four dollars in value to the public for
every tax dollar invested. Therefore, this commenter concluded,
improving visibility at these national parks improves the local
economies around them.
This commenter also noted that an additional economic incentive
behind protecting air quality is the necessary investment in pollution
control technologies as they are a job-creating mechanism in itself.
Each installation creates short-term construction jobs as well as
permanent operations and management positions.
Response: We agree with the comments. Although we did not consider
the potential positive benefits to local economies in making our
decision today, we do expect that improved visibility would have a
positive impact on tourism-dependent local economies. Also,
retrofitting the SJGS with SCR is a large construction project that we
expect to take 3 to 5 years to complete. This project will require
well-paid, skilled labor which can potentially be drawn from the local
area, which would seem to benefit the economy.
L. Comments Requesting an Extension to the Public Comment Period
Comment: We received comments requesting that the comment period be
extended, with most requesting an additional 60 days. We also received
comments requesting additional public hearings.
Response: Originally the comment period for our proposal was due to
close on March 7, 2011. In response to requests we extended the public
comment period to April 4, 2011. In doing so, we took into
consideration how an extension might affect our ability to consider
comments received on the proposed action and still comply with the
terms of a consent decree we have with WildEarth Guardians.\62\ We do
note that our February 17, 2011, public hearing in Farmington, New
Mexico was well attended and provided an opportunity for people to
comment on our proposal.
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\62\ WildEarth Guardians v. Lisa Jackson, Case No. 4:09-CV-
02453-CW.
---------------------------------------------------------------------------
M. Comments Requesting We Defer Action in Favor of a New Mexico SIP
Submittal
Comment: Various commenters have stated that the NMED should take
the lead in implementing the RH requirements of the CAA based on the
fundamental principle that the CAA and the RHR emphasize that states,
not EPA, are to take the lead in implementing the RH program, and we
should wait taking action until NMED submits to the Agency their
revised RH SIP and adopt such submittal instead of promulgating a FIP.
Response: Congress crafted the CAA to provide for States to take
the lead for implementing plans, but balanced that decision by
requiring EPA to approve the plans or prescribe a federal plan should
the State plan be inadequate. Our action today is consistent with the
statute. As explained in our proposal, we received a SIP from New
Mexico to address the interstate transport provisions of CAA section
110(a)(2)(D)(i) for the 1997 8-hour ozone and PM2.5 NAAQS on
September 17, 2007. New Mexico's September 17, 2007 submittal addressed
the requirement that the state not interfere with the visibility
programs of other states by stating that it would submit a RH SIP by
December 2007.
On January 15, 2009, EPA published a ``Finding of Failure to Submit
State Implementation Plans Required by the 1999 Regional Haze Rule.''
74 FR 2392. We found that New Mexico and other states had failed to
submit for our review and approval complete SIPs for improving
visibility in the nation's national parks and wilderness areas by the
required date of December 17, 2007. We found that New Mexico failed to
submit the plan elements required by 40 CFR 51.309(g), the reasonable
progress requirements for areas other than the 16 Class I areas covered
by the Grand Canyon Visibility Transport Commission Report. New Mexico
also failed to submit the plan element required by 40 CFR 51.309(d)(4),
which requires BART for stationary source emissions of NOX
and PM under either 40 CFR 51.308(e)(1) or 51.308(e)(2). This notice
initiated a 2-year deadline, referred to as the ``FIP clock,'' for New
Mexico to submit a SIP or for EPA to issue a FIP. The FIP would provide
the basic program requirements for each State that has not completed an
approved plan of their own by January 15, 2011. The CAA requires EPA to
promulgate a FIP if a State fails to make a required SIP submittal or
if we find that the State's submittal is incomplete, does not meet the
minimum criteria established in the CAA or we disapprove in whole or in
part the SIP submission. CAA section 110(c)(1).
In addition, WildEarth Guardians sued EPA alleging that we failed
to perform the non-discretionary duty to either approve a SIP or
promulgate a FIP for New Mexico, among other States, to satisfy the
requirements of CAA section 110(a)(2)(D)(i) with regard to the 1997
National Ambient Air Quality Standards for 8-hour ozone and fine
particulate matter. We have entered into a consent decree with
WildEarth Guardians to resolve this matter.
This consent decree specifically requires us--no later than August
5, 2011--to sign a notice either approving a SIP, promulgating a FIP,
or approving a SIP in part with promulgation of a partial FIP, for New
Mexico to meet the requirement of 42 U.S.C. 7410(a)(2)(D)(i)(II)
regarding interfering with measures in other states related to
protection of visibility. As required by the consent decree, since New
Mexico did not submit a complete proposed SIP to address the visibility
requirement by May 10, 2010, then by November 10, 2010, EPA was
required to propose one of three actions: A FIP; approval of a SIP (if
one has been submitted in the interim); or partial promulgation of a
[[Page 52415]]
FIP and partial approval of a SIP. In the absence of a SIP, EPA
proposed a FIP on January 5, 2011. We received the New Mexico submittal
on July 5, 2011,after the close of the record for the proposed FIP EPA
will give priority to the review of New Mexico's SIP but we cannot
consider it and meet the consent decree deadline.
N. Comments Generally Against Our Proposal
Comment: Various commenters generally stated they do not support
the proposed rulemaking. Their reasons included: It will affect the
town's economy, affect the coal power plant industry, electricity costs
will increase, they have no direct health problems from actual
emissions, direct and indirect jobs/businesses would be affected,
current air pollution control equipment meet EPA and health standards.
Others commented that our decision is arbitrary as no other similar
facilities have the same requirements imposed by the FIP and that there
will be no benefit to the community. One commenter argues that SJGS
already meets the visibility standards required by the CAA.
Response: While we appreciate the effort and time of the
commenters, the comments did not include documentation, rationale, or
data for EPA to respond beyond our responses provided elsewhere.
O. Comments on Legal Issues
1. EPA's Authority
Comment: Various commenters argued that combining Interstate
Transport and RH BART requirements in the proposed action exceeds our
authority and does not satisfy the regulatory requirements of each
program, and each program has different requirements and purposes.
Response: We do not agree that it exceeds our authority to combine
action on RH BART requirements as part of our action on the required
State submittal to meet section 110(a)(2)(D) of the CAA. EPA has two
separate sources of authority and obligations to take this action,
i.e., a statutory obligation to promulgate a FIP to meet the
requirements of section 110(a)(2)(D)(i)(II) and a statutory obligation
to promulgate a FIP to meet RH program requirements of the CAA. Nothing
in the CAA precludes EPA from addressing both requirements
simultaneously, and indeed, to address both in the same action is
rational to ensure the most efficient use of resources by both the
Agency and the affected source. The SJGS is subject to both provisions
of the CAA, and both provisions concern emissions of NOX
(among other pollutants). To separate our actions could potentially
lead to the same source needing to install two successive levels of
control measures, the first in order to meet the requirements of
section 110(a)(2)(D)(i), and then the second in order to meet the
requirements of the RH program.
The CAA requires each state to develop a SIP that provides for the
implementation, maintenance, and enforcement of the NAAQS. CAA section
110(a)(1). The statute explicitly requires that each state's SIP shall
include, among other things, adequate provisions prohibiting any source
from emitting any air pollutants in amounts which will interfere with
measures required to be included in the applicable implementation plan
for any other State to protect visibility. CAA section
110(a)(2)(D)(i)(II).
On April 25, 2005, we published a ``Finding of Failure to Submit
SIPs for Interstate Transport for the 8-hour Ozone and PM2.5
NAAQS.'' 70 FR 21147. This notice included a finding that New Mexico
and other states had failed to submit SIPs to address any of the four
prongs of section 110(a)(2)(D)(i), including the provisions relating to
interstate transport of air pollution affecting visibility, and started
a 2-year clock for us to promulgate a FIP, unless a State made a
submission to meet the requirements of section 110(a)(2)(D)(i) and we
approved the submission. CAA section 110(c)(1). That two year period
has expired.
The CAA also requires each state to develop a SIP to protect
visibility. CAA section 169. On January 15, 2009, we published a
``Finding of Failure to Submit State Implementation Plans Required by
the 1999 Regional Haze Rule.'' 74 FR 2392. In that notice we found that
New Mexico and other states had failed to submit complete SIPs for
improving visibility in the nation's national parks and wilderness
areas by the required date of December 17, 2007. Specifically, we found
that New Mexico failed to submit the plan elements required by 40 CFR
51.309(g), the reasonable progress requirements for areas other than
the 16 Class I areas covered by the Grand Canyon Visibility Transport
Commission Report. In addition, we also found that New Mexico had
failed to submit the plan element required by 40 CFR 51.309(d)(4),
which requires BART for stationary source emissions of NOX
and PM under either 40 CFR 51.308(e)(1) or 51.308(e)(2). This finding
of failure to submit started a 2-year clock for us to promulgate a FIP,
unless the State made a RH SIP submission and we approved it. That two
year period has also expired.
On September 17, 2007 we received a SIP from New Mexico to address
the interstate transport provisions of CAA 110(a)(2)(D)(i) for the 1997
8-hour ozone and PM2.5 NAAQS. In that submission, the state
indicated that it intended to meet the requirements of section
110(a)(2)(D)(i) with respect to visibility by submission of a timely RH
SIP. Those RH SIPs were due no later than December 17, 2007.
As of the time of our proposal for this action on January 5, 2011,
the state had not make the RH SIP submission as represented in its
section 110(a)(2)(D) submission, and had not make a RH SIP submission
or alternate section 110(a)(2)(D) submission indicating that the state
intended to meet visibility prong by any other means.
We received a RH SIP submittal from the state on July 5, 2011.
Unfortunately, due to the timing of that submittal, we cannot evaluate
it as part of this action. We note that this RH SIP submittal arrived
approximately 3\1/2\ years past the due date of December 17, 2007, and
well past January 15, 2011, the date by which we were obligated either
to approve a RH SIP submission or to promulgate a RH FIP, as a result
of the 2009 finding of failure to submit the RH SIP. Moreover, the July
5, 2011, submission also occurred more than four years after the date
by which we were obligated either to approve a SIP submission or to
promulgate a FIP to address the state's failure to submit a submission
for section 110(a)(2)(D)(i)(II).
We are under a consent decree deadline with WildEarth Guardians
that requires the Agency to take action by August 5, 2011, either to
approve the New Mexico section 110(a)(2)(D) SIP, or to promulgate a
FIP, to address the 110(a)(2)(D)(i)(II) visibility prong. Because of
the lateness of the July 5, 2011 submission, it is not possible to
review and potentially fully approve the July 5, 2011, SIP submission
by proposing a rulemaking and promulgating a final action by August 5,
2011, as required by the consent decree.
The CAA requires us to promulgate a FIP if a State fails to make a
required SIP submittal or if we find that the State's submittal is
incomplete, does not meet the minimum criteria established in the CAA
or we disapprove in whole or in part the SIP submission. CAA section
110(c)(1). As previously discussed, we have made findings related to
the New Mexico SIP submission needed to address interstate transport
and the requirement that emissions from New Mexico sources do
[[Page 52416]]
not interfere with measures required in the SIP of any other state to
protect visibility, pursuant to section 110(a)(2)(D)(i)(II) of the CAA.
Therefore, as New Mexico failed to submit an approvable SIP that
addresses the interstate provisions of the CAA with respect to
visibility, and has made a very late RH SIP submission giving us no
time to complete the regulatory process necessary to evaluate that
submission in light of the deadlines imposed by the above-mentioned
consent decree, we have the statutory authority and the obligation to
promulgate a FIP that meets one or both requirements.
In addition, we think that it is appropriate to take action on the
visibility requirements of section 110(a)(2)(D)(i)(II) and RH program
requirements simultaneously in these circumstances because the purposes
and requirements of the interstate transport provisions of the CAA with
respect to visibility and the RH program are intertwined. The
requirements of CAA section 110(a)(2)(D)(i)(II) explicitly provide that
states must have SIPs with adequate provisions to prevent inference
with the efforts of other states to protect visibility, which includes
the protections contemplated by the RH program. This section of the CAA
requires each SIP ``to include adequate provisions prohibiting any
source from emitting any air pollutants in amounts which will interfere
with measures required to be included in the applicable implementation
plan for any other State * * * to protect visibility.'' These required
SIP measures to protect visibility are set forth in sections 169A &
169B of the CAA and EPA's implementing regulations for the RH program.
Section 110(a)(2)(D)(i)(II) does not explicitly define what is
required in SIPs to prevent the prohibited impact on visibility in
other states. However, because the RH program requires measures that
must be included in SIPs specifically to protect visibility, EPA's 2006
Guidance \63\ recommended that RH SIP submissions meeting the
requirements of the visibility program could satisfy the requirements
of CAA section 110(a)(2)(D)(i)(II) with respect to visibility.
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\63\ See, ``Guidance for State Implementation Plan (SIP)
Submissions to Meet Current Outstanding Obligations Under Section
110(a)(2)(D)(i)for the 8-Hour Ozone and PM2.5 National
Ambient Air Quality Standards,'' from William T. Harnett, Director
Air Quality Policy Division, OAQPS, to Regional Air Division
Director, Regions I-X, dated August 15, 2006 (the ``2006
Guidance'').
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Subsequently, when some states did not make the RH SIP submission,
in whole or in part, or did not make an approvable RH SIP submission,
we have evaluated whether states could comply with section
110(a)(2)(D)(i)(II) by other means. Thus, we have elsewhere determined
that states may also be able to satisfy the requirements of CAA section
110(a)(2)(D)(i)(II) with something less than an approved RH SIP, see
e.g. Colorado (76 FR 22036 (April 20, 2011)) and Idaho (76 FR 36329
(June 22, 2011)). In other words, an approved RH SIP is not the only
possible means to satisfy the requirements of CAA section
110(a)(2)(D)(i)(II) with respect to visibility; however, such a SIP
could be sufficient. Given this reasoning, we do not agree with
commenters' contentions that the two programs have completely different
requirements and purposes and that it is unreasonable for EPA to seek
to address these issues in the same action.
Comment: Various commenters have stated that we proposed to act on
an interstate transport SIP requirement, while borrowing portions of
the RH SIP requirements, and that such partial implementation of
programs is inappropriate and conflicts with the structure and purpose
of the CAA.
Response: We disagree with the premise of the commenters that we
cannot address more than one statutory requirement in the same notice
and comment rulemaking. See response to comments, above, regarding our
general authority and obligation to act on section 110(a)(2)(D)(i)(II)
and RH SIP requirements. We also specifically disagree that acting on
portions of the RH SIP requirements in this action is inappropriate and
conflicts with the structure and purpose of the CAA. We have authority
to act on submissions, or portions of submissions, as appropriate to
meet the requirements of the CAA, in accordance with section 110(k)(3).
In this instance, we have determined that it is appropriate to take
action addressing the NOX BART requirements for an
individual source, and thereby to meet a portion of our outstanding
statutory FIP obligation for the RH program, at the same time as acting
on the section 110(a)(2)(D)(i)(II) SIP submission with respect to the
visibility prong to meet that statutory FIP obligation.
We note that we have previously acted on other portions of the
section 110(a)(2)(D)(i) SIP submission from the state. In prior
actions, we approved the New Mexico SIP submittal for: (1) The
``significant contribution to nonattainment'' prong of section
110(a)(2)(D)(i) (75 FR 33174, June 11, 2010); and (2) the ``interfere
with maintenance'' and ``interfere with measures to prevent significant
deterioration'' prongs of section 110(a)(2)(D)(i). (75 FR 72688,
November 26, 2010). Were it in fact ``inappropriate'' to act on
portions of SIP submissions, or were it contrary to the structure and
purpose of the CAA to do so, as the commenters argue, we would not have
taken such prior actions on portions of the state's section
110(a)(2)(D)(i) submission. Moreover, no one objected to those actions
on these grounds.
We also contend that promulgating FIPs to address specific CAA
requirements is consistent with the purposes of the statute. One of the
primary goals of the CAA is to protect and enhance the quality of the
Nation's air resources so as to promote the public health and welfare.
CAA section 101(b)(1). Failing to submit an approvable SIP submission,
as required by section 110 of CAA, is contrary to the purposes and
goals of the CAA. The CAA requires us to promulgate a FIP if a State
has failed to make a required submission or finds that a plan does not
satisfy the minimum established criteria, or disapproves a SIP
submission in whole or in part. CAA section 110(c)(1).
In this action, we are disapproving a portion of the New Mexico
Interstate Transport SIP with respect to the requirement that emissions
from New Mexico sources do not interfere with measures required in the
SIP of any other state to protect visibility. On September 17, 2007 we
received a SIP from New Mexico to address the interstate transport
provisions of CAA 110(a)(2)(D)(i) for the 1997 8-hour ozone and
PM2.5 NAAQS. In this submission, the state indicated that it
intended to meet the requirements of section 110(a)(2)(D)(i) with
respect to visibility by submission of a timely RH SIP. As previously
explained above, we received a RH SIP submission from the state on July
5, 2011. Because of the lateness of the submission, and in light of our
obligations under the WildEarth Guardians consent decree to have
completed rulemaking on the visibility prong of Section
110(a)(2)(D)(i), it is not possible to review such SIP submission,
propose a rulemaking, and promulgate a final action prior to the August
5, 2011 deadline.
Therefore, as previously stated, we have both a statutory
obligation to promulgate a FIP to address the requirements of section
110(a)(2)(D)(i) with respect to visibility and a statutory obligation
to promulgate a FIP to address the requirements of RH. As also
previously stated, the purposes and
[[Page 52417]]
requirements of these programs are intertwined. As such, we consider it
appropriate to promulgate one FIP that addresses both the requirements
of section 110(a)(2)(D)(i) with respect to visibility and the BART
requirements for NOX from SJGS. Although there are
additional RH SIP requirements to be addressed, and we intend to
address these requirements in the near future, there is no requirement
in the CAA that we take action to address a state's failure to submit
an approvable RH SIP in only one action.
Comment: Some commenters argued that the proposed FIP is too all
encompassing, exceeds the authority vested in EPA under Section 110 of
the CAA because it provides too stringent a control for attaining
visibility standards, and will have broader impact than the purpose of
the CAA to not interfere with neighboring state implementation plans.
Response: In general, for the reasons we have outlined elsewhere in
our responses to comments, we disagree that our FIP is too all
encompassing or exceeds our authority under section 110(a)(2)(D)(i) of
the CAA. Under that provision, we may not approve the SIP submission
from the state unless the SIP contains provisions adequate to prohibit
emissions from sources in that state from interfering with measures
required to protect visibility in other states. As explained in this
action, we have determined that emissions sources in New Mexico meet
this requirement, except for the SJGS. For this source, we have
determined that additional and federally enforceable controls are
required in order to meet the NOX emissions used in the WRAP
photochemical modeling and that federally enforceable emission limits
are required in order to meet the SO2 emissions used in the
WRAP photochemical modeling, as part of this action in order to be in
compliance with section 110(a)(2)(D)(i). Our action is also based in
part on our authority to address the NOX BART requirements
for the SJGS. To meet this separate requirement, we have determined
that specific NOX controls are required for the SJGS.
Comment: Various commenters argued that EPA failed to present ``a
coherent or defensible justification'' for its interpretation of
section 110(a)(2)(D)(i)(II) in the proposal, and that EPA failed to
explain adequately its interpretation of CAA section
110(a)(2)(D)(i)(II) and the relationship between that provision, as
interpreted by the Agency, and CAA sections 169A and 169B. In addition,
the commenter asserted that EPA has no basis to disapprove the state's
section 110(a)(2)(D) submission with respect to the visibility prong,
because the state's submission was consistent with EPA's 2006 guidance
to states for these SIP submission.
Response: We disagree with these assertions. First, in the proposal
we explained our views as to the proper interpretation of section
110(a)(2)(D)(i)(II). We explained that section 110(a)(2)(D(i)(II)
requires states ``to have a SIP, or submit a SIP revision, containing
provisions `prohibiting any source or other type of emissions activity
within the state from emitting any air pollutant in amounts which will
* * * interfere with measures required to be included in the applicable
implementation plan for any other State under part C [of the CAA] to
protect visibility. 76 FR 493 (January 5, 2011). We explicitly stated
that ``[b]ecause of the impacts on visibility from the interstate
transport of pollutants, we interpret the `good neighbor' provisions of
section 110 of the Act described above as requiring states to include
in their SIPs measures to prohibit emissions that would interfere with
the reasonable progress goals set to protect Class I areas in other
states.'' Id.
