Appendix — Nat'l Mining Ass'n v. Envtl. Prot. Agency, 135 S. Ct. 703 (2014) (No. 14-49)
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14- 49
No. 14-___
IN THE
Supreme Court of the Anited States
NATIONAL MINING ASSOCIATION, PETITIONER
Vv.
ENVIRONMENTAL PROTECTION AGENCY, RESPONDENT
Se ee
ON PETITION FOR WRIT OF CERTIORARI TO THE
UNITED STATES COURT OF APPEALS FOR THE DISTRICT
OF COLUMBIA CIRCUIT
PETITION FOR A WRIT OF CERTIORARI
VOLUME 2 of 4
CARROLL W. MCGUFFEY III PETER S. GLASER
JUSTIN WONG (Counsel of Record)
TROUTMAN SANDERS LLP TROUTMAN SANDERS LLP
600 PEACHTREE STREET, NE 401 NINTH STREET N.W.
SUITE 5200 SUITE 1000
ATLAN14, GA 30308-2216 WASHINGTON, D.C. 20004
202-274-2998
Peter.glaser
@troutmansanders.com
duly 14, 2014 Counsel of Petitioner
Gauson- Eres Pravina CO, Inc. — (202) 789-0096 — WaSHinGTON,D C 20002
New-—Liquid oil—
continental
New-—Liquid oil—
non-
continental
We are also finalizing alternate equivalent emission
standards (for certain subcategories) to the final
surrogate standards in three areas: SO: (for HCl),
483a
Table 4--Emission Limitations for
Filterable
particulate
matter
3.0E-2
lb/MMBtu
(3.0E-1
Ib/MWh)
3.0E-2
Ib/MMBtu
(3.0E-1
Ib/MWh)
7.0E-2
lb/MWh
2.0E-1
lb/MWh
Liquid Oil-Fired EGUs
Hydrogen
chloride
2.0E-3
Ib/MMBtu
(1.0E-2
lb/MWh)
2.0E-4
lb/MMBtu
(2.0E-3
Ib/MWh)
4.0E-4
lb/MWh
2.0E-3
IhyMWh
Hydrogen
fluoride
4.0E-4
lb/MMBtu.
(4.0E-3
lb/MWh).
6.0E-5
Ib/MMBtu.
(5.0E-4
Ib/MWh).
4.0E-4
lb/MWh.
5.0E-4
Ib/MWh.
individual non-mercury metals and total non-mercury
metals (for filterable PM) from coal- and solid oil-
derived fuel-fired EGUs, and individual and total
metals (for filterable PM) from oil-fired EGUs. The
final alternate emission limitations are provided in
Tables 5 and 6 of this preamble.
Subcatego Coal-
ry/
Pollutant
SO[2)}
Cadmium,
fired
EGUs
484a
Table 5—Alternate Emission Limitations for
IGCC
NA
Liquid
oil,
continent
al
NA
Existing Coal- and Oil-Fired EGUs
Liquid
oil,
non-
continent
al
NA
Solid oil-
derived
Existing Coal- and Oil-Fired EGUs
Subcatego
ry/
Pollutant
Chromium
Cr
Cobalt, Co
Lead, Pb
Nickel, Ni
Coal-
fired
EGUs
2.8E0
Ib/TBtu
(3.0E-2
lb/GWh)
8.0E-1
lb/TBtu
(8.0E-3
lb/GWh)
1.2E0
lb/TBtu
(2.0E-2
Ib/GWh)
4.0E0
lb/TBtu
(5.0E-2
Ib/GWh
NA
3.5E0
Ib/TBtu
(4.0E-2
Ib/GWh)
5.0E0
lb/TBtu
(6.0E-2
485a
Table 5—-Alternate Emission Limitations for
IGCC
2.9E0
lb/TBtu
(3.0E-2
lb/GWh)
1.2E0
lb/TBtu
(2.0E-2
Ib/GWh)
1.9E+2
lb/MMB
tu
(1.8E0
Ib/MWh)
2.5E0
lb/TBtu
(3.0E-2
Ib/GWh)
NA
6.5E0
lb/TBtu
(7.0E-2
lb/GWh)
2.2E+1
Ib/TBtu
(3.0E-1
Liquid
oil,
continent
al
5.5E0
Ib/TBtu
(6.0E-2
lb/GWh)
2.1E+1
lb/TBtu
(3.0E-1
lb/GWh)
8.1E0
Ib/TBtu
(8.0E-2
Ib/GWh)
2.2E+1
Ib/TBtu
(3.0E-1
Ib/GWh)
2.0E-1
Ib/TBtu
(2.0E-3
Ib/GWh)
1.1E+2
ib/TBtu
(1.1E0
Ib/GWh)
3.3E0
lb/TBtu
(4.0E-2
Liquid
oil,
non-
continent
al
3.1E+1
lb/TBtu
(3.0E-1
lb/GWh)
1.1E+2
lb/TBtu
(1.4E0
lbyYGWh)
4.9E0
IbvTBtu
(8.0E-2
Ib/GWh)
2.0E+1
ib/TBtu
(3.0E-1
Ib/GWh)
4.0E-2
Ib/TBtu
(4.0E-4
Ib/GWh)
4.7E+2
lb/TBtu
(4.1E0
IWGWh)
9.8E0
Ib/TBtu
(2.0E-1
Solid oil-
derived
8.0E-1
ib/TBtu.
(2.0E-2
lb/GWh).
1.1E0
Ib/TBtu.
(2.0E-2
Ib/GWh).
8.0E-1
ib/TBtu.
(2.0E-2
Ib/GWh).
2.3E0
Ib/TBtu.
(4.0E-2
Ib/GWh).
NA.
9.0E0
lb/TBtu.
(2.0E-1
Ib/GWh).