In the proposal, we expressed our view that section
110(a)(2)(D)(i)(II) ``does not explicitly specify how we should
ascertain whether a state's SIP contains adequate provisions to prevent
emissions from sources in that state from interfering with measures
required in another state to protect visibility'' Id. at 496. We
clearly stated that the statute is thus ambiguous and that the Agency
must interpret that provision in this action. Id. We are explaining our
reading of the ambiguity in the statute in this notice and comment
rulemaking.
Thereafter, we articulated in detail the underlying premise for our
2006 guidance, and the recommendations that states address this
requirement through submission of the RH SIP. We specifically explained
the basis for our belief that the development of those SIPs would
provide an appropriate forum in which states would have evaluated the
need for emission controls to protect visibility, and in particular
would have considered emissions from sources in other states and their
degree of control as part of developing their respective programs to
protect visibility. The proposal articulated our basis for proposing to
interpret the requirement of section 110(a)(2)(D)(i)(II) to mean that
the state's SIP must contain at least those emission reductions that
other states would have relied upon from New Mexico sources in the
development of their reasonable progress goals in their respective
visibility programs. Moreover, our proposal articulated that evaluation
of the analysis conducted by the WRAP is one means of gauging whether
New Mexico has adequately controlled its sources for this purpose.
We also disagree with the assertion that we have failed to explain
adequately our interpretation of the visibility prong of section
110(a)(2)(D)(i) in light of the requirements of section 169A and 169B
of the Act. As explained in our proposed action, the CAA establishes a
visibility protection program that sets forth ``as a national goal the
prevention of any future, and the remedying of any existing, impairment
of visibility in mandatory class I Federal areas which impairment
results from manmade air pollution.'' CAA section 169A(a)(1). In
section 169A(a)(1) of the 1977 Amendments to the CAA, Congress created
a program for protecting visibility in the nation's national parks and
wilderness areas. This section of the CAA establishes as a national
goal the ``prevention of any future, and the remedying of any existing,
impairment of visibility in mandatory Class I Federal areas which
impairment results from manmade air pollution.'' In 1980, we
promulgated regulations to address visibility impairment in Class I
areas that is ``reasonably attributable'' to a single source or small
group of sources, i.e., ``reasonably attributable visibility
impairment.'' 45 FR 80084 (December 2, 1980). These regulations
represented the first phase in addressing visibility impairment. We
deferred action on RH that emanates from a variety of sources until
monitoring, modeling and scientific knowledge about the relationships
between pollutants and visibility impairment were improved. Id.
Congress added section 169B to the CAA in 1990 to address RH
issues, and we promulgated regulations addressing RH in 1999. 64 FR
35714 (July 1, 1999), codified at 40 CFR part 51, subpart P (the RHR).
The RHR revised the existing visibility regulations to integrate
provisions addressing RH impairment and established a comprehensive
visibility protection program for Class I areas. The requirements for
RH, found at 40 CFR 51.308 and 51.309, are included in our visibility
protection regulations at 40 CFR 51.300-309. States were required to
submit the first SIP addressing RH visibility impairment no later than
December 17, 2007. 40 CFR 51.308(b).
We disagree with the argument that because section 169A and B
create a specific program for protection of visibility, that compels
the conclusion that section 110(a)(2)(D)(i)(I) could not
[[Page 52418]]
have any substantive bearing on this issue. Such an argument is at odds
with the clear provisions of the statute, and with the structure of the
CAA. Section 110(a)(2)(D)(i)(II) of the CAA requires that SIPs shall
include adequate provisions ``prohibiting * * * any source * * * within
the State from emitting any air pollutant in amounts which will * * *
interfere with measures required to be included in the applicable
implementation plan for any other State under part C * * * to protect
visibility.'' (Emphasis added). Because sections 169A and 169B
establish the national goal for visibility protection, including RH
issues, we infer that when Congress included protection of required
visibility programs in other states as part of section 110(a)(2)(D)(i),
it was a conscious reference to the sections in the CAA that address
that matter. Indeed, in section 110(a)(2)(D)(i)(II), Congress directed
us to prevent interference with the ``measures required to be included
in the applicable implementation plan for any other State under part C
of this chapter * * * to protect visibility,'' and the RH program is
unequivocally among those required measures to protect visibility.
Thus, it is reasonable for EPA to evaluate whether the SIP of a given
state prohibits emissions, consistent with what other states will have
developed their own visibility programs in reliance upon.
It is illogical to conclude that Congress would have explicitly
directed us to assure that state SIPs contain provisions to protect
visibility programs in other states, but that we not have the authority
to require such provisions as part of a section 110(a)(2)(D)(i)(II) SIP
submission, or if necessary to supply them as part of a FIP. Such an
argument is also clearly inconsistent with the other prongs of section
110(a)(2)(D)(i). The mere existence of other statutory programs to
provide for attainment and maintenance of the NAAQS required in part D
of the Act, does not negate the requirement that states also meet the
requirement of the ``significant contribution to nonattainment'' and
``interference with maintenance'' prongs of section 110(a)(2)(D)(i)(I),
and the authority of EPA to require substantive provisions in the SIP,
or to promulgate a FIP to provide them, as may be necessary. We have
exercised such authority and issued SIP calls or promulgated FIPs to
assure that state SIPs meet the requirements of section
110(a)(2)(D)(i).\64\ Because of the impacts on visibility from the
interstate transport of pollutants, we thus interpret the ``good
neighbor'' provisions of section 110 of the Act described above as
requiring states to include in their SIPs measures to prohibit
emissions that would interfere with the reasonable progress goals of
the RH program set to protect Class I areas in other states of the RH
program.
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\64\ See, e.g., ``Finding of Significant Contribution and
Rulemaking for Certain States in the Ozone Transport Assessment
Group Region for Purposes of Reducing Regional Transport of Ozone;
Final Rule,'' 63 FR 57356, October 27, 1998, (the NOx SIP Call).
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Finally, we disagree with the commenter's views concerning the
state's September 2007, submission complying with the Agency's 2006
guidance, and even if it had complied with that guidance, the purported
legal significance of that fact for purposes of this action. As the
commenters themselves conceded, the state's 2007 submission stated that
it would make a timely RH SIP submission by December of 2007 as its
intended means of meeting the requirements of section
110(a)(2)(D)(i)(II) for visibility, but due to intervening events the
state did not in fact do so prior to our proposed action. Contrary to
the commenter's views, that submission was not factually consistent
with the recommendations of the guidance.\65\
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\65\ Subsequent to the proposal for this action, and subsequent
to the commenter's comments, the state did make a RH SIP submission
on July 5, 2011, one month before we have to finalize rulemaking
either by promulgating a FIP or reviewing, proposing a rulemaking
and promulgating a final action fully approving the SIP, as required
by the August 5, 2011 consent decree deadline. Nevertheless, the
commenter was clearly in error given that there was no submission
purporting to meet the requirements of the RH program as of the time
of its comments.
---------------------------------------------------------------------------
More importantly, however, our 2006 guidance reflected our
recommendations for how states could potentially meet the section
110(a)(2)(D)(i)(II) requirement at that point in time. As of August
2006, we stated our belief that it was ``currently'' premature for
states to make a more substantive SIP submission for this element,
because of the anticipated imminent RH SIP submissions. We explicitly
stated that ``at this point in time'' in August of 2006, it was not
possible to assess whether emissions from sources in the state would
interfere with measures in the SIPs of other states. As subsequent
events have demonstrated, we were mistaken as to the assumption that
all states would submit RH SIPs in December of 2007 and mistaken as to
the assumption that all such submissions would meet applicable RH
program requirements and therefore be approved shortly thereafter. Thus
the premise of the 2006 Guidance that it would be appropriate to await
submission and approval of such RH SIPs before evaluating SIPs for
compliance with section 110(a)(2)(D)(i)(II) was in error. Our 2006
Guidance was clearly intended to make recommendations that were
relevant at that point in time, and subsequent events have rendered it
inappropriate in this specific action.
In short, we must act upon the state's submission in light of the
actual facts, and in light of the statutory requirements of section
110(a)(2)(D)(i). Whereas our prior recommendations were prospectively
anticipating the submission of the RH SIP as a means of the state
imposing the controls necessary on New Mexico sources necessary to
prevent interference with the required visibility programs of other
states, those recommendations are inappropriate at this juncture. In
order to evaluate whether the state's SIP currently in fact contains
provisions sufficient to prevent the prohibited impacts on the required
programs of other states, we are obligated to consider the current
circumstances and investigate the level of controls at New Mexico
sources and whether those controls are or are not sufficient to prevent
such impacts.
We similarly disagree with the commenters' argument that it is
still ``premature'' to evaluate the compliance of the state's SIP at
this time, and that we ``must await the date on which regional haze
SIPs have been submitted and approved.'' First, this approach is
illogical, as it fails to address what would happen if a state were
never to submit the required RH SIP, or were never to submit a RH SIP
that was approvable. On its face, the commenter's argument is simply
inconsistent with the objectives of the statute to protect visibility
programs in other states if a state never submits an approvable RH SIP.
Second, this approach is flatly inconsistent with the timing
requirements of section 110(a)(1) which specifies that SIP submissions
to address section 110(a)(2)(D)(i), including the visibility prong of
that section, must be made within three years after the promulgation of
a new or revised NAAQS. We acknowledge that there have been delays with
both RH SIP submissions by states and our actions on those RH SIP
submissions, but that fact does not support a reading of the statute
that overrides the timing requirements of the statute. We believe that
there are means available now to evaluate whether a state's section
110(a)(2)(d)(i)(II) SIP submission meets the substantive requirement
that it contain provisions to prohibit interference with the visibility
programs
[[Page 52419]]
of other states, and therefore that further delay, until all RH SIPs
are submitted and fully approved, is unwarranted and inconsistent with
the key objective to protect visibility.
Section 110(a)(2)(d)(i)(II) directs EPA to evaluate the SIP of a
state for adequate controls on emissions from the state to prevent
interference with measures ``required to be included in the applicable
state implementation plan'' of other states. Thus, this evaluation is
supposed to consider what other states should have in their SIPs as of
this point in time, and is not limited by the fact that other states
may or may not have made the required RH SIP submission, nor by the
fact that we may or may not have approved those RH SIP submissions at
this point in time. Instead, we must evaluate the state's section
110(a)(2)(D)(i)(II) submission in light of the programs that states are
required to have, and that clearly includes the RH program required in
other states. As discussed above, we believe that one means to evaluate
this issue is to determine whether the level of controls in the SIP are
consistent with the expectations for controls at New Mexico sources
relied upon by other states in the development of their own respective
visibility programs and consistent with the needs for emissions
reductions that we ourselves conclude are needed for purposes of the RH
program.
Comment: The proposed FIP requires exceedingly stringent and
expensive compliance obligations that are not adequately legally
supported because the proposed FIP fails to adequately satisfy the
interstate transport provisions of Section 110(a)(2)(D)(i) of the CAA
or the provisions of the RHR.
Response: We disagree that the FIP is not legally supported. The
FIP satisfies provisions in both section 110(a)(2)(D)(i)(II) of the CAA
regarding interstate transport of pollutants affecting visibility in
other states and for the NOX BART determination for the
SJGS, the RHR.
We find that the emissions from the SJGS in New Mexico are
interfering with the other states' required measures to protect
visibility. Therefore, we are imposing through the FIP, specific
emission limits upon the SJGS to prevent such interference. We are
imposing an SO2 limit and a NOX limit. To provide
greater certainty to the SJGS that controls needed to prevent
interference with other states' visibility programs, as well as the
controls needed to meet the RHR's BART requirements, do not conflict
with each other and end up imposing unnecessary greater costs upon the
SJGS, we are imposing a BART NOX emission limit that meets
both requirements at this time, rather than postponing action on this
RH SIP requirement. We are only determining that the SJGS is subject to
BART and promulgating the NOX BART FIP for the SJGS. We are
not addressing whether New Mexico has met the requirements of the RHR
for any other sources; we are not addressing whether the SJGS is
meeting the RH BART requirements for any other pollutants; and we will
address those requirements in later actions.
We have the specific authority to promulgate a FIP imposing a
NOX BART emission limitation upon the SJGS because we
previously found that New Mexico had failed to submit a complete RH SIP
by December 17, 2007. 74 FR 2392 (January 15, 2009). This finding
started a two year clock for the promulgation of a RH FIP by EPA or the
approval of a complete RH SIP from New Mexico. CAA section 110(c)(1).
The FIP obligation imposed upon us became effective on February 15,
2011. Part of that FIP obligation includes making a NOX BART
determination for the SJGS. To prevent a possible conflict between a
NOX visibility transport emission limitation FIP for the
SJGS and the NOX RH BART emission limitation FIP for the
SJGS, we chose to promulgate now, rather than later, the NOX
RH BART determination for the SJGS. We are combining the requirements
of section 110(a)(2)(D)(i)(II) for NOX with a NOX
BART evaluation (40 CFR 51.308) to be efficient and provide greater
certainty to the source as to the appropriate NOX controls
needed to meet those two separate but related requirements.
This FIP also will impose a federally enforceable limit on the
emissions of SO2 from the SJGS based upon the WRAP
determination of each member state's contribution to visibility
impairment of SO2 emissions, of which New Mexico is a
member. The SJGS's existing SO2 permit does not provide the
necessary emission limits and enforceable mechanisms to ensure the
SO2 emissions used in the WRAP photochemical modeling for
the SJGS units will be met. Therefore, we assumed the SO2
emission limit used in the WRAP modeling and, by this action, make it
enforceable. This is necessary to ensure that New Mexico sources do not
interfere with efforts to protect visibility in other states pursuant
to the requirements of section 110(a)(2)(D)(i)(II) of the CAA.
Comment: One commenter argued that EPA took too narrow an
interpretation of the term ``interfere'' in the visibility protection
context of Section 110(a)(2)(D)(i)(II) for New Mexico, and that EPA
should account for a broader range of causes of visibility impairment
when considering regulating interference with other states' visibility.
According to the commenter, EPA's action should consider future growth
in emissions from area sources such as oil and gas development as part
of evaluating interference with the visibility programs required in
other states' SIPs because the proposed New Mexico RH SIP already
reduces NOX emissions sufficiently. The commenter also
argued that pollutants other than NOX cause interference
with other states' visibility programs and should be considered instead
of reducing NOX emissions under BART because the commenter
believes NOX emissions contribute a minor portion to overall
visibility impairment.
Response: We disagree with the assertion that we took too narrow a
view of the term ``interfere'' in Section 110(a)(2)(D)(i)(II). In the
FIP proposed and finalized in this action, we are concluding that the
New Mexico SIP contains adequate provisions to prevent such impacts on
the visibility programs of other states, except for the emissions from
the SJGS. By promulgating a FIP to impose NOX and
SO2 emission limits necessary at the SJGS to prevent such
interference, as well as to meet the requirement for BART for
NOX for this same source, EPA is addressing the requirements
of the statute. In reaching this conclusion, we considered the term
``interfere'' based upon the facts, information, and data available to
the Agency at this time.
As we discuss in our proposal, we relied on WRAP modeling to
determine the appropriate emission limits for sources in New Mexico in
order to determine if New Mexico's emissions were interfering with
other state visibility SIPs. The states in the West, including New
Mexico, worked together through the WRAP to determine their
contribution to visibility impairment at the relevant Federal Class I
areas in the region and the emissions reductions from each State needed
to attain the reasonable progress goals for each area. Western states
are relying on the WRAP assumed reduction in emissions levels modeled
for sources in New Mexico including the SJGS in order to meet their RH
reasonable progress goals. All of the sources except for SJGS met the
WRAP assumed reduction in emissions levels modeled for New Mexico's
assigned contribution to the region's visibility impairment of Federal
class I areas. Thus, we proposed a FIP to prevent emissions from New
Mexico sources from interfering with other
[[Page 52420]]
states' measures to protect visibility, and to implement NOX
and SO2 emission limits necessary at one source, the SJGS,
to prevent such interference, as well as BART for NOX for
this source.
We determined that enacting a NOX BART determination for
SJGS was necessary because the WRAP analyses showed that NOX
emissions in general and SJGS NOX emissions, specifically,
contribute significantly to haze in the West. SJGS is by far the
largest source of NOX emissions in NM. Our FIP requires
substantial reductions in NOX emissions from this source. We
agree that oil and gas development can result in emissions that could
have an impact on visibility due to increases in NOX
emissions. However, we are basing our evaluation of the potential
impacts of emissions from New Mexico sources on the WRAP analysis, and
consideration of the sources that other states would have assumed that
New Mexico intended to control as part of that modeling. The state's
initial submission for section 110(a)(2)(D)(i) indicated that the state
intended to meet its obligations with respect to the visibility prong
by means of the RH SIP. Therefore, we have examined the issue in light
of what other states would have assumed such a SIP would achieve.
Moreover, even if the impacts from the oil and gas sector were
significant, this fact would not justify a decision to not act on the
BART requirements for NOX for the SJGS, because
NOX emissions from SJGS are a significant source of
NOX emissions that interfere with other state's required
visibility programs. In addition, based on the facts and information
currently available, we believe the most effective means of ensuring
that emissions from New Mexico do not interfere with other states'
visibility programs is to require further and federally enforceable
NOX reductions and federally enforceable SO2
limits at SJGS.
We also specifically disagree with the commenter's statement that
NOX emissions contribute only a minor portion to overall
visibility impairment. As we noted in our proposal, our modeling
indicates that the visibility impairment due to the SJGS's emissions is
primarily dominated by nitrate particulates. As our NOX BART
modeling demonstrates, reducing NOX emissions from the SJGS
will result in a 21.69 dv, cumulative improvement, across 16 Class I
areas. As the RHR states, ``States should consider a 1.0 deciview
change or more from an individual source to ``cause'' visibility
impairment, and a change of 0.5 deciviews to ``contribute'' to
impairment.'' \66\ Therefore, we do not view a cumulative visibility
impairment of 21.69 dv as an insignificant contribution. The commenter
suggests we consider future growth in emissions from area sources such
as oil and gas development as part of our control strategy. We agree
with the commenter that oil and gas activity in New Mexico produces
NOX and other emissions. We understand the WRAP is currently
reviewing and refining the emissions inventory for this sector. We will
address this matter further in our review of New Mexico's RH SIP.
---------------------------------------------------------------------------
\66\ 70 FR 39104, 39120.
---------------------------------------------------------------------------
2. BART Requirements
Comment: One commenter states ``EPA's BART determination for the
San Juan Generating Station contravenes EPA's rules and conflicts with
the structure and purpose of CAA Section 169A.'' Following this
comment, there appears a parenthetical ``see'' reference to comments
that had been submitted from two other commenters.
Response: The comment does not give any underlying rationale or
facts for its assertion that our action contravenes our rules and
conflicts with CAA Section 169A. We disagree with the statement,
because the NOX BART determination for the SJGS was made in
accordance with our rules and CAA requirements. The references to
subsections of other submitted comments do not appear to match with the
comments we had received. We cannot further evaluate or respond to this
comment. In any event, the other comments are separately addressed in
this document.
Comment: One commenter states that our proposed rule must be
withdrawn because it fails to justify implementation of a SCR BART
limit. This commenter cites to a portion of American Corn Growers v.
EPA, 291 F.3d 1, 19 (DC Cir. 2002), where the DC Circuit wrote of
state's having ``broad authority over BART determinations.'' The
commenter also points to that court's discussion of legislative
history, where it stated that ``* * * Congress intended the states to
decide which sources impair visibility and what BART controls should
apply to those sources.'' Id. at 8. From this, the commenter states
that the authority of states to establish BART cannot be constrained by
us.
Response: While a State has broad authority over a BART
determination when it is the decision maker, we similarly have broad
authority when promulgating a FIP. Because, as discussed earlier in
this notice, New Mexico did not timely formulate and submit its BART
determinations, we have the authority and responsibility to make a
NOX BART determination for SJGS.
Comment: One commenter argues that an evaluation of the amount of
reasonable progress expected to be achieved in the Class I areas by
other control measures is required before the amount of reasonable
progress needed from BART at the SJGS should be determined. Under the
CAA, BART is not expected to be the maximum degree of emissions
reduction technologically feasible. In fact, it may be lower if
reasonable progress from other CAA programs is sufficient.
Response: We believe BART to be a severable piece of the RHR that
can be evaluated on its own. BART can be a part of a reasonable
progress strategy, and controls imposed under other CAA requirements
can be considered to be BART. In fact, as we discuss elsewhere in our
response to comments, we did evaluate the existing controls at the
SJGS, but found them inadequate to satisfy NOX BART.
However, there is not any requirement in the RHR that would require we
first make an evaluation of reasonable progress prior to conducting a
BART evaluation, nor is there any consideration of lessening the degree
of a potential BART control in light of other CAA programs.
Comment: One commenter alleges our proposed rule improperly
requires BART for the San Juan Generating Station under Section 110 of
the CAA and not Section 169A. While we propose to act under the ``good
neighbor'' provision in Section 110 of the CAA, the commenter alleges,
EPA ``appears to selectively borrow'' the BART requirement from the RH
program established under Section 169A to do what ``neither section
could do alone.'' One commenter states Congress intended BART to be one
part of a ``comprehensive, long-term strategy for addressing RH in
Class I areas.'' The commenter asserts that BART is more stringent than
169A requires, because it is being used ``out of context'' in a limited
Section 110 program designed to ensure one state does not interfere
with another state's air quality plans. The commenter feels the
approach we use is a partial or piecemeal implementation of the RH
program, which is contrary to the integrated, comprehensive decision-
making that 169A envisions. Because requirements of Section 110 and the
Section 169A were not kept separate from each other, the commenter
feels our proposal is substantively and procedurally flawed and fails
to
[[Page 52421]]
properly implement the programs under both sections.
Response: We are not requiring NOX BART for the SJGS
under section 110 of the CAA. We are requiring NOX BART for
the SJGS under section 169A and the RHR. Further, we disagree with the
statement that BART requirements were selectively borrowed from the RH
program or that any provisions were selectively borrowed or considered
out of context. In making the BART determination, we first looked to
RHR requirements and determined SJGS is BART eligible for
NOX at each affected emissions unit. We then established
BART for those units under the RH Rule and the Guidelines for BART
Determinations found in Appendix Y of 40 CFR part 51. Because our BART
determination is in accordance with the guidelines, it is not any more
stringent due to the additional action under Section 110. Moreover, as
discussed elsewhere, we do not agree our determination is procedurally
or substantively flawed because it is not comprehensive enough. While
other commenters have suggested that we should proceed to determine
BART for other pollutants, we are finalizing a NOX BART
determination for the SJGS and will address other RH requirements in a
separate future action. Therefore, we do not agree that the action
under Section 110 and the determination under Section 169A have created
any conflict or flaw in the implementation of either program.
Comment: A commenter states that although a similar analytical
approach is appropriate, the outcome of the BART analysis for the SJGS
should differ from the proposed BART determination for the Four Corners
Power Plant. Commenter agrees that a consistent method of analysis
should apply. However, it disagrees that the outcomes of the analyses
must be the same, given the meaningful differences between the two
facilities. For example, the site congestion is a much greater concern
at the SJGS than at Four Corners. EPA should reconsider the emission
limit it assumed for San Juan in the site-specific, plant-wide manner
employed by Region 9.
Another commenter states the proposal fails to consider other BART-
eligible sources or other emission control strategies. In addition, the
commenter is concerned that our proposed FIP for the SJGS may have been
inappropriately influenced by the FIP proposed for Four Corners Power
Plant by Region 9. Although the overall analytical approach must be
consistent, the commenter argues, the final determinations should be
different to reflect the differences between those two facilities.
Response: We agree with the commenters that a consistent method of
analysis should apply for all BART evaluations, and we believe the use
of the BART Guidelines ensures that occurs. However, we see no reason
to conclude the outcomes of these analyses should be prejudged to
necessarily have any relationship to each other. We note that the
differences the first commenter mentions, such as existing pollution
control equipment and site congestion, were factored into our SJGS
NOX BART visibility modeling (baseline emissions) and cost
evaluation, respectively. Also, concerning the amount of review time
(e.g., comment period), our consent decree deadline prevents us from
extending the comment period more than we already have, which was
almost a month over our initial 60 day period. We disagree with the
first commenter that we failed to properly consider the NOX
emission limit the units of the SJGS can reliably attain. Elsewhere in
our response to comments, we present detailed information that
documents these units can reliably meet a NOX BART emission
limit of 0.05 lbs/MMBtu. In our analysis, we see no information in the
record that causes us to conclude there are any site specific issues
that would prevent the units of the SJGS from attaining this emission
limit. Lastly, as we discuss elsewhere in our response to comments, we
have modified the compliance schedule. We find that compliance with the
emission limits for the SJGS should be within 5 years of the effective
date of our final rule. We note that the compliance schedule for the
Four Corners Power Plant is now being analyzed under a ``better than
BART'' scenario according to section 51.308(e)(2)-(3), which provides
for a possibly longer time period for the installation of controls.\67\
---------------------------------------------------------------------------
\67\ Supplemental Proposed Rule of Source Specific Federal
Implementation Plan for Implementing Best Available Retrofit
Technology for Four Corners Power Plant: Navajo Nation, 76 FR 10530.
---------------------------------------------------------------------------
Comment: The proposed FIP for SJGS is entirely inconsistent with
the FIP proposed for six units in Oklahoma by EPA. Given the similarity
of the BART determinations made by the state of Oklahoma and the BART
determination prepared for San Juan by PNM's consultant, and the
significant difference between those determinations and EPA's proposed
FIP, commenter asks EPA to reconsider its BART analysis for SJGS using
the method of analysis applied in Oklahoma.
Response: We disagree that the results (e.g., emission limits and
controls) of our proposed NOX BART determinations for
Oklahoma \68\ and the NOX BART determination we proposed for
the SJGS should be similar. The cost of controls must be compared to
the expected visibility benefits, and those benefits from the potential
installation of SCR on sources in Oklahoma were predicted to be much
less than what we expect to result from the installation of SCR at the
SJGS. In fact, the visibility benefit (or lack thereof) from the
installation of SCRs on the Oklahoma BART sources is so small that we
did not see the need to refine the cost estimate by investigating the
feasibility of a lower NOX emission limit. Our conclusion in
no way implies we accepted the SCR cost estimate at face value--only
that we did not see the need to refine it. With regard to the different
BART compliance schedules between our proposals, we believed in SJGS's
case that the expected visibility benefits were so significant that the
controls should be installed ``as expeditiously as practicable.'' 40
CFR 51.308(e)(1)(iv). As we discuss elsewhere in our response to
comments, we have modified the compliance schedule. We are finalizing a
schedule which requires compliance with the emission limits within 5
years--rather than 3 years--from the effective date of our final rule.
---------------------------------------------------------------------------
\68\ Id.
---------------------------------------------------------------------------
Comment: Some commenters have stated that the proposed FIP does not
satisfy other requirements of the RH Program.
Response: We are acting on a portion of the State's SIP revision
addressing Interstate Transport requirements, specifically visibility.
We are not acting upon a state RH SIP submittal. The only RH
requirement on which we are acting is to make a NOX BART
determination for the SJGS and promulgate a NOX BART FIP for
the SJGS under the RHR. We have made clear in our proposal that we will
later act on the rest of the RH requirements.
Comment: One commenter states that the requirement to install SCR
at the SJGS is a fatally flawed and unnecessary approach to RH
reduction, and that the FIP is not consistent with the law, science,
economics, or prudent engineering practice.
Response: While we appreciate Commenter's general concern about the
control equipment for RH reduction, the Commenter did not provide any
specific examples in the record to be able to adequately respond to
this generalized statement. It should be noted that EPA's action
establishes emission limits that
[[Page 52422]]
may be met with SCR but it does not mandate specific control equipment.
Comment: A commenter states that our BART analysis should be only
about visibility and not public health concerns, which can be
misleading.
Response: We agree with the commenter that our action should be,
and in fact is, about protecting visibility. We derive our authority
for this action both under section 110(a)(2)(D)(i)(II) of the CAA and
the RHR. In so doing, although we do note the ancillary public health
benefits resulting from controlling the same pollutants that cause
visibility, we have not considered those benefits in arriving at our
decision.
3. Executive Orders Comments
Comment: The MSR Public Power Agency (MSR) disagrees with our
findings under the Unfunded Mandates Reform Act of 1995 that the
proposed FIP does not contain a federal mandate that may result in
expenditures by state, local, or tribal governments that exceed the
inflation-adjusted threshold of $100 million ($100 million in 1995
dollars) or more in any one year thus triggering a written assessment
of the costs and benefits of the proposed FIP. MSR believes that the
cost of retrofitting the four units at the SJGS is closer to PNM's
estimated cost of $908 million.
Response: The Unfunded Mandates Reform Act (UMRA) requires that
Federal agencies assess the effects of Federal regulations on State,
local, and tribal governments and the private sector. In particular,
UMRA requires that agencies prepare a written statement to accompany
any rulemaking that ``includes any Federal mandate that may result in
the expenditure by State, local, and tribal governments, in the
aggregate, or by the private sector, of $100,000,000 or more (annually
adjusted for inflation) in any one year'' (Section 202(a)). Our revised
cost estimate indicates that the Total Annual Cost is $39,265,670.\69\
Therefore, we have determined that we are below this threshold, even
without adjusting it for inflation. In other words, even if the entire
Total Annual Cost of the installation of SCRs on the units of the SJGS
were ascribed to one entity, we do not believe the UMRA threshold would
be triggered.
---------------------------------------------------------------------------
\69\ See Exhibit 1 RTC Revised Cost Analysis, lines 91, Cost
Analysis Fox.
---------------------------------------------------------------------------
Comment: Once commenter states that we should not ignore Executive
Order 12866.
Response: This action is not a ``significant regulatory action''
under the terms of Executive Order 12866, (58 FR 51735, October 4,
1993) as it only applies to one facility and is not a rule of general
applicability. Therefore, this action is not subject to review under
the Executive Order.
Comment: One commenter states that the proposed rulemaking is
contrary to Executive Order 13563 (Improving Regulation and Regulatory
Review) of January 18, 2011 and as such we should consider the cost of
promulgating the rule and take the least burdensome path among
different options.
Response: Executive Order 13563 is supplemental to and reaffirms
the principles, structures, and definitions governing contemporary
regulatory review that were established in Executive Order 12866 of
September 30, 1993. The President issued the referenced Order on
January 18, 2011, after we issued our proposed rulemaking. In general,
the Order seeks to ensure the regulatory process is based on the best
available science; allows for public participation and an open exchange
of ideas; promotes predictability and reduces uncertainty; identifies
and uses the best, most innovative, and least burdensome tools for
achieving regulatory ends; and takes into account benefits and costs,
both quantitative and qualitative. However, nothing in the Order shall
be construed to impair or otherwise affect the authority granted by law
to the Agency. Although this Order was issued after our proposed
rulemaking, in our review process the cost of compliance was one of the
elements addressed to ensure that the requirements to achieve the goals
stated in the CAA were beneficial and not burdensome to the regulated
entity. Please refer elsewhere in our response to comments for a
detailed analysis of the elements required by our regulations for BART
determinations.
Comment: The Navajo Nation EPA commented that the FIP proposal has
tribal implications as specified in Executive Order 13175, and that
consultation is required because of the impacts to Navajo workers,
contractors, and subcontractors at San Juan Generating Station and the
San Juan Mine.
Response: Executive Order 13175, entitled ``Consultation and
Coordination with Indian Tribal Governments'' (65 FR 67249, Nov. 9,
2000), relates to consultations with tribal governments by federal
agencies. As directed by the Executive Order, EPA has recently issued a
new policy entitled EPA Policy for Consultation and Coordination with
Indian Tribes (May 4, 2011), which re-establishes and clarifies EPA's
process for consulting with tribes. We have concluded that this final
rule does not have tribal implications, as specified in Executive Order
13175, because this action does not impose federally enforceable
emissions limitations on any source located on tribal lands, and
neither imposes substantial direct compliance costs on tribal
governments, nor preempts tribal law. However, in response to this
comment, we engaged in government-to-government consultation at the
request of the Navajo Nation regarding this rule and the Nation's
previously submitted comments.
4. Other General Legal Comments
Comment: A number of commenters have requested that we should
approve the New Mexico Interstate Transport SIP previously submitted in
2007 as it satisfies both our policy and our Consent Decree with
WildEarth Guardians. Another commenter states that we have no sound
basis in any event for disapproving New Mexico's SIP revision under the
visibility clause of section 110(a)(2)(D)(i)(II), as that SIP revision
simply carries out our own guidance to the states.
Another commenter stated that our proposal to adopt a FIP before NM
completes its ongoing rulemaking process to adopt a RH SIP is premature
and deprives the state of its significant discretion to establish and
administer its own RH program.
Response: We disagree that we should approve the SIP submitted in
2007 because it satisfies both our policy and the WEG Consent Decree.
Our consent decree with WEG requires that by August 5, 2011, we must
approve a SIP, promulgate a FIP, or approve a SIP in part with
promulgation of a partial FIP for New Mexico to meet the requirement of
section 110(a)(2)(D)(i)(II) regarding interfering with measures in
other states related to protection of visibility. As stated elsewhere
in this notice, New Mexico's 2007 submittal fails to meet this
requirement. That SIP anticipated the timely submission of a
substantive RH SIP, which was due by December 17, 2007, as the means of
meeting this requirement. Because until recently that RH SIP was not
submitted, we had no choice but to seek other means of satisfying our
WEG consent decree deadline of August 5, 2011.
Because states were late in their RH SIP submissions, on January
15, 2009, we published a ``Finding of Failure to Submit State
Implementation Plans Required by the 1999 regional haze rule.'' 74 FR
2392. In New Mexico's case, this finding included sections 40 CFR
51.309(g) and 40 CFR 51.309(d)(4). Section 51.309(d)(4)(vii) states
that the implementation plan must contain any
[[Page 52423]]
necessary long term strategies and BART requirements for stationary
source PM and NOX emissions. Any such BART provisions may be
submitted pursuant to either Sec. 51.308(e)(1) or Sec. 51.308(e)(2).
This finding started a 2-year clock, which expired on January 15,
2011, for the promulgation of a RH FIP by us, unless those states,
including New Mexico, made a RH SIP submission and we approved it.
Therefore, we had full authority to promulgate a FIP for the State of
New Mexico that included a NOX BART determination for the
SJGS. In response to the second commenter, we do not view it as
premature to take action on one element of the RH requirements at this
time. We chose to exercise this authority to conduct a NOX
BART review of the SJGS, as a partial route forward in satisfying our
consent decree with WEG.
Although we subsequently received the New Mexico submittal on July
5, 2011, we simply have arrived at a point where we do not have the
time to stop our action, review that SIP, propose a rulemaking, take
and address public comment, and promulgate a final action as defined in
the consent decree.
Comment: One commenter alleges that our statement that the SJGS is
more than 30 years old and needs to update its control equipment is
inaccurate.
Response: As explained elsewhere in this notice and our proposal,
our data supports the need for the SJGS to retrofit their sources of
emissions to meet the requirements of the CAA.
Comment: One commenter argues that the Administrative Procedures
Act is not adequate regarding impacts on small governmental entities.
Response: This final rulemaking only addresses the disapproval of a
portion of the SIP revision submitted by the State of New Mexico for
the purpose of addressing the visibility prong of the Interstate
Transport rule. See elsewhere in our response to comments for a
detailed description of what is addressed in this Final Action.
Therefore, comments related to the Administrative Procedures Act and
how it is not adequate regarding the impacts to small businesses are
outside the scope of our proposed action.
Comment: One commenter alleges that ``Federal forces'' create air
regulations to solve a problem that doesn't exist and threatens our
county's livelihood.
Response: This rulemaking is the result of CAA requirements that a
SIP must have adequate provisions to prohibit emissions from adversely
affecting another state's air quality through interstate transport and
that certain facilities install BART to protect visibility in national
parks and wilderness areas. The visibility problem in these areas of
great scenic importance has been recognized as a significant issue by
policymakers from Federal, State and local agencies, industry and
environmental organizations.\70\ Technical data, that are part of the
record, evidence that emissions of SO2 and NOX
from the SJGS are interfering with efforts to protect visibility in
other states, as well as impacting Class I areas within NM.
---------------------------------------------------------------------------
\70\ See RHR, 64 FR 35714 (July 1, 1999).
---------------------------------------------------------------------------
P. Modeling Comments
Comment: The San Juan Coal Company (SJCC) commented that EPA
compared the emission levels of both New Mexico's 2018 projected
emissions and New Mexico's current emissions that were developed for
the WRAP photochemical modeling. EPA relied upon that comparison to
determine that all of the sources in New Mexico are achieving the
emission levels assumed by WRAP in its modeling except for the SJGS.
SJCC alleged that EPA's summary of that analysis presents no relevant
data to support the Agency's conclusion. Because the WRAP inventories
are so extensive and difficult to research and review, EPA at a minimum
should have provided copies of the State's emissions inventories that
were reviewed and the specific emissions data for SJGS that supports
EPA's conclusion. SJCC stated that EPA should not have put the burden
of interpreting the WRAP technical support documents on the reader.
Furthermore, in light of the substantial number and different types of
emission sources throughout New Mexico, our conclusion is suspect. EPA
must produce the specific emissions information for SJGS and for all
other emission sources in the State, which isolates SJGS as the only
reason for New Mexico's interstate interference with visibility
protection.
Response: While we did point in the proposed rule to the WRAP Web
site as a reference for the emission data that we reviewed and
compared, we also developed a complete TSD, and included some of the
spreadsheets for 2002, i.e., the ``current'' emissions and for the
projected 2018 emissions, in the docket for the proposed rule.
Specifically, in Chapters 2 (BART Eligible Determination), 3 (Subject-
to-BART Determination) and 4 (BART Guidelines and Modeling Protocols)
of the TSD we discussed the WRAP's CALPUFF screening modeling and why
we identified SJGS as the only source in New Mexico that was not
sufficiently controlled to eliminate interference with the visibility
programs of other states.
Our review and the State's first focused on BART eligible sources
because these are sources first considered for control in State
Regional Haze Plans. In May 2006, NMED conducted an internal review of
sources that met the regulatory definition ``BART-eligible'' source set
forth in 40 CFR 51.301.\71\ The State identified 11 facilities that
were BART-eligible. The WRAP performed the initial BART CALPUFF
screening modeling for the state of New Mexico. The modeling was
performed for each of the 11 sources and their combined SO2,
NOX, and PM emissions. The purpose of this BART CALPUFF
screening modeling was to determine whether any of these 11 sources
``emits any air pollutant which may reasonably be anticipated to cause
or contribute to any impairment of visibility'' in any Federal Class I
area. Consistent with the BART Guidelines, this WRAP initial BART
CALPUFF screening modeling evaluated the 98th percentile visibility
impacts at any Class I area from each of these 11 sources. Using 0.5 dv
as the significance threshold, of the 11 sources, only one source's
visibility impacts at any Class I area due to its combined
SO2, NOX, and PM emissions was above the 0.5 dv
significance threshold (i.e., PNM's SJGS Boilers 1-4). Of the
10 other sources, none were above a 0.33 dv impact. Consequently, only
the PNM's SJGS Boilers 1-4 were determined by NMED to be
emitting pollutants contributing to impairment of visibility in any
Federal Class I area and therefore were subject to BART. We note in the
BART Guidelines that states (and by extension EPA when promulgating a
FIP) have flexibility in determining an appropriate threshold for
determining whether a source contributes to any visibility impairment
for the purposes of BART. However, this threshold should not be higher
than 0.5 dv. As discussed in the TSD, based on modeling sensitivities,
even if we re-ran the BART CALPUFF screening modeling for the other 10
sources, the conclusion reached by both New Mexico and EPA would be
unlikely to change. Therefore, these facilities are not subject to
BART. As such, New Mexico did not propose additional controls for these
facilities nor did the WRAP modeling include additional reductions for
these 10
[[Page 52424]]
sources. These 10 sources are sufficiently controlled to eliminate
interference with other states' visibility programs.
---------------------------------------------------------------------------
\71\ BART-eligible sources are those sources, which have the
potential to emit 250 tons or more of a visibility-impairing air
pollutant, that were put in place between August 7, 1962 and August
7, 1977, and whose operations fall within one or more of 26
specifically listed source categories.
---------------------------------------------------------------------------
Our review and the States' particularly focused on sources
potentially subject to BART because in developing RH plans, sources
subject to BART were a particular focus for States in projecting
emission reductions. After the running of the WRAP initial BART CALPUFF
screening modeling that identified the one source subject to BART, the
WRAP ran photochemical modeling for all the sources in the entire
region for the base year (2002) and the future year (2018). The WRAP
participating states based their RH reasonable progress goals and long-
term strategies upon this photochemical modeling and its inputs,
particularly the future year projections for all of the sources in the
region. All the participating WRAP states agreed to the emissions input
for the base and future years. These states are relying upon the WRAP
photochemical modeling's future year projected emissions from all the
sources in the region to establish their Reasonable Progress Goals. In
consultation with New Mexico, the WRAP photochemical modeling included
anticipated reductions in emissions at the SJGS. Through the WRAP
consultation process, New Mexico provided the anticipated future year
projected emissions from SJGS to be 0.27 lb/MMBtu for units 1 and 3 and
0.28 lb/MMBtu for units 2 and 4. Other WRAP states are relying on the
levels modeled for the SJGS units, developed in consultation, in their
demonstration of reasonable progress plans towards natural visibility
conditions. New Mexico, however, did not adopt limits to insure that
the levels assumed for SJGS in the WRAP modeling would be achieved.
This discrepancy from what other States assumed is a particular concern
because, as discussed previously, SJGS, was found in the BART modeling
to, by itself, contribute significantly to visibility impairment.
Our review of the WRAP BART CALPUFF screening modeling and analysis
for sources potentially subject to BART in New Mexico is well
documented in the TSD as described above. In addition, as part of our
review, we evaluated the methodologies used by WRAP in developing their
future year emissions projections for the WRAP photochemical modeling.
The spreadsheets on the WRAP Web site document the future year
projections used by the WRAP in their photochemical modeling. Except
for SJGS, the WRAP projections in the photochemical modeling were
supported by accepted and agreed upon emissions inventory projection
methodologies in combination with regulations or other limitations and
were based on the data available at the time. This information was
publicly available for review on the WRAP Web site.
Therefore, we adequately explained why our action is limited to the
SJGS. In addition, the information we relied on to reach our
conclusions is available to the public and was validated by a voluntary
group of state, federal and local air agencies dealing with regional
air quality issues. Relying on WRAP data provides consistency of
analyses throughout the Western states, and assures that our decisions
are not arbitrary. Thus, EPA's decision is based on data to support
that the SJGS is the only source that requires the enforceable measures
in this action to ensure reductions needed to meet the anticipated
level of emissions relied upon in the WRAP modeling.
Comment: SJCC contests EPA's conclusion that SJGS is the only
source in New Mexico continuing to contribute to visibility impairment
in other states because EPA reached this conclusion without comparing
all the New Mexico sources' current emissions in the WRAP modeling with
their projected 2018 emissions. In addition, EPA did not use the annual
emissions value in the ``core emission inventories'' presented in the
WRAP modeling for the SJGS reported in tons per year (tpy). The
commenter states that EPA performed its comparison by using emission
rates in terms of units of pounds per British thermal unit (lbs/MMBtu)
for the SJGS. The commenter continues to allege that in addition to
using lbs/MMBtu rather than the annual emissions, EPA apparently,
further adjusted SJGS's current emissions that were in the WRAP
modeling to account for a shorter averaging time because the WRAP
averaging periods were unenforceable. This methodology was not applied
to any other source. SJCC claims that if EPA had applied this
methodology to the other New Mexico sources, it is extremely likely
that EPA would have needed to adjust their current levels as well.
Therefore, EPA's comparison analysis is flawed, and EPA cannot assume
that the SJGS is the only source in the State (or within the WRAP
region for that matter) whose current emissions have not been specified
on a basis that is consistent with how projected 2018 emissions were
expressed for the WRAP modeling.
Response: As discussed in our proposal and elsewhere in this
notice, the analysis conducted by the WRAP provides an appropriate
means for evaluating whether emissions from sources in a state are
interfering with the visibility programs of other states, as
contemplated in section 110(a)(2)(D)(i) of the Act. In developing their
visibility projections using photochemical grid modeling, the WRAP
states assumed a certain level of emissions from sources within New
Mexico. The visibility projection modeling was in turn used by the
states to establish their own respective reasonable progress goals. We
evaluated the planned emission reductions from point sources in New
Mexico assumed in the WRAP 2018 modeling. But for SJGS, the WRAP
projections were supported by accepted and agreed upon emissions
inventory projection methodologies and/or regulations or other
limitations and were based on the data available at the time. As a
result of the initial BART analysis performed by the WRAP, identifying
SJGS as subject-to-BART, and consultation with New Mexico, the WRAP
photochemical modeling included anticipated reductions in emissions at
the SJGS. The reductions at SJGS were the only additional reductions
that other states relied upon occurring that NMED would require in
their RH/BART SIP. The WRAP's photochemical modeling that was performed
to yield daily (24-hour) visibility impairment impacts adjusted the
future year NOX emissions from SJGS after input from NMED
and PNM to 0.27 lb/MMBtu for units 1 and 3 and 0.28 lb/MMBtu for units
2 and 4.
PNM has subsequently indicated that they cannot meet these relied-
upon emission rates without installing additional control equipment and
the actual achievable emission rate is approximately 0.30 lb of
NOX/MMBtu on a longer-term basis (30 day rolling average) as
currently reflected in their permit and 0.33 lb of NOX/MMBtu
on a shorter-term basis. Clearly, the difference between what was
assumed by the WRAP and what is actually being achieved and is
enforceable should not be ignored.
We disagree that our use of lbs/MMBtu versus the annual emissions
rate compromised our evaluation. There is no compromise in integrity
using the lbs/MMBtu versus using an annual emission rate, since the
annual NOX emission rate for each EGU in the WRAP
photochemical modeling is calculated using the short term emission rate
of lbs/MMBtu multiplied with the heat input and hours of operation. In
the future case photochemical modeling for most sources, the actual
base emissions from 2002 were projected to the future using differing
techniques to project the
[[Page 52425]]
amount of growth and yield an estimate of the future emissions, taking
into account the source type, any applicable regulations and
limitations, and data available at the time. As discussed in another
response to comment, the WRAP modeling was conducted in a collaborative
effort, and the participating states agreed with these methodologies
for generating the future year emission inventories. To apply the same
exact procedures in calculating future emissions that were applied to
the SJGS to all other sources in New Mexico would be inconsistent with
the methodology that the WRAP used. We used the same methodology to
calculate emissions for EGU's that were installing controls as the WRAP
did for other EGUs installing controls. We used the short-term 0.33 lb/
MMBtu emission rate as it directly relates to the averaging period for
evaluating the visibility impairment, which is daily. For EGUs, the
WRAP utilized a forecasting technique to yield 2018 emission estimates
by applying a growth factor to the 2002 firing rate up to a capacity
threshold of 0.85.\72\ For NOX and SOx emissions from EGUs,
the WRAP also used data from 2004 to be representative of emission
rates for 2018. However, for EGU sources where the installation of
controls was anticipated, such as the SJGS, they utilized the short-
term emission factor that would result from the addition of controls
(lb of pollutant per MMBtu) and then multiplied by the heat input to
yield an annual tpy value that was reported in the WRAP's emission
spreadsheets. While the commenter is correct that the WRAP's
spreadsheets for photochemical modeling report data is in tpy, the WRAP
calculation method uses the same basis for calculation that we used in
our analysis, a lb of pollutant per MMBtu. We did our emission
calculations for the SJGS using the same methodologies as the WRAP for
other EGUs installing controls and, therefore, disagree with the
commenter's allegation that the SJGS were calculated unfairly.
---------------------------------------------------------------------------
\72\ Document that was included in our proposal docket,
``Developing the WRAP Point and Area Source Emissions Projections
for the 2018 Reasonable Progress Milestone for Regional Haze
Planning'', Paula G. Fields, Martinus E. Wolf, Tom Moore, Lee
Gribovicz.
---------------------------------------------------------------------------
We disagree with the characterization that we adjusted the SJGS
current emissions in the WRAP. From the comment it is unclear if the
commenter's concerns were just about emission rate/calculations for the
photochemical modeling or the CALPUFF modeling. Because the comment is
unclear, we have addressed their comment for both types of modeling. At
issue is the emission rate that needs to be calculated from the SJGS in
order to determine visibility impacts from the facility. For the
CALPUFF modeling, the July 2005 BART rules recommend using the actual
24-hour maximum emission rate over the last several years as the basis
for the baseline emissions, and when a source is controlled in the
future the emission rate that would represent a maximum 24-hour
potential emission rate after install of controls is used for the
future control scenario. Therefore, the values used in the CALPUFF
modeling pursuant to EPA regulation and guidance are a short-term (24-
hour) emission rate to reflect visibility impairment impacts. For the
baseline, we took the existing enforceable permit level, which is a 30-
day average and converted it to a 24-hour maximum emission rate to use
in CALPUFF to determine the visibility impacts from the SJGS. PNM and
NMED's CALPUFF modeling, conducted to estimate daily visibility
impairment at Class I areas for the baseline conditions, utilized an
emission factor rate of 0.33 lb/MMBtu as the level that they could show
compliance on a short-term basis.\73\ We utilized the same emission
rate in our CALPUFF modeling of the base case visibility impacts.
---------------------------------------------------------------------------
\73\ NMED Proposed Regional Haze SIP, available at AppxA--NM--
SJGS--NOxBARTDetermination--06212010.pdf and modeling files provided
by NMED to EPA for Review June/July 2009.
---------------------------------------------------------------------------
In the photochemical modeling, the emission rate used in the
baseline inventory was based on a NOX emission rate of 0.27
or 0.28 (depending on the boiler Unit) and a 0.33 lb/MMBtu based rate
as the maximum 24-hour emission rate in the CALPUFF modeling. We also
note that these baseline emission rates were used by the state in
consultation. In summary on this issue, EPA believes the commenter did
not fully understand how emission rates were modeled for the two
modeling platforms in comparison to how the WRAP calculated future year
emission rates for EGUs, and we believe we have followed our
regulations and guidance in accurately assessing the impacts with
appropriate emission rates.
As part of our action for 110(a)(2)(D)(i) of the CAA, we are also
setting a SO2 limit in our action to be protective of the
0.15 lb/MMBtu limit for SJGS units that was included in the WRAP
photochemical modeling and relied upon by WRAP states. SJGS has
installed control equipment that is achieving below this level
currently, but does not have an enforceable limit that limits the SJGS
units to 0.15 lb of SO2/MMBtu.
Comment: The SJCC found the wording of EPA's conclusion comparing
New Mexico's current emissions and projected 2018 emissions to be
confusing. If all sources in New Mexico, other than SJGS are currently
achieving projected 2018 emissions, as EPA asserts, then that means the
only emissions reductions that will occur during the first RH planning
period from all emission sources in New Mexico will be from SJGS, which
SJCC asserts is incorrect. To support this interpretation, the SJCC
turned to the New Mexico emissions inventories used in the WRAP
modeling and noted that the WRAP modeling projects a reduction in
NOX emissions of about 10,500 tpy from the SJGS by 2018. The
SJCC notes that in comparison, the State's (then) proposed RH SIP
estimated that statewide NOX emissions will decrease by
64,814 tpy by 2018. Based upon these numbers and comparing them, the
SJCC concludes that the statement that all sources in New Mexico,
except SJGS, are achieving the emission levels assumed by the WRAP
modeling is incorrect. Rather, the SJCC asserts, information shows that
other New Mexico sources besides the SJGS could be ``interfering'' with
other states' measures to protect visibility. The SJCC concludes that
although EPA's interpretation of ``interference'' may be reasonable on
its face, the application of its explanation of its meaning indicates
otherwise. EPA's explanation provides no credible justification for
singling out the SJGS as the only New Mexico source of emissions that
is interfering with other states' visibility-protection measures.
Response: The statement that other sources were achieving the
necessary reductions may have been unclear. In developing its emissions
inventory, WRAP states estimated the emissions growth and all
reductions that were expected to occur from point, area, and other
sources, from all regulatory requirements. For New Mexico point sources
other than the SJGS, the current federally enforceable emission limits
for these sources are consistent with those relied upon in the WRAP
modeling. For the SJGS, the WRAP states considered the impact of the RH
BART requirements. As discussed in our proposal and elsewhere in this
notice, we evaluated the planned emission reductions from point sources
in New Mexico assumed in the WRAP modeling and concluded that the SJGS
was the only source in New Mexico that was expected to get reductions
beyond the current, i.e., baseline levels, because
[[Page 52426]]
that source was determined to be subject to BART. The 10,500 tpy
NOX reduction mentioned by the commenter refers to the
reduction in NOX emissions at the SJGS anticipated by the
WRAP and included in the future case photochemical modeling.
For other sources, such as the ones the SJCC points to as
accounting for the remainder of their 64,814 total reduction of
NOX emissions in New Mexico, the WRAP states considered
other rules on the books, projected reductions from other federal rules
(including those addressing mobile sources), national consent decrees,
and mobile source fleet turnover, among other things. These projections
were reviewed and agreed to by the WRAP states as a part of their joint
development of a complete WRAP emission inventory in support of their
RH SIPs, and were relied upon by the WRAP states as a part of the
reasonable progress goals. The commenter is correct that other sources
in New Mexico are projected to reduce their emissions as well. Those
projections are based on the states' best estimate of the growth of
emissions from some sources and the future impact of all combined
regulatory programs. We conclude, for the purpose of satisfying section
110(a)(2)(D)(i)(II), those projections were reasonable and adequately
incorporated into the WRAP modeling.
As to the comment on how we defined ``interference'' in the context
of CAA Sec. 110(a)(2)(D)(i)(II), please refer to our response to
comments to legal issues (Section O.1 of this notice), where we have a
full response as to how we view the term ``interfere'' in the context
of the interstate transport requirements of the CAA. In that response
we state that by promulgating a FIP to impose NOX and
SO2 emission limits necessary at the SJGS to prevent such
interference, as well as to meet the requirement for BART for
NOX for this same source, EPA is addressing the requirements
of the CAA. In reaching this conclusion, we considered the term
``interfere'' based upon the facts, information, and data available to
EPA at this time.
Comment: PNM commented that our choice of an SO2
baseline and future emission rate of 0.15 lbs/MMBtu was incorrect, and
that an SO2 emission rate of 0.18 lbs/MMBtu is more
appropriate. PNM alleges that this is based on the current, federally
enforceable emission limit. PNM asserts that our justification for
using the lower SO2 rate is that the lower rate is expected
in the future. The commenter argues that utilizing the current
SO2 limit is the more appropriate modeling method even
though the use of the current limit would actually result in higher
expected visibility improvements.
Response: We conducted CALPUFF visibility modeling to analyze the
impacts on visibility impairment from the NOX BART proposed
controls. Due to the nonlinear nature and complexity of atmospheric
chemistry and chemical transformation among pollutants, all relevant
pollutants should be modeled together to predict the total visibility
impact at each Class I area receptor.\74\ In order to estimate the
benefits from the NOX BART proposed controls, we included
the SO2 emissions as relied upon in the WRAP modeling in our
CALPUFF modeling. The SO2 emission limit of 0.15 lb/MMBtu
that we input into the NOX BART visibility modeling is based
upon what was relied upon in the WRAP modeling. Our FIP makes this
WRAP-relied upon SO2 limit of 0.15 lb/MMBtu federally
enforceable. PNM's requested baseline emission rate of 0.18 lb/MMBtu of
SO2 is not what was relied upon in the WRAP modeling.
---------------------------------------------------------------------------
\74\ Memo from Joseph Paisie (Geographic Strategies Group,
OAQPS) to Kay Prince (Branch Chief EPA Region 4) on Regional Haze
Regulations and Guidelines for Best Available Retrofit Technology
(BART) Determinations, July 19, 2006
---------------------------------------------------------------------------
Per EPA's BART Guidelines, maximum actual emissions should be
utilized in the visibility modeling of the base case, and all installed
control technology should be considered. Future case modeling should
include post control maximum emission rates.\75\ We note that the SJGS
currently has SO2 control technology installed and has
current actual SO2 emissions below our proposed FIP limit.
As a result, the facility will not have to install additional controls
to meet our SO2 FIP limit. As we are setting the 0.15 lb/
MMBtu SO2 emission limit in the FIP for SJGS, we modeled an
emission rate of 0.15 lb/MMBtu for SO2 for both the baseline
(current) and control (future) cases in estimating the anticipated
visibility improvement due to installation of the NOX BART
proposed controls. By holding the SO2 emissions constant in
the revised baseline (current) and future (control) cases, the modeled
predicted improvements in visibility due to the NOX BART
proposed controls are kept separate from any potential changes in
visibility due to changes in SO2 emissions. This means the
final CALPUFF analysis reflects only the benefits due to the additional
NOX reductions beyond the baseline. This also reflects the
SJGS's flexibility to increase its SO2 emissions up to the
SO2 FIP limit of 0.15 lb/MMBtu. It provides a more
representative estimate of anticipated visibility improvements from
installation of NOX controls.
---------------------------------------------------------------------------
\75\ Page 39129 of BART Rule, ``We believe the maximum 24-hour
modeled impact can be an appropriate measure in determining the
degree of visibility improvement expected from BART reductions (or
for BART applicability)'', Pages 39107-3918 of BART Rule For
assessing the fifth factor, the degree of improvement in visibility
from various BART control options, the States may run CALPUFF or
another appropriate dispersion model to predict visibility impacts.
Scenarios would be run for the pre-controlled and post-controlled
emission rates for each of the BART control options under review.
The maximum 24-hour emission rates would be modeled for a period of
three or five years of meteorological data.
---------------------------------------------------------------------------
Comment: A commenter disagrees with the general modeling approach
and assumptions relied upon in EPA's modeling analysis. The commenter
contends that we performed numerous different visibility models and
chose the one with the highest visibility improvements, even though the
chosen model results are the least consistent and the least realistic
of the modeling runs prepared. The commenter claims that EPA's chosen
value suggests that visibility improvements associated with installing
SCRs at SJGS will be three times higher than the model that would
assume more realistic, site-specific background ammonia concentrations
and the Method 6 post-processing that has been relied upon by PNM,
NMED, and WRAP and by EPA itself with regard to SO2 (by
relying on the WRAP modeling). The commenter argues that EPA's
rejection of PNM's modeling is unjustified and unnecessarily inflates
the expected visibility improvements associated with SCRs. The
commenter states that EPA did not raise any of its concerns to PNM or
NMED until the issuance of the proposed FIP despite discussions with
NMED over several years regarding proper modeling techniques.
Response: This comment is incorrect. In January 2010, NMED proposed
as NOX BART, the installation of SCR on the four units at
SJGS and relied upon modeling much of which was completed in the 2006-
2007 timeframe. SCR is generally considered the most stringent control
technology available for NOX. The Guidelines for BART
Determinations under the Regional Haze Rule's modeling guidelines in 40
CFR part 51 App. Y, IV. D. 5 indicate that selection of the most
stringent controls available may allow a source or the state agency to
skip conducting visibility impairment modeling. Therefore, because NMED
selected SCR, the most stringent control generally available,
consistent with our RHR requirements (Step 1, Number 9 in the
Guidelines), we did not perform a close review of the modeling in the
State's proposal during
[[Page 52427]]
the State's public process. Unfortunately, NMED decided not to finalize
their proposal and then withdrew it from further state rulemaking in
May 2010.
When we developed the proposed FIP for NOX BART, we
conducted our own visibility impact analysis (the degree of visibility
improvement reasonably anticipated due to NOX BART at SJGS).
In conducting modeling for our proposed NOX BART FIP, we
utilized current practices and model versions that were acceptable to
us at the time they were conducted in the latter half of 2010. In order
to minimize technical concerns with the CALPUFF modeling system
version, modeling options selected in CALMET, calculation of emissions
(including sulfuric acid mist), and background ammonia levels employed
by PNM, we remodeled visibility impacts using the CALPUFF version that
we have determined to be appropriate for regulatory purposes. Please
see our Complete Response to Comments for NM Regional Haze/Visibility
Transport FIP document for more details. We remodeled the visibility
impacts of SJGS to address these issues with PNM and NMED's modeling,
utilizing an acceptable version of CALPUFF. In doing so, we maintain
consistency with the most current modeling guidance EPA and the FLM
representatives have provided to the states.
We performed numerous modeling runs in order to evaluate the
sensitivity of model results to the chosen model inputs and post
processing methods to generally inform the process. The justification
for selecting the revised IMPROVE equation (``Method 8'') over the
original IMPROVE equation (``Method 6'') is discussed in a separate
response to comment. Background ammonia concentrations are also
discussed further in a separate response to comments. We disagree with
the commenter's assertion we simply picked the modeling results that
best supported our position, without regard to consistency and/or
realism. Every parameter and model input was evaluated and selected
separately, based on accepted methodology of EPA and the FLM
representatives, guidance and available data. During selection of model
versions and inputs, EPA R6 staff conferred with other EPA modeling
experts and FLM representatives on these modeling issues to ensure that
our modeling would be done in accordance with current day CALPUFF
modeling practices for visibility impairment analyses. A discussion of
model selection and inputs was presented in our proposal and in the TSD
and further discussed in the Complete Response to Comments for NM
Regional Haze/Visibility Transport FIP document.
Results for all modeling scenarios are provided in the Appendix 3
to the TSD, entitled ``EPA's CALPUFF Visibility Modeling Results.''
These results demonstrate the sensitivity of the model to
underestimation of background ammonia and the sensitivity to the use of
the original IMPROVE equation. Utilizing the different methods and
different ammonia levels does result in different predicted impact
levels, but the overall change in visibility impairment, i.e., the net
visibility improvement, due to the proposed NOX BART FIP
emission limit is a significant value in all cases. In other words,
while the ammonia levels affect visibility improvement, throughout the
range of ammonia background being modeled, the NOX BART
controls adopted here result in significant and important visibility
improvement. For example, our sensitivity modeling predicted
significant visibility improvement at Mesa Verde due to the proposed
NOX BART emission limit, ranging from 38 to 56% improvement,
depending on the background ammonia and post-processing method
selected.
Comment: We received comments that alleged that our CALPUFF
modeling analysis failed to fully and appropriately account for the
visibility improvement already achieved by recent SO2 and
NOX emission reductions from SJGS. PNM contracted with B&V
to perform a BART analysis for the SJGS. The commenters claim that this
analysis used EPA's BART guidelines and showed that the low
NOX burners installed on all four units at SJGS during the
environmental upgrade project between 2007 and 2009 meet the
requirements for NOX BART.
Response: Our technical modeling analysis accounted for the
visibility improvements achieved by existing controls at the SJGS by
incorporating the SO2 and NOX enforceable permit
limits established under the March 10, 2005 consent decree between PNM
and the Grand Canyon Trust, Sierra Club, and NMED (2005 Consent Decree)
into the baseline emissions modeling scenario. Our analysis of the
visibility improvements due to the installation of NOX
controls as part of our proposal reflected the visibility improvement
due to installation of additional NOX controls beyond those
installed as required by the 2005 Consent Decree (completed in 2009).
Furthermore, we note that neither NMED nor EPA reviewed or approved a
NOX BART analysis including a CALPUFF modeling analysis
performed by B&V prior to the installation of controls under the 2005
consent decree. Low-NOX burners do not satisfy the
requirements for NOX BART for the SJGS; they are not
supported by the NOX BART five-factor analysis.
Comment: We received comments suggesting that modeling should be
performed using an emission rate of 0.07lbs NOX/MMBtu, for
operation of SCR, rather than the 0.05 lbs/MMBtu emission rate.
Response: Our modeling of the visibility impacts and benefits of
the installation of SCR as being NOX BART are based on the
determination of the emission limit technically feasible and achievable
at the SJGS. This determination is discussed in response to additional
comments received on the emission limit achievable by SCR at SJGS.
Comment: We received comments that claim that the installation of
SCR at the SJGS would result in imperceptible visibility improvements.
Response: We performed visibility modeling as part of the
NOX BART determination analysis. A change of 1 deciview is
generally regarded as a perceptible change in visibility (70 FR 39118;
July 6, 2005). Our modeling indicates that significant improvements in
visibility are anticipated from the installation of SCR to satisfy
NOX BART requirements. As discussed in the TSD, our
visibility modeling shows that improvement due to installation of SCR
is significant and at a level that is certainly perceptible, including
a 3.11 dv improvement at Canyonlands and 2.88 dv at Mesa Verde and an
improvement of 1 deciview or greater at 7 other Class I areas.
Installation of SCR will result in significant and perceptible
visibility improvements at a number of Class I areas.
Furthermore, in a situation where the installation of BART may not
result in a perceptible improvement in visibility, the visibility
benefit may still be significant. ``Failing to consider less-than-
perceptible contributions to visibility impairment would ignore the
CAA's intent to have BART requirements apply to sources that contribute
to, as well as cause, such impairment'' (70 FR 128; RH Regulations and
Guidelines for Best Available Retrofit Technology (BART)
Determinations, July 6, 2005). Installation of SCR will result in
significant and perceptible visibility improvements at a number of
Class I areas. However, a perceptible visibility improvement is not a
requirement of the BART determination as a visibility improvement that
is not perceptible
[[Page 52428]]
may still be determined to be significant.
Comment: A commenter asserted that EPA's proposed reductions of
NOX emissions from the SJGS, to satisfy the requirements of
section 110(a)(2)(d)(i)(II) of the CAA, are excessive and not supported
by the record. The commenter claimed that EPA failed to provide
quantitative details on how those emissions reductions were calculated.
Furthermore, the emission reductions achievable by EPA's proposed
NOX BART appear to be substantially more than the amount of
reductions required for New Mexico to comply with its visibility-
related obligation under section 110(a)(2)(D)(i)(II). The commenter
alleges that EPA did not provide information on the extent that SJGS's
emissions must be adjusted and did not provide a straightforward, side-
by-side comparison of SJGS's ``current'' emissions with and without
those emissions being adjusted by the Agency; thus, the actual amounts
of the emissions ``discrepancies'' that EPA stresses in its preamble
are unidentified.
The commenter challenges EPA's statement that those discrepancies
are ``significant'' based on ``changes in visibility projections'' and
states that EPA failed to provide modeling results quantifying the
visibility impact associated with those emission ``discrepancies.'' The
commenter states our ``discrepancies'' are not differences between
SJGS's projected emissions used in the WRAP modeling and an EPA-
adjusted level of ``current'' emissions. Rather, those emissions
``discrepancies'' are the differences between SJGS's current levels of
NOX and SO2 emissions used in the WRAP modeling
and their EPA-adjusted counterparts, i.e., current levels of those
emissions adjusted to values that EPA believes should have been used in
the modeling. The commenter questioned how, if New Mexico's 2002
NOX emissions were 312,193 tpy (Plan02d) and SJGS
corresponding emissions were 30,353 tpy of NOX, only the
amount of EPA's adjustment could significantly impact out-of-state
visibility impairment when the State's total NOX emissions
will likely be at least 10-100 times greater than the ``adjustment''
amount. The commenter then indicated that it is impossible to
independently evaluate the strength of our conclusion regarding the
extent to which emissions from SJGS must be ``adjusted,'' because the
specific numbers, which purportedly support that Agency conclusion,
have not been provided. The commenter then indicated that a judgment of
whether EPA's ``discrepancies'' are significant cannot be evaluated
until EPA identifies (1) the magnitudes of those discrepancies and (2)
the resultant modeled difference in visibility impairment due to those
discrepancies.
The commenter alleges that at no time have we specified the amount
of emissions reductions that may be necessary to satisfy New Mexico's
obligation under section 110(a)(2)(D)(i)(II) of the CAA. The commenter
estimated the amount of NOX reductions in the WRAP modeling
for the SJGS as 10,590 tpy and then approximated the amount of
NOX emission reductions from SJGS under EPA's scheme to
prevent New Mexico's ``interference'' as approximately 2,200 tpy of
NOX after considering the consent decree reductions of 8,411
tpy since 2002. They then commented that if SJGS's current (Plan02d)
2002 NOX emissions are ``adjusted'' in accordance with EPA's
approach, those required emission reductions to reach SJGS's projected
level used in the WRAP modeling would increase by an unknown quantity,
but they then assumed that the discrepancy is 100% greater than 2,200
tpy, yielding an additional 4,400 tpy NOX reduction needed
by 2018 to prevent interference. Commenter indicated that EPA's
proposal under Sec. 110(a)(2)(D)(i)(II) to retrofit SJGS's generating
units with SCR could achieve roughly 4 times the amount of
NOX emission reductions actually required and EPA's proposed
NOX emission reductions from the SJGS are excessive.
Response: We disagree with the assertion that EPA must separate the
required NOX emission reductions required by SJGS to meet
section 110(a)(2)(D)(i)(II) requirements from the NOX
emission reductions required to meet the NOX BART
determination for SJGS. EPA also disagrees that we are required to
conduct a modeling analysis to determine if the NOX
reductions necessary for SJGS to meet the 110(a)(2)(D)(i)(II)
visibility requirement would result in significant visibility
improvement. As we discuss elsewhere in this notice, there is no
necessity that we must evaluate these requirements separately and no
requirement that we perform a 110(a)(2)(D)(i)(II) visibility analysis.
See Legal response to comments, above, regarding our general authority
and obligation to act on section 110(a)(2)(D)(i)(II) and RH SIP
requirements.
The commenter takes issue with the fact that we did not
specifically quantify the difference in emissions between the WRAP
modeling and what is being achieved by SJGS, and explain why the
discrepancy was believed to be significant. We disagree. We provided in
the proposal and TSD a full discussion of how the NOX
emissions in the WRAP modeling were not being achieved by SJGS, and how
NOX emissions relied upon in the WRAP modeling for the SJGS,
and agreed upon during consultation, are not federally enforceable.
Therefore, we are establishing federally enforceable NOX
emission limits that will eliminate interstate interference and at the
same time address the RH BART requirement for NOX for SJGS.
The commenter then asserts that a side by side comparison should have
been provided in tons/year. We disagree that is necessary to quantify
this comparison in tons/years. The modeling for electric generating
units (EGUs) may have been reported out as tons/year (tpy) in the WRAP
emission modeling summary tables, but the WRAP actual modeling itself
used a short-term emission rate (i.e., lb/MMBtu). See our other
response to comment that addresses tpy versus lb/MMBtu modeled
emissions in more detail.
In the case of SJGS, the WRAP's photochemical modeling that was
performed to yield daily (24-hour) visibility impairment impacts
included future emission estimates based on emission rates of 0.27 and
0.28 lb of NOX/MMBtu and 0.15 lb of SO2/MMBtu.
After NMED's consultation with other states, PNM indicated to the State
that SJGS could not meet the two future WRAP emission rates for
NOX without installing additional NOX controls.
PNM claims that the actual emission rate was approximately 0.30 lb of
NOX/MMBtu on a longer-term basis as reflected in the permit
and 0.33 lb of NOX/MMBtu on a short-term basis as reflected
in PNM's visibility impact modeling for SJGS. PNM and NMED's CALPUFF
modeling, conducted to estimate daily visibility impairment at Class I
areas, utilized an emission factor rate of 0.33 lb/MMBtu for estimation
of daily impact as the level that they could show compliance on a
short-term basis.\76\
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\76\ Id.
---------------------------------------------------------------------------
We did not model the difference between the current enforceable
emission limits and those emission limits relied upon in the WRAP
modeling for SJGS. We find that New Mexico sources, other than the
SJGS, are sufficiently controlled to eliminate interference with the
visibility programs of other states because the federally enforceable
emission limits for these sources are consistent with those relied upon
in the WRAP modeling. The SO2 and NOX emissions
relied upon in the
[[Page 52429]]
WRAP modeling for the SJGS, however, are not federally enforceable.
Therefore, we are establishing federally enforceable emission limits
for SO2 and NOX for the SJGS to eliminate
interference with the visibility programs of other states. There is no
requirement to perform a 110(a)(2)(D)(i)(II) visibility analysis.
We note that the 98% largest deciview impact we modeled using 0.33
lb/MMBtu NOX and 0.15 lb/MMBtu SO2 was 5.15dv at
Mesa Verde Class I area. We also modeled visibility impacts using 0.33
lb/MMBtu NOX and 0.18 lb/MMBtu SO2 in our initial
modeling to compare model results with those presented by PNM and NMED.
We note that reducing SO2 emissions from 0.18 to 0.15 lb/
MMBtu resulted in a minimal change in visibility impacts at all Class I
areas (0.03 dv at Mesa Verde), demonstrating a limited sensitivity to
changes in SO2 emissions compared to the large changes in
visibility due to decreasing NOX emissions at SJGS, as shown
in our modeling of the 0.05 lb of NOX/MMBtu emission rate
(SCR case). The use of 0.15 lb/MMBtu SO2 emission rate is
discussed in a separate response to comment. Considering that the 0.33
lb/MMBtu NOX value is approximately 20% greater than the
0.27/0.28 rate, the significant visibility impacts, and the
NOX sensitivity demonstrated by the modeling, it is clear
this difference in emission rates can have a significant impact on
visibility. Even on a long-term basis, the difference between relying
upon 0.30 lb/MMBtu compared to the 0.27/0.28 lb/MMBtu would have a
significant impact. Although the atmospheric chemistry is not strictly
linear in this case, if modeled, the combined difference in
NOX and SOX emission rates would likely result in
an impact between several tenths of a deciview and 1 deciview. Clearly,
the difference between what was assumed by the WRAP and what is
actually being achieved by the SJGS should not be ignored. Since we
determined a much lower emission rate for BART, we did not need to
directly evaluate the impacts of just achieving the emission rate
levels included in the WRAP modeling.
The commenter claims that the SJGS total emissions in 2002 were
approximately 10% of the statewide New Mexico NOX emission
total. The commenter implies that the reductions found to be needed at
SJGS are exceedingly small in comparison to the total State emissions
and therefore should not be singled out for control. The commenter
fails to consider the proximity of SJGS to Class I areas and the fact
that its emissions are concentrated relative to the more diffuse
emissions of many sources in the State, such as area and mobile
sources. We conduct modeling to quantify visibility impairment impacts
because sources that are close to a Class I area and have elevated
stacks result in greater plume impact on the Class I area, and will
have a greater impact on visibility impairment per ton of
NOX, compared to a much greater tonnage of NOX
emissions from a variety of sources that are 100s of kilometers away.
Much of the New Mexico NOX emissions are spread throughout
the state and nearer to the metropolitan areas of Albuquerque and Santa
Fe and over 200 kms from Class I areas in other states, in comparison
to the SJGS which is just 42 km from the Mesa Verde Class I area. Our
modeling indicated that the SJGS had a very large impact in our
baseline emissions modeling (5.15 deciviews at Mesa Verde) which
highlights why we conduct modeling instead of analyzing emission
ratios, which is apparently what the commenter erroneously implies we
should do.
The commenter did not provide specific details or cite any guidance
as to how EPA erred in estimating emissions for modeling. We disagree
with the comments that we have unfairly adjusted the emission
calculations to overstate the benefit of our proposal. We have
conducted our calculations consistent with EPA methods and guidance,
and the WRAP EGU modeling projections.\77\ As documented in our TSD, we
used the most recent materials, including EPRI's spreadsheets, and
current EPA guidance to estimate emissions for our analyses and
disagree with the commenter's vague comment that we unfairly adjusted
the emissions to what we thought they should be.
---------------------------------------------------------------------------
\77\ Document that was included in our proposal docket,
``Developing the WRAP Point and Area Source Emissions Projections
for the 2018 Reasonable Progress Milestone for Regional Haze
Planning'', Paula G. Fields, Martinus E. Wolf, Tom Moore, Lee
Gribovicz.
---------------------------------------------------------------------------
Comment: We received comments from the NPS and USFS supporting the
reporting of the cumulative visibility impact of SJGS and the
cumulative benefits of SCR. NPS and USFS believe it is appropriate to
consider both the degree of visibility improvement in a given Class I
area as well as the cumulative effects of improving visibility across
all of the Class I areas affected. The BART guidelines do not consider
the geographic extent of visibility impairment. NPS and USFS believe
the most practical approach to this problem is to consider the
cumulative impacts of a source on all Class I areas affected, as well
as the cumulative benefits from reducing emissions. They state that
cumulative benefits have been a factor in the BART determinations by
Oregon and Wyoming, as well as EPA in its proposals for the Navajo
Generating Station and the Four Corners Power Plant. They also note
that the improvements in visibility impairment due to reductions in
NOX emissions in other analyses have been largest at Class I
areas other than the closest Class I area, therefore evaluation of all
Class I areas within the modeling domain is appropriate.
Several commenters were opposed to the use of a ``cumulative
deciviews'' or ``total'' visibility improvement metric. These
commenters claim that the ''cumulative deciviews'' metric is misleading
and that the modeling impact improvements would take place at different
locations within a Class I area, within different Class I areas, and
probably on different dates so a ``cumulative deciviews'' result would
not be observed by one viewer. They continued that one viewer would not
perceive visibility impacts in more than one Class I area
simultaneously, or even within relatively short periods of time, in
nearly every case. Furthermore, the visibility impacts to a region
should not depend on the number of Class I areas present. The
commenters state it is improper to consider a ``cumulative'' deciview
improvement over more than one Class I area.
The commenters also suggest that the use of a ``total dv'' metric
is inconsistent with BART guidelines (40 CFR part 51 Appendix Y,
IV.D.5). The guidelines state that it is appropriate to model impacts
at the nearest Class I area as well as other nearby Class I areas to
determine where the impacts are greatest. Modeling at other Class I
areas may be unwarranted if the highest modeled effects are observed at
the nearest Class I area. The commenters claim the analysis should be
focused on the visibility impacts at the most impacted area, not all
areas. The commenters add that states have already successfully dealt
with this practice. To illustrate, they point to the Colorado Air
Quality Control Commission declining to take a ``cumulative'' approach
to deciviews, even though commenters had argued the concept should
influence decision making about BART.
Response: We agree with the NPS and the USDA Forest Service on the
utility of a cumulative visibility metric in addition to the other
visibility metrics we utilized and we do not agree that our approach is
inconsistent with BART guidelines. Our visibility modeling shows that a
number of Class I areas are
[[Page 52430]]
individually and significantly impacted by emissions from the SJGS. The
number of days per year significantly impacted by the facility's
NOX emissions is expected to decrease drastically at each
Class I area (Table 6-8 of the TSD) as the result of installation of
NOX BART emission controls at the SJGS. Clearly, the
visibility benefits from NOX BART emission reductions will
be spread among all affected Class I areas, not only the most affected
area, and should be considered in evaluation of benefits from proposed
reductions.
The portion of the BART Guidelines (40 CFR 51 Appendix Y, IV.D.5)
that the commenter referenced states: ``If the highest modeled effects
are observed at the nearest Class I area, you may choose not to analyze
the other Class I areas any further as additional analyses might be
unwarranted.'' \78\ This section of the BART Guidelines addresses how
to determine visibility impacts as part of the BART determination.
Several paragraphs later in the BART Guidelines it states: ``You have
flexibility to assess visibility improvements due to BART controls by
one or more methods. You may consider the frequency, magnitude, and
duration components of impairment,'' emphasizing the flexibility in
method and metrics that exists in assessing the net visibility
improvement.
---------------------------------------------------------------------------
\78\ 70 FR 39170.
---------------------------------------------------------------------------
As discussed in a separate response to comment, for any CALPUFF
visibility modeling in a SIP, a protocol addressing procedures and
analyses should be determined with the appropriate reviewing authority
and affected FLMs. As identified in the BART Guidelines, an important
element of the modeling protocol is the choice of receptors used in the
model, and the decision of when additional analyses including modeling
the effects at Class I areas beyond the nearest area are warranted and
necessary. As indicated in the TSD and RTC for this notice, we
conferred with EPA OAQPS and FLM representatives on the details of
conducting the CALPUFF modeling in this action, and concluded, like PNM
and NMED previously concluded in their 2009 modeling, that because of
the size of the source and the number of Class I area potentially
affected, we should evaluate modeling receptors at all Class I areas
within 300 km of the source. We also received comments from FLM
representatives supporting the way we conducted our modeling including
our evaluation of multiple Class I areas.
Our baseline modeling indicated that visibility impacts from the
SGJS were above 0.5 deciviews at all 16 Class I areas within 300km of
the SJGS and above 1 deciview at 14 of the 16 Class I areas.\79\ These
significant visibility impacts support the conclusion that further
analyses were warranted. In this specific case, our analysis indicated
the largest baseline impact was at the closest Class I area (Mesa
Verde) but also indicated very large impacts at other Class I areas. In
fact, we found that the largest overall decrease in visibility impact
resulting from the proposed NOX emission reductions occurred
at a much more distant Class I area (Canyonlands). Therefore, had we
stopped our analysis after modeling the visibility improvement at Mesa
Verde, we would not have discovered that the largest visibility
improvement is predicted to occur elsewhere.
---------------------------------------------------------------------------
\79\ 70 FR 39118. Impacts of 1 deciview or greater are
considered to cause a visibility impairment.
---------------------------------------------------------------------------
In fully considering the visibility benefits anticipated from the
use of an available control technology as one of the factors in
selection of NOX BART, it is appropriate to account for
visibility benefits across all affected Class I areas and the BART
guidelines provide the flexibility to do so. One approach as noted
above is to qualitatively consider, for example, the frequency,
magnitude, and duration of impairment at each and all affected Class I
areas. Where a source such as the SJGS significantly impacts so many
Class I areas on so many days, the cumulative `total dv' metric is one
way to take magnitude of the impacts of the source into account.
Therefore, under the BART Guidelines, and based upon these facts,
we decided additional analyses were not only warranted but necessary.
The BART Guidelines only indicate that additional analyses may be
unwarranted at other Class I areas, and in no way exclude such
analyses, as the commenter suggests. We concluded that a quantitative
analysis of visibility impacts and benefits at only the Mesa Verde area
would not be sufficient to fully assess the impacts of controlling
NOX emissions from the SJGS.
Again, nothing in the RHR suggests that a state (or EPA in issuing
a FIP) should ignore the full extent of the visibility impacts and
improvements from BART controls at multiple Class I areas. Given that
the national goal of the program is to improve visibility at all Class
I areas, it would be short-sighted to limit the evaluation of the
visibility benefits of a control to only the most impacted Class I
area. As noted previously, NMED and PNM's BART analyses also presented
visibility impact and improvement projections at all 16 Class I areas.
We believe such information is useful in quantifying the overall
benefit of BART controls.
Comment: A commenter disagreed with our use of the revised IMPROVE
equation (Method 8) post-processing methodology for the CALPUFF model
results to calculate visibility impairment for the SJGS NOX
BART determination from predicted pollutant concentrations. To be
consistent with the WRAP modeling, the commenter claims we instead
should have used the original IMPROVE equation (Method 6). The
commenter further alleges that our use of Method 8 resulted in much
higher visibility impacts and improvements than would have been
predicted using Method 6. The commenter also claims that our
NOX BART modeling analysis is internally inconsistent
because we rely on Method 6 for SO2 (using the WRAP
modeling) and on Method 8 modeling for NOX. Furthermore, the
commenters assert that the use of Method 8 is generally justified by
EPA by referring to the ``regulatory version,'' however, Method 8
processing is not supported by the ``regulatory version'' EPA used in
its analysis.
Response: Method 6 and Method 8 refer to two different versions of
algorithms used to estimate visibility impairment from pollutant
concentrations. Method 8 is a more recently available, more refined
version of the original equation and is now considered by us and FLM
representatives to be the better approach to estimating visibility
impairment. Compared to the original IMPROVE equation, this revised
IMPROVE equation has less bias, accounts for more pollutants,
incorporates more recent data, and is based on considerations of
relevance for the calculations needed for assessing progress under the
RHR.\80\ We are aware that Method 8 tends to show more improvement in
visibility than Method 6 when reductions in very small particles are
achieved, such as those that are formed by emissions of NOX.
We believe that this, however, more accurately reflects real visibility
conditions.
---------------------------------------------------------------------------
\80\ Revised IMPROVE algorithm for Estimating Light Extinction
from Particle Speciation Data, IMPROVE, January 2006 (http://vista.cira.colostate.edu/improve/Publications/GrayLit/gray_literature.htm) ; Hand, J.L., Douglas, S.G., 2006, Review of the
IMPROVE Equation for Estimating Ambient Light Extinction
Coefficients--Final Report (http://vista.cira.colostate.edu/improve/Publications/GrayLit/016_IMPROVEEeqReview/IMPROVEeqReview.htm).
---------------------------------------------------------------------------
We are also aware that at the time the States were working together
in the WRAP to develop their RH SIPs, Method 6 was widely employed to
develop RPGs and for initial BART
[[Page 52431]]
analyses. By the time Method 8 was widely available, some States were
far enough along in their SIP development that a switch to the newer
method would have been disruptive. Because of this, we did not object
to the use of Method 6 in the WRAP photochemical modeling or subject-
to-BART screening modeling. In the case of New Mexico, Method 6 was
used in WRAP modeling to determine which sources are subject to BART.
Using Method 6, New Mexico determined that the SJGS was subject to BART
because of its significant impact on Class I areas. We reached the same
conclusion using either Method 6 or Method 8 in our modeling. New
Mexico and the other WRAP States also used Method 6 to develop
reasonable progress goals for the Class I areas in the region.
For the purposes of ensuring that New Mexico's emissions do not
interfere with other States' plans for visibility improvement, the
choice of IMPROVE Method is not relevant. The commenter seems to imply
that because the WRAP modeling largely used Method 6, we should use
Method 6 for all our analyses, including our source specific analyses
for NOX BART. However, regardless of which IMPROVE equation
is used, New Mexico did not provide federally enforceable limitations
on SJGS' SO2 and NOX emissions to achieve the
reductions expected by other States. Without these reductions, other
States will not achieve the progress at their Class I areas which they
expected under the collaborative WRAP process.
As discussed previously, we have concluded that it is appropriate
to address the requirements for NOX BART for SJGS at the
same time we address New Mexico's obligations under the visibility
prong of 110(a)(2)(D)(i). As part of the BART analysis, we performed
CALPUFF modeling to assess the impacts of the NOX BART
proposed controls on the single source at issue on visibility
impairment. Because Method 8 is the preferred method for analyses being
conducted at this time,\81\ we estimated the CALPUFF visibility impacts
using this peer reviewed algorithm. We also evaluated modeling results
using Method 6 to quantify the sensitivity of our results to the choice
in visibility impairment algorithm. We note that using either Method 8
or Method 6, substantial visibility benefits were projected for the
installation of SCR and support the conclusion that SCR is the
appropriate BART control.
---------------------------------------------------------------------------
\81\ U.S. EPA. Additional Regional Haze Questions. U.S.
Environmental Protections Agency. August 3, 2006, available at
http://www.wrapair.org/forums/iwg/documents/Q_and_A_for_Regional_Haze_8-03-06.pdf#search=%22%22New%20IMPROVE%20equation%22%22; WRAP
presentation, ``Update on IMPROVE Light Extinction Equation and
Natural Conditions Estimates'' Tom Moore, May 23, 2006; U.S. Forest
Service, National Park Service, and U.S. Fish and Wildlife Service.
2010. Federal land managers' air quality related values work group
(FLAG): phase I report--revised (2010). Natural Resource Report NPS/
NRPC/NRR--2010/232. National Park Service, Denver, Colorado.
---------------------------------------------------------------------------
We disagree with the comment concerning Method 8 and the
``regulatory version'' of the model. CALPOST is the post-processing
tool used to apply an algorithm to estimate visibility impairment from
pollutant concentrations from CALPUFF. We determined CALPOST version
6.221, which includes the option to apply either the Method 6 or the
Method 8 algorithm, was the appropriate CALPOST version for our
analysis. Since we determined Method 8 was the better method for
estimating impairment, we chose to use the version of CALPOST that
allowed the calculation using either Method 6 or Method 8. We note that
this CALPOST version was approved and supported by the FLMs to allow
for application of the revised IMPROVE equation (``Method 8'').\82\ As
discussed in more detail in a separate response to comment in this
Section N and our Complete Response to Comments for NM Regional Haze/
Visibility Transport FIP document, the ultimate decision on the
acceptable model version, formulation, and set-up of CALPUFF and
CALPOST for visibility modeling is our responsibility in a FIP
situation.
---------------------------------------------------------------------------
\82\ U.S. Forest Service, National Park Service, and U.S. Fish
and Wildlife Service. 2010. Federal land managers' air quality
related values work group (FLAG): phase I report--revised (2010).
Natural Resource Report NPS/NRPC/NRR--2010/232. National Park
Service, Denver, Colorado, available at http://www.nature.nps.gov/air/Pubs/pdf/flag/FLAG_2010.pdf.
---------------------------------------------------------------------------
Comment: We received a number of comments concerning the version of
the CALPUFF modeling system EPA has used. We utilized CALPUFF Version
5.8 suite for visibility modeling. The commenter indicated revised
CALPUFF model Versions 6.112 and 6.4 are available and submitted
modeling analyses using these versions of CALPUFF with the suggestion
that their modeling should be used instead of ours. A number of
commenters stated that Version 5.8 is outdated and overestimates
visibility impacts. The commenters argue that the latest version,
CALPUFF Version 6.4, which includes updated chemistry and technical
enhancements to improve the model's performance and accuracy, should be
used to evaluate visibility impacts. They alleged that this version
includes updated chemistry that is more robust and performs better and
technical enhancements to improve the model's performance and accuracy.
Additionally, commenters included information on a February 16,
2011 meeting held with the EPA in Research Triangle Park (RTP), North
Carolina along with representatives of the western states utility
organization WEST Associates, the American Petroleum Institute (API),
and TRC (the developer of CALPUFF). The FLMs participated in this
meeting by teleconference. It was agreed at the meeting that the FLMs
will take the lead on a review and testing of the CALPUFF model code
changes including the new chemistry modules, and Model Change Bulletins
(MCBs) and coordinate with EPA.
Response: The commenter indicated that a revised version of the
model is available and submitted modeling analyses using CALPUFF model
Versions 6.112 and 6.4. Comments received justifying the use of these
versions of CALPUFF alleged that they were more scientifically robust
and included updated chemistry and technical enhancements to improve
the model's performance and accuracy. We disagree that the newer
versions of CALPUFF should be used in this action to determine
potential visibility impacts. The newer version(s) of CALPUFF have not
received the level of review required for use in regulatory actions
subject to EPA approval and consideration in a BART decision making
process. Based on our review of the available evidence we do not
consider the models to have been shown to be sufficiently documented,
technically valid, and reliable for use in a BART decision making
process. In addition, the available evidence would not support approval
of these models for current regulatory use. There are known technical
problems with CALPUFF 6.112 and furthermore, the development of new
model versions requires technical and policy evaluations to ensure the
models meet regulatory requirements.
The commenter's modeling using different model versions with as yet
unapproved mechanisms and the non-guideline techniques indicated
different results than past modeling submitted by PNM and the results
of our modeling of SJGS.\83\ The visibility impacts of their modeling
results are much lower compared to results of past PNM, NMED and EPA
modeling. These discrepancies are large enough to lend further
[[Page 52432]]
credence to the need for a full review of the revised modeling systems
before considering the modeling results for any decision
making.84 85 EPA was fully justified in following its
modeling approach, which was consistent with current EPA and FLM
guidelines, as well as similar to modeling recently performed by NMED
and PNM. EPA used the approved version of the model in accordance with
the appropriate procedures, as discussed further in other response to
comments and is confident in using our results as one of the five
factors in making a BART determination.
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\83\ Comparison of model results presented by commenter with
values in our TSD Chapter 6.
\84\ 70 FR 39123, 39124. ``We understand the concerns of
commenters that the chemistry modules of the CALPUFF model are less
advanced than some of the more recent atmospheric chemistry
simulations. To date, no other modeling applications with updated
chemistry have been approved by EPA to estimate single source
pollutant concentrations from long range transport.'' and in
discussion of using other models with more advanced chemistry it
continues, ``A discussion of the use of alternative models is given
in the Guideline on Air Quality in appendix W, section 3.2.''
\85\ EPA report, ``Assessment of the VISTAS Version of the
CALPUFF Modeling System'', EPA-454/R-08-007, August 2008 available
at (http://www.epa.gov/ttn/scram/reports/calpuff_vistas_assessment_report_final.pdf).
---------------------------------------------------------------------------
In considering the comment that we should use the latest version of
CALPUFF (6.4) or an earlier version 6.112, we considered the regulatory
status of CALPUFF for visibility analyses and what analyses are needed
to utilize an updated CALPUFF modeling system. The requirements of 40
CFR 51.112 and 40 CFR part 51, Appendix W, Guideline on Air Quality
Models (GAQM) and the BART Guidelines which refers to GAQM as the
authority for using CALPUFF, provide the framework for determining the
appropriate model platforms and versions and inputs to be used. Because
of concern with CALPUFF's treatment of chemical transformations, which
affect AQRVs, EPA has not approved the chemistry of CALPUFF's model as
a `preferred' model. The use of the regulatory version is approved for
increment and NAAQS analysis of primary pollutants only. Currently
CALPUFF Version 5.8, is subject to the requirements of GAQM 3.0(b) and
as a screening model, GAQM 4. CALPUFF Versions 6.112 and 6.4 have not
been approved by EPA for even this limited purpose.
Under the BART guidelines, CALPUFF should be used as screening tool
and appropriate consultation with the reviewing authority is required
to use CALPUFF in a BART determination as part of a SIP or FIP. The
BART Guideline cited and referred to EPA's GAQM which includes
provisions to obtain approval through consultation with the reviewing
authority. Moreover, we also note that in EPA's document entitled
Guidance on the Use of Models and Other Analyses for Demonstrating
Attainment of Air Quality Goals for Ozone, PM2.5, and Regional Haze
(EPA-454/B-07-002), that Appendix W does not identify a particular
modeling system as `preferred' for modeling conducted in support of
state implementation plans under 40 CFR 51.308(b). A model should meet
several general criteria for it to be a candidate for consideration.
These general criteria are consistent with the requirements of 40 CFR
51.112 and 40 CFR 51, Appendix W. Therefore, it is correct to interpret
that no model system is considered `preferred' under 40 CFR 51,
Appendix W, Section 3.1.1 (b) for either secondary particulate matter
or for visibility assessments. Under this general framework, we
followed the general recommendation in Appendix Y to use CALPUFF as a
screening technique since the modeling system has not been specifically
approved for chemistry. The use of CALPUFF is subject to GAQM
requirements in section 3.0(b), 4, and 6.2.1(e) which includes an
approved protocol to use the current 5.8 version.
As noted previously, the summary of results provided by the
commenter indicate much lower results compared to the current
regulatory approved version of the modeling system. The significant
difference in results is an indicator that there are important changes
in the science between these new versions and the current EPA version.
We must have a full understanding of these changes before `approving'
their use. The information provided indicates the new science includes
chemistry for which this model was never approved so these changes
would necessitate a notice and comment rulemaking and not a simply
update as previously done for this model to address bug-fixes and the
like. We believe that with such modifications to the modeling system,
CALPUFF (Version 6.4) used in this manner could no longer be considered
a screening technique under Section 4 of GAQM. The CALPUFF Version
6.112 would be considered an alternative model and would be subject to
the requirements of Section 3.2 of GAQM. As covered in more thorough
detail below and in our RTC, these alternate versions of CALPUFF (6.112
and 6.4) are subject to the provisions of GAQM.
Based on the technical information that has been provided, these
model versions could not be approved because the information provided
is not sufficient and does not comport with the requirements of Section
3.2, including 3.2.2(b)(3) and (e), of GAQM. The model developer has
relied upon several articles (Escoffier-Czaja and Scire, 2007; and
Scire, et al., 2003) which describe the general reliability of the
CALPUFF modeling system and post-processing techniques for use in
visibility assessments. Based on our review of this information, we do
not believe it provides sufficient information for EPA to assess the
suitability of the newer versions of the modeling system as would be
done in reviewing models in accordance with GAQM Section 3.2.2(e)
requirements.
First, it is important to understand that each of the papers were
presented as part of general proceedings at conferences, and therefore
do not reflect the thoroughness of a formal peer review process that
would be associated with submission to mainline scientific journals.
Therefore, we do not consider these references suitable for
establishing the validity of the model or post-processing techniques or
demonstrating that these models have undergone independent scientific
peer review as necessary for reviewing models in accordance with
Section 3.2.2(e)(i) of GAQM.
Second, the evaluation techniques utilized by the developer are not
appropriate for evaluation of the chemical mechanisms of the CALPUFF
system. Appendix A.3 of GAQM describes CALPUFF as generally considered
suitable for treatment of dispersion of non-reactive pollutants from a
single source or small group of sources for distances beyond 50-km to
200- to 300-km. CALPUFF usage, in the context of the Southwestern
Wyoming Air Quality Task Force (SWWYTAF) modeling dataset presented in
both Escoffier-Czaja and Scire (2007) and Scire et al. (2003), is
treated as a full photochemical modeling system such as the
Comprehensive Air Quality Model with Extensions (CAMx) or the Community
Multiscale Air Quality Model (CMAQ). However, the evaluation techniques
presented in the aforementioned references evaluate the model as a
near-field dispersion model, presenting information on sulfate and
nitrate performance in quantile-quantile plots (Q-Q plots) only for the
Bridger-Teton IMPROVE monitoring site. This technique is not
satisfactory for purposes of model performance evaluations for full
science chemistry models. Recommended methods and metrics for
evaluation of photochemical models are discussed at length in EPA's
Guidance on the Use of Models and
[[Page 52433]]
Other Analyses for Demonstrating Attainment of Air Quality Goals for
Ozone, PM2.5, and Regional Haze (EPA-454/B-07-002).
Therefore, we do not consider the analysis techniques presented by the
model developer sufficient to demonstrate that the model is not biased,
as would be done to justify use of a model in accordance with Section
3.2.2(e)(iv) of GAQM.
Finally, no modeling files were provided for review, no protocol or
other complete documentation was provided outlining the methods and
procedures of operating the alternative model in agreement with the
appropriate reviewing authority (EPA Region 6) prior to submission of
comments, contrary to requirements of Section 3.2.2(e)(v) of GAQM.
Therefore, on the basis of available information submitted to the
public record, we could not approve the use of the alternative model
versions in accordance with Section 3.2.2(e) requirements of GAQM. We
believe our modeling accurately describes the visibility impacts of the
SJGS, the benefits of BART controls, and was based on established and
well-recognized methods.
It would be problematic for us to allow the use of any unapproved
model variants with potentially significant changes to chemistry
treatment without additional information regarding the model's
formulation, performance, and acceptability. In promulgating the BART
guidelines we made the decision in the final BART Guideline to
recommend that the model be used to estimate the 98th percentile
visibility impairment rather than the highest daily impact value as
proposed. We made the decision to consider the less conservative 98th
percentile primarily because the chemistry modules in the CALPUFF model
are simplified and likely to provide conservative (higher) results for
peak impacts. Since CALPUFF's simplified chemistry could lead to model
over predictions and thus be conservative, EPA decided to use the less
conservative 98th percentile.\86\ The modeling that PNM's contractor
performed for PNM was based on CALPUFF versions that have been updated
with an allegedly more robust chemistry and purportedly performs better
according to the commenter than the current version of the model
approved for regulatory actions (CALPUFF version 5.8). If these
versions of CALPUFF can be shown to be reliable and acceptable to EPA,
it would likely be appropriate to the use Highest Daily impact (1st
High instead of the 8th High) based on the presumption that the updated
chemistry of CALPUFF model would result in less conservative results
than Version 5.8. In past agreements in using the CAMx photochemical
model, which has a robust chemistry module, the Region has recommended
the use of the 1st High value when sources were being screened out of a
full BART analysis based on the CAMx results.\87\
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\86\ ``Most important, the simplified chemistry in the model
tends to magnify the actual visibility effects of that source.
Because of these features and the uncertainties associated with the
model, we believe it is appropriate to use the 98th percentile--a
more robust approach that does not give undue weight to the extreme
tail of the distribution.'' 70 FR 39104, 39121.
\87\ Comment Letter from EPA Region 6 to TCEQ dated February 13,
2007 regarding TCEQ Final Report ``Screening Analysis of Potential
BART-Eligible Sources in Texas'', December 2006.
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The current version of CALPUFF approved for regulatory action was
last updated by EPA on June 29, 2007. The CALPUFF modeling system
approved at that time included CALPUFF version 5.8, level 070623,
CALMET version 5.8 level 070623, and CALPOST version 5.6394, level
070622. CALPUFF is still considered a screening model for visibility
assessments. Therefore, we followed the requirements of Appendix W for
screening models in our modeling.\88\ We conducted our modeling with
the version 5.8 suite with a few exceptions that were discussed among
modeling experts from EPA Region 6, EPA/OAQPS and FLM representatives.
Our modeling procedures were discussed more fully in our TSD.
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\88\ GAQM (2005 update) part 3.0(b), and 4.2.1.1 and 4.2.1.2.
Section 4 dealing with screening versions of modeling analyses was
updated in the 2005 GAQM notice.
---------------------------------------------------------------------------
We note that the CALPUFF Versions 6.4 and 6.112 have not been
reviewed by EPA for potential regulatory use. PNM's contractor has
indicated that a meeting was held with EPA/OAQPS representatives on
Feb. 16, 2011 and FLM representatives participated via conference call.
The commenter indicates that EPA was going to let the FLM
representatives take the lead on review and testing of the new version
of CALPUFF (6.4) and coordinate with EPA regarding this issue. Mr.
Tyler Fox, Group Leader of the Air Quality Modeling Group at EPA/OAQPS
has indicated that EPA will take the lead on the review of the new
version (CALPUFF Version 6.4) and that the new addition of a more
sophisticated chemistry mechanism is a paradigm shift in treatment of
chemistry in CALPUFF and requires additional rule making and public
review since CALPUFF was never approved for chemistry in the GAQM and
EPA is currently evaluating several models to address current modeling
needs for models that can be used for analyses of secondary formation
pollutants for ozone, PM2.5 secondary, and regional haze/
visibility impairment.\89\ At this time, EPA and the FLM
representatives are in the process of planning to move forward on
reviewing all available models to determine their suitability for these
analyses. We note that we have reviewed the materials shared at the
meeting and discussed the planned steps forward from the meeting, but
that CALPUFF Versions 6.4 and 6.112 have still not been evaluated to
determine their suitability for use in various contexts.
---------------------------------------------------------------------------
\89\ Personal communications with Mr. Tyler Fox to verify
guidance given at meeting pertaining to alternate CALPUFF versions.
July 29, 2011.
---------------------------------------------------------------------------
Based on the applicable GAQM and BART Guidelines regulations, the
combination GAQM (2005) citations (6.2.1(e) and 3.0(b)), and the BART
Guidelines outline that for any visibility modeling performed with the
CALPUFF model in a SIP, a protocol addressing procedures and analyses
should be developed with the appropriate reviewing authority and
affected FLMs. Approval of an alternate model usually includes
consultation with the modeling group at EPA/OAQPS even though ultimate
authority in most cases is the Regional Office. In the case of a SIP or
a FIP, the EPA Regional Office has the final approval decision on what
constitutes appropriate/acceptable modeling. Development of an
acceptable protocol with a Regional Office for review and approval of
an alternative model (i.e. updated model version, etc.) can be a very
significant task and could take 6 months to a year or longer to
complete a protocol that detailed submission of information for review
including model sensitivity runs, evaluation of model performance,
etc., so this can be a sizable hurdle in order for EPA to ensure that
we are basing decisions on sound science and the best tools for
actions. Approval of updated CALPUFF versions has been such a large
task that EPA/OAQPS has typically taken the lead in approval of CALPUFF
updates for regulatory use. In this case, PNM did not work out a
protocol to address any of these needed elements for EPA Region 6 to
conduct a review of PNM's proposed use of an alternate model and the
modeling results. The new versions of CALPUFF, version 6.112 or 6.4,
that the commenter used to provide modeling analyses have not gone
through a full regulatory review in accordance with 40 CFR part 51
Appendix W Section 3.2.2.
[[Page 52434]]
Furthermore, the currently available information does not support the
approval of these versions of the CALPUFF model for use in making BART
determinations. In addition, if these versions of the model were used,
EPA would have to reconsider whether using the 98th percentile impact
for determining impairment was appropriate. Therefore, EPA does not
believe the use of CALPUFF version 6.112 or 6.4 is appropriate for this
rulemaking. We believe we have made the appropriate choice in using
CALPUFF version 5.8.
Comment: The USDA Forest Service (USFS) provided comments
supporting our assumptions regarding the value of the background
ammonia (a constant 1.0 ppb concentration) used for the visibility
analysis. In contrast, PNM claims that the use of variable monthly
ammonia values ranging from 0.2 ppb in the winter months to 1.0 ppb
during the summer would better reflect the seasonal variations in
ammonia concentrations than would a constant, assumed ammonia
concentration. PNM further argued that the use of variable monthly
ammonia concentrations would still be conservative. Therefore, PNM
alleges, since a variable monthly ammonia scheme is more representative
and conservative, it should be used instead of EPA's constant ammonia
levels. PNM also claims that the use of the Ammonia Limiting Method
(ALM) is appropriate given the ``conservatism (averaging about a factor
of two) of the assumed ammonia relative to observations.'' PNM further
comments that our supporting documentation also states that
``alternative levels may be used if supported by data'' and therefore
we have no basis for criticizing the variable, monthly ammonia levels
used in the modeling prepared by PNM. PNM further comments that EPA's
decision to rely on constant high background ammonia concentrations
unjustifiably results in higher visibility improvements than expected
by PNM's more realistic modeling results.
Response: We agree and concur with the use of the 1 ppb ammonia
levels from USFS representatives. We disagree with the comments
supporting the use of variable, monthly ammonia concentrations. There
are several factors to consider with selecting the appropriate ammonia
background for estimating visibility impacts, including the length and
temporal resolution of the ammonia data collected, whether the ammonia
data varies depending on location of collection in comparison to
proximity of SJGS plumes, the fluctuation of levels throughout the
year, and the importance of plume chemistry from the point of
NOX and SO2 emissions that react with emitted and
background ammonia as the plumes transport to downwind receptors. We
have examined the available ammonia data collected, including the data
cited to in the comments.\90\ Our selection of the IWAQM Phase 2
default ammonia background constant value of 1 ppb (rather than the
variable monthly ammonia concentrations suggested by the commenter)
better represents ammonia concentrations directly around the SJGS
emission sources. The ammonia near the source that is available to
interact with the plume as it is emitted is of greater concern for
determining visibility impacts from the source due to the atmospheric
chemical reactions that occur as the pollutants and ammonia are
transported together to a Class I area. Therefore, it is more
appropriate to use a background level for ammonia that is
representative of the area around the source rather than the ammonia
levels at the isolated downwind Class I areas.
---------------------------------------------------------------------------
\90\ Sather, et al. ``Baseline ambient gaseous ammonia
concentrations in the Four Corners area and eastern Oklahoma, USA,''
Journal of Environmental Monitoring (September 2008) (``The Sather
2008 report'').
---------------------------------------------------------------------------
The pollutants emitted by the source, such as sulfate and nitrate,
will react with available ammonia present near the release point and
this ammonia and ammonia reaction products will be transported along
with the emitted pollutants to the downwind receptors. The available
monitoring data indicates that ammonia levels are higher around the
SJGS emission sources and decrease at Mesa Verde, thus supporting that
conclusion that when SJGS plumes are transported to Mesa Verde (and
other Class I areas), as expected, the SJGS emissions react with
ammonia levels near the SJGS resulting in decreasing ambient ammonia
levels downwind from the SJGS. The annual average ammonia values at the
Substation and Farmington sites, which are the passive monitor readings
that are closest to the SJGS, are above the 1 ppb levels that we have
chosen to model. This supports our decision to use a constant 1.0 ppb
ammonia value as being representative of the area around the source
rather than the ammonia levels at the isolated downwind Class I areas.
Therefore, the level we modeled is more appropriate. As discussed
originally in the TSD and also in our Complete Response to Comments for
NM Regional Haze/Visibility Transport FIP document, we have taken into
consideration the issues raised by the commenter and conferred with the
author of the 2008 Sather report, and concluded that the ammonia levels
we used in the model are appropriate.
We disagree with the use of the ALM. There is a lack of
documentation, adequate technical justification, and validation for the
development and use of the ALM. This is discussed further in a separate
response to comments.
Comment: PNM contracted with Mr. Joe Scire to review and prepare a
report on PNM's BART modeling submitted to NMED during its 2010 state
proposed rulemaking process. PNM included this Report as part of its
comments to EPA. PNM asserts that the Report confirms that PNM's
modeling was consistent with the methodology developed for CALPUFF and
it was prepared consistent with the WRAP protocol for BART modeling and
the WRAP BART modeling. The commenter argues that since EPA has
accepted the WRAP modeling and used it to support its own positions
with regard to SO2 in the proposed FIP, and given the fact
that PNM's modeling was prepared in a manner consistent with the WRAP
modeling, EPA should not need to alter PNM's modeling. Moreover, the
modeling results achieved by us are merely a function of our modeling
methods, not true differences in visibility impacts.
In addition to the commenter's position that the PNM modeling was
conducted appropriately, PNM claims that the Report shows more recent
developments in modeling science and chemistry could be used to make a
more accurate and realistic prediction of the visibility improvements
that might result from installing SCRs at SJGS. The recommendations
included modeling results from the use of (1) two updated CALPUFF
models, Ver. 6.112 and a version with updated chemistry (Ver. 6.4); (2)
a refined modeling grid (1 km versus 4 km), and (3) Ammonia Limiting
Method (ALM). PNM claims use of the ALM would take into account the
spatial variations of background ammonia concentrations and account for
the consumption of background ammonia by background sources of sulfate
and nitrate; and that modeling at a higher resolution of 1 km (compared
to 4 km) is better, to ``better represent the wind flow in a complex
terrain regime.'' Using these modeling techniques, PNM argues that
these alternate modeling results show that the greatest visibility
improvement that could be achieved at any Class I area by installing
SCRs at SJGS would be less than 0.5 dv per unit, and thus less than
what a human could perceive.
Response: The commenter indicates that we used the WRAP
photochemical
[[Page 52435]]
modeling to support our action on SO2 controls and from
this, somehow concludes we should accept PNM's BART CALPUFF visibility
modeling, allegedly consistent with WRAP protocols for assessing the
visibility impacts of SJGS. In this instance, the commenter appears to
confuse two types of modeling. As we discuss elsewhere in this notice,
we did rely on the WRAP's photochemical modeling in considering whether
New Mexico sources, specifically SJGS, interfered with other States'
visibility plans. The WRAP's CALPUFF screening modeling was used to
determine which BART-eligible sources were subject to BART. As a result
of the WRAP CALPUFF screening modeling, New Mexico identified one
source subject to BART and, as discussed elsewhere, projected emission
reductions that were relied upon by the WRAP in their photochemical
modeling. The photochemical modeling was used to consider the emissions
from all sources in the regions and was used to establish the
reasonable progress goals for the WRAP States. The source-specific
CALPUFF visibility modeling, on the other hand, requires a site
specific modeling approach designed to evaluate visibility impacts to
inform decisions in a BART determination for a specific source. Our
CALPUFF visibility modeling, performed using an accepted CALPUFF model
version and following applicable guidance and EPA/FLM recommendations,
showed significant visibility benefits due to the use of SCR as
NOX BART at SJGS.
As discussed elsewhere, since NMED was previously proposing to
install the most stringent controls, we did not raise some of our
concerns with past modeling, since the BART guidelines allow some
flexibility in the need to conduct modeling when the most stringent
controls are being required. In our review of PNM's earlier BART
CALPUFF visibility modeling, we did note some inconsistencies between
PNM's CALPUFF modeling protocol and the EPA approved modeling
techniques for source-specific modeling to support a BART
determination. As stated in the TSD that accompanied our proposal,
however, we agree with the commenter that the PNM CALPUFF modeling
generally followed the BART protocol for BART screening analyses
developed by the WRAP.\91\ After the WRAP CALPUFF screening modeling
had been generated, some problems with the changes from the previous
CALPUFF modeling system that were included in CALPUFF Version 6.211 and
another version referred to as the ``VISTAS version'' had been
identified.\92\ Version 6.211 has been found to set up situations where
the boundary layer could artificially collapse creating unrealistic
meteorological conditions and significantly impacting the modeled
dispersion (refer to the TSD for additional details). This assessment
leads to EPA's approval of CALPUFF 5.8 as the approved version,
announced on June 29, 2007. Furthermore, PNM did not consult with
Region 6 to establish a protocol for additional CALPUFF modeling as
part of the BART visibility analyses, and while they chose to generally
follow the protocol developed by the WRAP specifically for BART
screening analyses, PNM deviated in some ways. In addition, a site
specific protocol for SJGS should have included additional refinements
in model settings and incorporation of data. We specifically noted
several deviations from appropriate practice in PNM's implementation of
the meteorological processing model for CALPUFF, named CALMET, in
addition to model versions issues. PNM's CALMET modeling utilized radii
of influence values inconsistent with EPA/FLM guidance, and did not
follow the EPA/FLM guidance about including upper air observational
data. Finally, the CALPUFF modeling system (including CALMET) versions
used by PNM did not follow EPA and FLM recommendations and guidance.
NMED received comment on not being consistent with established BART
modeling procedures from the FLM's during the proposed 308 SIP in
August 2010. PNM has also alleged that variable ammonia concentrations
should be used, which is inconsistent with the WRAP's BART screening
protocol and modeling. Furthermore, NMED specifically requested that
PNM perform modeling using the default constant 1 ppb background
ammonia concentration on multiple occasions in 2008 as they were
developing the proposed RH SIP. These numerous deviations from our
guidance methods and procedures and use of an alternate model version
were not considered by the commenter. These deviations are discussed
further in the Technical Support Document that accompanied our
proposal.
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\91\ CALMET/CALPUFF Protocol for BART Exemption Screening
Analysis for Class I Areas in the Western United States (August 15,
2006; available at: http://pah.cert.ucr.edu/aqm/308/bart/WRAP_RMC_BART_Protocol_Aug15_2006.pdf * * *).
\92\ ``CALPUFF: Status and Update,'' Dennis Atkinson,
Presentation at Regional/State/Local Modelers Workshop, May 16,
2007. (http://www.cleanairinfo.com/
regionalstatelocalmodelingworkshop/archive/2007/presentations/
Wednesday%20[dash]%20May%2016%202007/CALPUFF--status--update.pdf);
EPA report, ``Assessment of the ``VISTAS'' Version of the CALPUFF
Modeling System,'' EPA-454/R-08-007, August 2008 available at
(http://www.epa.gov/ttn/scram/reports/calpuff_vistas_assessment_report_final.pdf); ``CALPUFF Regulatory Update,'' Roger W. Brode,
Presentation at Regional/State/Local Modelers Workshop, June 10-12,
2008, available at (http://www.cleanairinfo.com/regionalstatelocalmodelingworkshop/archive/2008/presentations/BRODE_CA.pdf).
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As discussed in section 4.3.1 and table 4-6 of the TSD, our
sensitivity modeling results support the conclusion that the
differences between the WRAP BART screening protocol and our current
regulatory approach would not likely change the original determination
by the WRAP and NMED of which sources screen out of BART and which are
subject to a full BART analysis. We disagree, however, that PNM's
modeling was acceptable modeling for evaluating the visibility impacts
to inform a BART determination. It would have been inappropriate for us
to use a CALPUFF model version with known problems/errors to support
our proposed BART determination instead of using the CALPUFF version we
approved for regulatory review. Therefore, our BART CALPUFF visibility
modeling sought to correct the deficiencies in the PNM BART CALPUFF
visibility modeling. In addition, given that the emission rates that we
proposed as NOX BART differed from those used in PNM and
NMED's BART visibility modeling, it was necessary to perform our
CALPUFF visibility modeling, following EPA/FLM guidance and practices,
to assess the anticipated visibility improvements from the use of SCR
with our proposed BART lower emission rate of 0.05 lb of
NOX/MMBtu (NMED/PNM modeling used an emission rate of 0.07
lb of NOX/MMBtu for SCR). As discussed in the TSD, we also
had updated emission estimates for sulfuric acid emissions based on the
latest information that was included in our modeling. We therefore
disagree with the commenter and have explained why we needed to do our
own BART CALPUFF visibility analysis. We used the approved version of
the model in accordance with the appropriate procedures, as discussed
further in other response to comments and we are confident in using our
results as one of the five factors in making a BART determination. The
commenter did not provide any direct comments indicating that our BART
visibility modeling differed in any way from EPA and FLM modeling
guidance and standard practices that EPA and the FLM representatives
have approved in other protocols.
With regard to the commenter's suggestion that more recent versions
of
[[Page 52436]]
CALPUFF be used, as discussed in more detail in another response, the
two suggested model versions have not gone through the appropriate
review to assess if they are founded in appropriate science and perform
adequately and reliably and are an improvement to the current version
that is acceptable for regulatory actions. PNM did not submit the
modeling files as part of its comments. Instead, the PNM submitted
report only includes a summary of the modeling results. Therefore,
sufficient evidence has not been presented to support PNM's claims had
we wished to review this modeling done with non-approved models.
Because the model results provided by the commenter cannot be evaluated
and because we have no basis to conclude that these versions provide
reliable results, we did not conduct a full review of the submitted
summary of the model output results. In looking over the summary of the
modeling results in the submitted report, however, we continue to have
significant concerns with the model version and options/inputs used
given that the results are indicating drastically lower values than our
modeling that was conducted with CALPUFF Version 5.8.
We disagree with the use of a higher grid-resolution (1-km) for
modeling of visibility impacts using the CALPUFF modeling system.
Current EPA guidance from the May 15, 2009 EPA Model Clearinghouse
memorandum defaults to a horizontal grid resolution of 4-km. While this
guidance does not automatically preclude the use of higher resolution
meteorological fields, the memorandum discusses five issues that should
be addressed in considering use of a 1-km meteorological grid. None of
these five elements were addressed by the commenter. Among the elements
that should have been considered were a discussion of the nature of
SJGS's source-receptor relationship to Class I areas in the modeling
domain and meteorological characteristics which govern these source-
receptor relationships, a statistical performance analysis showing the
inadequacy of the 4-km CALMET fields, demonstration of the technical
adequacy of CALMET diagnostic algorithms in a complex terrain
situation, statistical evaluation demonstrating that 1-km CALMET fields
perform better than 4-km fields in this specific situation, and
discussion of how the enhanced resolution impacts the air quality
model. When CALMET is using much higher grid resolutions, such as 1-km
grid, on the original Numerical Weather Prediction files, the CALMET
meteorological model performance must be examined through appropriate
statistical analysis to understand if the CALMET diagnostic adjustments
perform appropriately. The Report presented no evidence to support the
claim that a 1-km resolution increases the accuracy of the final wind
field in specifically modeling the SJGS. The commenter has not provided
any statistical or other analyses to justify such a deviation for
modeling of the SJGS. Consistent with EPA-FLM recommendations for
CALMET and the WRAP BART screening modeling protocol, we determined
that a 4-km grid resolution should be used.
We also disagree with the use of the Ammonia Limit Method which is
also called ALM and note that it is inconsistent with the nitrate
repartitioning approach that has been previously accepted by the FLMs
and EPA. There is a lack of documentation, adequate technical
justification, and validation for the development and use of the ALM.
We and the FLMs have previously reviewed protocols proposing using ALM
and we and/or the FLMs have not approved the use of the proposed ALM
procedure. In general terms, one of the key issues is ALM is a method
to have emissions from other sources consume ammonia, so there is less
ammonia to react with the source of interest being modeled. Since
ammonia levels from the local area around the plant were used by EPA,
to do calculations in the modeling to consume ammonia from surrounding
sources would unnaturally consume ammonia that was actually monitored
in the vicinity of the SJGS. The ALM has not been approved by EPA and
the FLMs through interagency workgroups (IWAQM or FLAG) as an approved
part of CALPUFF based visibility analyses. The commenter has not
provided any adequate justification, documentation, or other analyses
to justify the proposed use of ALM.
Furthermore, the use of ALM requires the input of background
ammonia concentrations as well as background concentrations of sulfate,
nitrate, and nitric acid. The commenter used background concentrations
derived from modeling simulations of the EPA Community Multiscale Air
Quality Modeling System (CMAQ) for 2002. The Report's summary shows
that monthly averages of predicted concentrations for ammonia, sulfate,
nitrate, and nitric acid at a grid resolution of 36 km were used as
model inputs to apply the ALM. As discussed in a separate response to
comments, available ammonia monitor data indicates that ammonia
concentrations are higher in the vicinity of the SJGS and city of
Farmington than at the Mesa Verde Class I area (approximately 42 km
from SJGS). The use of 36 km resolution model predictions results in an
average ammonia level for the entire 36km by 36 km grid cell and does
not reflect the higher ammonia concentrations measured near the SJGS
which are of greater concern for determining visibility impacts from
the source. In addition, the CMAQ model predictions that the commenter
used are not an appropriate estimation of background ammonia available
for reaction with the SJGS emissions since this CMAQ simulation of
``background'' concentrations already includes SJGS emissions and
reactions they have in the atmosphere. The background ammonia
concentration that the commenter input into the non-approved CALPUFF
model has already been decreased by reaction with SJGS emissions in the
CMAQ model predictions.
The commenter also provided a summary of the modeling results based
on variable ammonia levels using CALPUFF version 6.112 and 6.4. We
disagree with the use of variable ammonia as we have responded to
comments about using variable ammonia levels in another response to
comment. We note that variable ammonia levels were not approved in the
WRAP's BART screening modeling protocol, nor in protocols by NMED in
their 2010 proposal, nor by EPA Region 6 as the commenter seemed to
indicate in their comment.
We note that the summary of the report's BART visibility modeling
results shows that an SCR emission rate of 0.07 lb/MMBtu was used,
rather than the 0.05 lb/MMBtu that we included in our proposal. Using
this higher level of 0.07 lb/MMBtu would bias the reduction in impacts
from the installation of SCR lower than what we proposed. If their
modeling was conducted using our proposed emission rate, it may have
shown a value greater than 0.5 dv for each individual unit. This is not
relevant though given the numerous issues associated with their
modeling analysis as discussed above. Moreover, as noted in the BART
Guidelines, the CALPUFF model results are useful for considering the
comparative impacts of single sources on visibility impairment in a
relative sense and relative to other sources, SJGS's impacts are
significant. We note that the SJGS is one of the single largest sources
of NOX in the United States and located close to 16 Class I
areas. As such, even without modeling results, one could conclude that
the source is likely to contribute to significant visibility impacts at
multiple Class I
[[Page 52437]]
areas and that the installation of SCR would lead to meaningful
visibility benefits. We also note that our modeling looked at the dv
improvements at 16 Class I areas and indicates even greater visibility
benefits at other Class I areas than Mesa Verde. The summary of the
modeling results provided by the commenter do not evaluate improvements
at other Class I areas or any cumulative visibility improvement
benefits of SCR, yet they asserted that their analysis showed the
maximum impacts from SCR at any Class I area. As we note elsewhere, we
actually projected the largest visibility improvement due to SCR
control level at the Canyonlands Class I area. As a result, there is no
evidence to support the commenter's claim that the largest improvement
was less than 0.5 dv at any Class I area. Given the relative size of
SJGS and its location as compared to other BART sources, such results
would be surprising. We conclude that our modeling which was performed
using an accepted CALPUFF model version and following applicable
guidance and EPA/FLM recommendations is an appropriate approach for
assessing the visibility benefits due to the use of SCR. This modeling
confirmed that our NOX BART determination will result in
significant visibility benefits.
Comment: A commenter alleged that EPA lacks the requisite statutory
authorization in this proceeding to implement its proposed emission
limits for H2SO4 and NH3 emissions
from the SJGS. The commenter indicated that if EPA has not shown that
limits on emissions of H2SO4 and NH3
from the SJGS will result in reduced visibility impairment or make
reasonable progress in a class I area's Reasonable Progress Goal, the
Agency has no authority under CAA Sec. 169A to require the proposed
emission limits on those pollutants from SJGS. The commenter also
alleged that if EPA has not shown interference from
H2SO4 or NH3 emissions, EPA has no
authority to regulate these pollutants under CAA section
110(a)(2)(D)(i)(II). EPA has not shown that its conclusory statement
that the proposed limits will ``minimize the contribution of these
compounds to visibility impairment'' falls short of demonstrating a
visibility-impairment contribution that is necessary to authorize
regulation of those compounds under Section 169A.
The commenter indicated that if EPA has no other policy reason
other than appropriate considerations of comity, EPA should defer to
New Mexico's determination of which pollutants to regulate with BART
requirements. The commenter noted that New Mexico's proposed regional
haze SIP under section 309 of 40 CFR part 51 and the withdrawn regional
haze SIP proposal under section 308 both demonstrates the State's
intent to regulate regional haze during the first planning period with
controls only on emissions of SO2, NOX and PM.
The commenter concluded that any proposal by EPA to limit emissions of
either H2SO4 or NH3 from New Mexico
sources goes beyond the planned scope of the State's regional haze SIP
and should be abandoned. The commenter also indicated it is unclear
from EPA's proposal if its action is being proposed under CAA section
110(a)(2)(D)(i)(II) as an Interstate Transport provision related to
visibility, id., or instead under CAA section 169a as part of a BART
determination for the SJGS.
Response: For the reasons discussed elsewhere in our response to
comments, we have determined that neither an ammonia limit nor ammonia
monitoring requirements are appropriate. The design plans for the SCRs
that will be submitted will address design and operation of SCRs based
on a maximum ammonia slip level of 2 ppm. Proper design and operation
of the SCR should be protective of visibility impairment modeling
projections. We disagree with the commenter concerning the need to
regulate H2SO4. If a power plant is installing
SCR at an existing facility in an area where a state has a concern
about PM2.5 and regional haze impacts, it would be normal
for a state to consider the imposition of limits on
H2SO4 to minimize/limit the amount of degradation
in visibility due to any increases in these pollutants.
As we discussed in our proposal, we have concluded that the low
sulfur coal burned at the SJGS generates very little sulfur trioxide
(SO3), and hence H2SO4, which is
formed when SO3 combines with water in the flue gas to form
H2SO4. In addition, SCR catalysts are available
with a low SO2 to SO3 conversion of 0.5%, further
limiting the production of H2SO4. Nevertheless,
we conducted several modeling runs with different
H2SO4 emission levels and that modeling indicated
that increases in H2SO4 did result in some
visibility degradation at Class I areas in New Mexico and surrounding
states. The H2SO4 runs can be found in the TSD
and its appendices or in the RTC for this action. Some of the
H2SO4 runs were not used in the final decision
modeling analysis, but provided a basis for being concerned about
potential H2SO4 impacts and thus limiting the
amount of growth in H2SO4 from our action.
In summary, we conclude that emissions of
H2SO4 will not be a significant concern at the
SJGS. However, modeling conducted by us and some modeling results
provided by PNM's contractors indicate that visibility impairment could
worsen if emissions of H2SO4 are not limited in
an enforceable manner. We do not wish to allow a growth in emissions to
occur that would undermine the NOX reductions that we are
requiring to ensure that NM emission sources do not interfere with
visibility in other states as required by the 110(a)(2)(D)(i)(II).
Therefore, we believe we have struck the right balance in limiting
emissions of H2SO4 to a reasonable level verified
by annual stack testing. We are controlling H2SO4
under the BART provisions of the RHR and CAA Section 110. Our
regulatory authority includes CAA section 169A(b)(2), 40 CFR
51.308(e)(1)(ii) and CAA section 110(a)(2)(D)(i)(II).
IV. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
This action is not a ``significant regulatory action'' under the
terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is
therefore not subject to review under Executive Orders 12866 and 13563
(76 FR 3821, January 21, 2011). This action finalizes a source-specific
FIP for the San Juan Power Generating Station (SJGS) in New Mexico.
B. Paperwork Reduction Act
This action does not impose an information collection burden under
the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq.
Under the Paperwork Reduction Act, a ``collection of information'' is
defined as a requirement for ``answers to * * * identical reporting or
recordkeeping requirements imposed on ten or more persons * * *'' 44
U.S.C. 3502(3)(A). Because the FIP applies to a single facility,
(SJGS), the Paperwork Reduction Act does not apply. See 5 CFR 1320(c).
Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a Federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any
[[Page 52438]]
previously applicable instructions and requirements; train personnel to
be able to respond to a collection of information; search data sources;
complete and review the collection of information; and transmit or
otherwise disclose the information.
An agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for our
regulations in 40 CFR are listed in 40 CFR part 9.
C. Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of today's rule on small
entities, small entity is defined as: (1) A small business as defined
by the Small Business Administration's (SBA) regulations at 13 CFR
121.201; (2) a small governmental jurisdiction that is a government of
a city, county, town, school district or special district with a
population of less than 50,000; and (3) a small organization that is
any not-for-profit enterprise which is independently owned and operated
and is not dominant in its field.
After considering the economic impacts of this action on small
entities, EPA certifies that this action will not have a significant
economic impact on a substantial number of small entities. The FIP for
SJGS being finalized today does not impose any new requirements on
small entities. See Mid-Tex Electric Cooperative, Inc. v. FERC, 773
F.2d 327 (DC Cir. 1985).
D. Unfunded Mandates Reform Act (UMRA)
This rule does not contain a Federal mandate that may result in
expenditures of $100 million or more for State, local, and tribal
governments, in the aggregate, or the private sector in any one year.
Our cost estimate indicates that the total annual cost of compliance
with this rule is below this threshold. Thus, this rule is not subject
to the requirements of sections 202 or 205 of UMRA.
This rule is also not subject to the requirements of section 203 of
UMRA because it contains no regulatory requirements that might
significantly or uniquely affect small governments. This rule contains
regulatory requirements that apply only to the San Juan Power
Generating Station (SJGS) in New Mexico.
E. Executive Order 13132: Federalism
This action does not have federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various levels of government, as
specified in Executive Order 13132. This action merely prescribes EPA's
action to address the State not fully meeting its obligation to
prohibit emissions from interfering with other states measures to
protect visibility. Thus, Executive Order 13132 does not apply to this
action. In the spirit of Executive Order 13132, and consistent with EPA
policy to promote communications between EPA and State and local
governments, EPA specifically solicited comment on the proposed rule
from State and local officials.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This rule does not have tribal implications as specified by
Executive Order 13175 (65 FR 67249, November 9, 2000), because the rule
neither imposes substantial direct compliance costs on tribal
governments, nor preempts tribal law. Therefore, the requirements of
section 5(b) and 5(c) of the Executive Order do not apply to this rule.
However, consistent with EPA policy, EPA consulted with one Tribe on
this action.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying
only to those regulatory actions that concern health or safety risks,
such that the analysis required under section 5-501 of the EO has the
potential to influence the regulation. This action is not subject to EO
13045 because it implements specific standards established by Congress
in statutes.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This action is not subject to Executive Order 13211 (66 FR 28355
(May 22, 2001)), because it is not a significant regulatory action
under Executive Order 12866.
I. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (``NTTAA''), Public Law 104-113, 12(d) (15 U.S.C. 272 note)
directs EPA to use voluntary consensus standards in its regulatory
activities unless to do so would be inconsistent with applicable law or
otherwise impractical. Voluntary consensus standards are technical
standards (e.g., materials specifications, test methods, sampling
procedures, and business practices) that are developed or adopted by
voluntary consensus standards bodies. NTTAA directs EPA to provide
Congress, through OMB, explanations when the Agency decides not to use
available and applicable voluntary consensus standards. This rule would
require the affected units at SJGS to meet the applicable monitoring
requirements of 40 CFR part 75. Part 75 already incorporates a number
of voluntary consensus standards. Consistent with the Agency's
Performance Based Measurement System (PBMS), Part 75 sets forth
performance criteria that allow the use of alternative methods to the
ones set forth in part 75. The PBMS approach is intended to be more
flexible and cost effective for the regulated community; it is also
intended to encourage innovation in analytical technology and improved
data quality. At this time, EPA is not recommending any revisions to
part 75; however, EPA periodically revises the test procedures set
forth in part 75. When EPA revises the test procedures set forth in
part 75 in the future, EPA will address the use of any new voluntary
consensus standards that are equivalent. Currently, even if a test
procedure is not set forth in part 75, EPA is not precluding the use of
any method, whether it constitutes a voluntary consensus standard or
not, as long as it meets the performance criteria specified; however,
any alternative methods must be approved through the petition process
under 40 CFR 75.66 before they are used.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629, February 16, 1994), establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
[[Page 52439]]
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
EPA has determined that this rule will not have disproportionately
high and adverse human health or environmental effects on minority or
low-income populations because it increases the level of environmental
protection for all affected populations without having any
disproportionately high and adverse human health or environmental
effects on any population, including any minority or low-income
population. This rule limits emissions of pollutants from a single
stationary source, the SJGS.
K. Congressional Review Act
The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
United States. EPA will submit a report containing this action and
other required information to the U.S. Senate, the U.S. House of
Representatives, and the Comptroller General of the United States prior
to publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is not a ``major rule'' as defined by 5 U.S.C.
804(2). This rule will be effective on September 21, 2011.
L. Judicial Review
Under section 307(b)(1) of the CAA, petitions for judicial review
of this action must be filed in the United States Court of Appeals for
the appropriate circuit by October 21, 2011. Pursuant to CAA section
307(d)(1)(B), this action is subject to the requirements of CAA section
307(d) as it promulgates a FIP under CAA section 110(c). Filing a
petition for reconsideration by the Administrator of this final rule
does not affect the finality of this action for the purposes of
judicial review nor does it extend the time within which a petition for
judicial review may be filed, and shall not postpone the effectiveness
of such rule or action. This action may not be challenged later in
proceedings to enforce its requirements. See CAA section 307(b)(2).
List of Subjects in 40 CFR Part 52
Environmental protection, Air pollution control, Best available
control technology. Incorporation by reference, Intergovernmental
relations, Interstate transport of pollution, Nitrogen dioxide, Ozone,
Particulate matter, Regional haze, Reporting and recordkeeping
requirements, Sulfur dioxide, Visibility.
Dated: August 4, 2011.
Lisa P. Jackson,
Administrator.
For the reasons set out in the preamble, title 40, chapter I, of
the Code of Federal Regulations is amended as follows:
PART 52--[AMENDED]
0
1. The authority citation for part 52 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
Subpart GG--[Amended]
0
2. Section 52.1628 is added to read as follows:
Sec. 52.1628 Interstate pollutant transport and regional haze
provisions; what are the FIP requirements for San Juan Generating
Station emissions affecting visibility?
(a) Applicability. The provisions of this section shall apply to
each owner or operator of the coal burning equipment designated as
Units 1, 2, 3, or 4 at the San Juan Generating Station in San Juan
County, New Mexico (the plant).
(b) Compliance Dates. (1) Compliance with the requirements of this
section is required by:
(i) SO2: No later than 5 years after September 21, 2011.
(ii) NOX: No later than 5 years after September 21,
2011.
(iii) H2SO4: No later than 5 years after
September 21, 2011.
(2) On and after the compliance date of this rule, no owner or
operator shall discharge or cause the discharge of NOX,
SO2, or H2SO4 into the atmosphere from
Units 1, 2, 3 and 4 in excess of the limits for these pollutants.
(c) Definitions. All terms used in this part but not defined herein
shall have the meaning given them in the CAA and in parts 51 and 60 of
this chapter. For the purposes of this section:
24-hour period means the period of time between 12:01 a.m. and 12
midnight.
Air pollution control equipment includes baghouses, particulate or
gaseous scrubbers, and any other apparatus utilized to control
emissions of regulated air contaminants which would be emitted to the
atmosphere.
Boiler-operating-day means any 24-hour period between 12:00
midnight and the following midnight during which any fuel is combusted
at any time at the steam generating unit.
Heat input means heat derived from combustion of fuel in a unit and
does not include the heat input from preheated combustion air,
recirculated flue gases, or exhaust gases from other sources. Heat
input shall be calculated in accordance with part 75 of this chapter,
using data from certified O2 and stack gas flow rate
monitors.
Owner or Operator means any person who owns, leases, operates,
controls, or supervises the plant or any of the coal burning equipment
designated as Units 1, 2, 3, or 4 at the plant.
Oxides of nitrogen (NOX) means all oxides of nitrogen except
nitrous oxide, as measured by test methods set forth in 40 CFR part 60.
Regional Administrator means the Regional Administrator of EPA
Region 6 or his/her authorized representative.
(d) Emissions Limitations and Control Measures. (1) Within 180 days
of September 21, 2011, the owner or operator shall submit a plan to the
Regional Administrator that identifies the air pollution control
equipment and schedule for complying with paragraph (d) of this
section. The NOX control device included in this plan shall
be designed to meet the NOX emission rate limit identified
in paragraph (d) of this section with an ammonia slip of no greater
than 2.0 ppm. The owner or operator shall submit amendments to the plan
to the Regional Administrator as changes occur.
(2) NOX emission rate limit. The NOX emission rate limit
for each unit in the plant, expressed as nitrogen dioxide
(NO2), shall be 0.05 pounds per million British thermal
units (lbs/MMBtu), as averaged over a rolling 30 boiler-operating-day
period. The hourly NOX and O2 data used to
determine the NOX emission rates shall be in compliance with
the requirements in part 75 of this chapter. For each unit on each
boiler-operating-day, the hourly NOX emissions measured in
lbs/MMBtu, shall be averaged over the hours the unit was in operation
to obtain a daily boiler-operating-day average. Each day, the 30-day-
rolling average NOX emission rate for each unit (in lbs/
MMBtu) shall be determined by averaging the daily boiler-operating-day
average emission rate from that day and those from the preceding 29
days.
(3) SO2 emission rate limit. The SO2 emission rate limit
for each unit in the plant shall be 0.15 pounds per million British
thermal units (lbs/MMBtu), as averaged over a rolling 30 boiler-
operating-day period. The hourly NOX and O2 data
used to determine the NOX emission rates shall be in
compliance with the requirements in part 75 of this chapter. For each
unit on each boiler-
[[Page 52440]]
operating-day, the hourly SO2 emissions measured in lbs/
MMBtu, shall be averaged over the hours the unit was in operation to
obtain a daily boiler-operating-day average. Each day, the 30-day-
rolling average SO2 emission rate for each unit (in lbs/
MMBtu) shall be determined by averaging the daily boiler-operating-day
average emission rate from that day and those from the preceding 29
days.
(4) Sulfuric Acid (H2SO4) emission rate limit: Emissions of
H2SO4 from each unit shall be limited to 2.6 x
10-\4\ lb/MMBtu on an hourly basis.
(e) Testing and monitoring. Notwithstanding any language to the
contrary, the paragraphs in this section apply at all times to Units 1,
2, 3, and 4 at the plant.
(1) By the applicable compliance date in paragraph (b) of this
section, the owner or operator shall install, calibrate, maintain and
operate Continuous Emissions Monitoring Systems (CEMS) for
NOX, SO2, stack gas flow rate, and O2
on Units 1, 2, 3, and 4 in accordance with part 75 of this chapter. The
owner or operator shall also comply with the applicable quality
assurance procedures in part 75 of this chapter for these CEMS.
Continuous monitoring systems for NOX, SO2, stack
gas flow rate, and O2 that have been certified for use under
the Acid Rain Program, and that are continuing to meet the on-going
quality-assurance requirements of that program, satisfy the
requirements of this paragraph (e)(1). Compliance with the emission
limits for NOX and SO2 shall be determined by
using data from these CEMS.
(2) The CEMS required by this rule shall be in continuous operation
during all periods of operation of the coal burning equipment,
including periods of startup, shutdown, and malfunction, except for
CEMS breakdowns, repairs, calibration checks, and zero and span
adjustments. Continuous monitoring systems for measuring
SO2, NOX, and O2 shall complete a
minimum of one cycle of operation (sampling, analyzing, and data
recording) for each successive 15-minute period. Hourly averages shall
be computed using at least one data point in each fifteen minute
quadrant of an hour. Notwithstanding this requirement, an hourly
average may be computed from at least two data points separated by a
minimum of 15 minutes (where the unit operates for more than one
quadrant in an hour) if data are unavailable as a result of performance
of calibration, quality assurance, preventive maintenance activities,
or backups of data from data acquisition and handling system, and
recertification events. Each required CEMS must obtain valid data for
at least 90.0 percent of the unit operating hours, on an annual basis.
(3) Emissions of H2SO4 shall be measured
within 180 days of start up of the NOX control device and
annually thereafter using EPA Test Method 8A (CTM-013).
Note to paragraph (e)(3): EPA Test Method 8A is available at:
http://www.epa.gov/ttn/emc/ctm/ctm-013.pdf.
(f) Reporting and Recordkeeping Requirements. Unless otherwise
stated all requests, reports, submittals, notifications, and other
communications to the Regional Administrator required by this section
shall be submitted, unless instructed otherwise, to the Director,
Multimedia Planning and Permitting Division, U.S. Environmental
Protection Agency, Region 6, to the attention of Mail Code: 6PD, at
1445 Ross Avenue, Suite 1200, Dallas, Texas 75202-2733.
(1) The owner or operator shall keep records of all CEMS data,
stack test data, and CEMS quality-assurance tests required under this
section for a period of at least 3 years.
(2) For each unit subject to the emission limitations for
SO2, and NOX, in this section, the owner or
operator shall comply with the excess emission reporting requirements
in Sec. Sec. 60.7(c) and (d) of this chapter, on a semiannual basis,
unless more frequent (e.g., quarterly) reporting is requested by the
Regional Administrator. For SO2 and NOX, any day
on which the 30-day rolling average emission limit in paragraph (d) of
this section is not met shall be counted as an excess emissions day.
The duration of the excess emissions period shall be the number of unit
operating hours on that day. Any hour in which a CEMS is out-of-service
(excluding hours in which required calibrations and QA tests are
performed) shall be counted as an hour of monitor downtime.
(g) Equipment Operations. At all times, including periods of
startup, shutdown, and malfunction, the owner or operator shall, to the
extent practicable, maintain and operate the unit including associated
air pollution control equipment in a manner consistent with good air
pollution control practices for minimizing emissions. Determination of
whether acceptable operating and maintenance procedures are being used
will be based on information available to the Regional Administrator
which may include, but is not limited to, monitoring results, review of
operating and maintenance procedures, and inspection of the unit.
(h) Enforcement. (1) Notwithstanding any other provision in this
implementation plan, any credible evidence or information relevant as
to whether the unit would have been in compliance with applicable
requirements if the appropriate performance or compliance test had been
performed, can be used to establish whether or not the owner or
operator has violated or is in violation of any standard or applicable
emission limit in the plan.
(2) Emissions in excess of the level of the applicable emission
limit or requirement that occur due to a malfunction shall constitute a
violation of the applicable emission limit.
0
3. Section 52.1629 is added to read as follows:
Sec. 52.1629 Visibility protection.
The portion of the State Implementation Plan revision received on
September 17, 2007, from the State of New Mexico for the purpose of
addressing the visibility requirements of Clean Air Act section
110(a)(2)(D)(i)(II) for the 1997 8-hour ozone and the 1997 fine
particulate matter National Ambient Air Quality Standards is
disapproved.
[FR Doc. 2011-20682 Filed 8-19-11; 8:45 am]
BILLING CODE 6560-50-P