1.2E0
Ib/TBtu.
(2.0E-2
486a
Table 5--Alternate Emission Limitations for
Existing Coal- and Oil-Fired EGUs
Subcatego Coal- IGCC Liquid Liquid Solid oil-
ry/ fired oil, oil,
Pollutant EGUs continent non- ésrived
al
continent
al
Ib/GWh) ib/GWh) Ib/GWh) Ib/GWh) Ilb/GWh).
NA = Not applicable.
fna Includes Hg.
Table 6--Alternate Emission Limitations for
New Coal- and Oil-Fired EGUs
Subcategory/ Coal- IGCC Liquid Liquid Solid
fired fna oil, oil,
Pollutant EGUs continen- non- oil-
tal, continen- derived
Iv¥GWh
tal,
lb/GWh
SO[2] 4.0E-1 4.0E-1 NA NA 4.0E-1
lbyYMWh lb/MWh Ib/MWh
Total non- 6.0E-2 4.0E-1 2.0E-4 7.0E-3 6.0E-1
mercury
metals IbyYGWh Ib/GWh Ib/MWh ib/MWh Ib/GWh
fnb
Antimony, 8.0E-3 2.0E-2 1.0E-2 8.0E-3
Sb
lb/GWh lb/GWh lb/GWh
Arsenic, As 3.0E-3 2.0E-2 3.0E-3 6.0E-2 3.0E-3
lb/GWh Ib/GWh lb/GWh
Beryllium, 6.0E-4 1.0E-3 5.0E-4 2.0E-3 6.0E-4
Be
lb/GWh _ Iib/GWh Ib/GWh
Cadmium, 4.0E-4 2.0E-3 2.0E-4 2.0E-3 7.0E-4
Cd
lb/GWh lb/GWh lb/GWh
487a
Table 6—Alternate Emission Limitations for
New Coal- and Oil-Fired EGUs
Subcategory/ Coal- IGCC Liquid Liquid Solid
fired fna oil, oil,
Pollutant EGUs continen- non- oil-
tal, continen- derived
IbvYGWh
tal,
lb/GWh
Chromium, 7.0E-3 4.0E-2 2.0E-2 2.0E-2 6.0E-3
Cr
lb/GWh_ \ib/GWh lb/GWh
Cobalt, Co 2.0E-3 4.0E-3 3.0E-2 3.0E-1 2.0E-3
lb/GWh _ ib/GWh Ib/GWh
Lead, Pb 2.0E-3 9.0E-3 8.0E-3 3.0E-2 2.0E-2
Ib/GWh lb/GWh lb/GWh
Mercury, Hg NA NA 1.0E-4 4.0E-4 2.0E-3
Ib/GWh
Manganese, 4.0E-3 2.0E-2 2.0E-2 1.0E-1 7.0E-3
Mn
lb/YGWh_ ib/GWh lb/GWh
Nickel, Ni 4.0E-2 7.0E-2 9.0E-2 4.1E0 4.0E-2
Ib/GWh_ 1lb/GWh Ib/GWh
Selenium,Se 6.0E-3 3.0E-1 2.0E-2 2.0E-2 6.0E-3
Ib/GWh itb/GWh Ib/GWh
NA = Not applicable.
fna Based on best-performing similar source.
fnb Includes Hg.
As noted elsewhere in this preamble, we are
finalizing a requirement to use filterable PM as a
surrogate for the non-mercury metallic HAP and HCl
as a surrogate for the acid gas HAP for all
subcategories of coal-fired EGUs and for the solid oil
derived fuel-fired EGUs. For all liquid oil-fired EGUs,
we are finalizing a requirement to use filterable PM as
a surrogate for the total metallic HAP, and we are
finalizing HCl and HF limits.
488a
In addition, we are finalizing alternative standards
for certain HAP for some subcategories. The
alternative pollutants and subcategories are as
follows: (1) SO2 as a surrogate to HC) for all
subcategories with add-on FGD systems (except liquid
oil-fired subcategories as there were no existing units
from which to base an alternate SO[2] limit); (2)
individual non-mercury metallic HAP as an alternate
to filterable PM for all subcategories (except that it
includes Hg for liquid oil-fired subcategories); and (3)
total non-mercury metallic HAP as an alternate to
filterable PM for all subcategories (except that it
includes Hg for liquid oil-fired subcategories). These
alternative standards are discussed elsewhere in this
preamble.
We are finalizing a beyond-the-floor standard for Hg
only for all existing coal-fired units designed for low
rank virgin coal based on the use of activated carbon
injection (ACI) for Hg control, as described elsewhere
in this preamble. The EPA has determined that this
beyond-the-floor level is achievable after considering
the relevant CAA section 112(d)(2) provisions.
As noted elsewhere in this preamble, we are also
finalizing a compliance assurance option that would
allow you to monitor liquid oil fuel moisture to
demonstrate that fuel moisture content is no greater
than 1.0 percent. Provided that demonstration is
made, you will not have to conduct additional testing
and monitoring to demonstrate compliance with the
HC] and HF emission limits for units in both liquid oil
subcategories (i.e., continental and non-continental).
Pursuant to CAA section 112(h), we are finalizing a
work practice standard for organic HAP, including
emissions of dioxins and furans, for all subcategories
of EGUs. The work practice standard being finalized
489a
requires the implementation of periodic burner tune-
up procedures described elsewhere in this preamble.
We are finalizing work practice standards because the
significant majority of data for measured organic HAP
emissions from EGUs are below the detection levels of
the EPA test methods, even when long duration
(around 8 hour) test runs are considered. As such, we
consider it impracticable to measure emissions from
these units. As discussed at proposal, we believe the
inaccuracy of a majority of measurements, coupled
with the extended sampling times used, allow a work
practice standard under CAA section 112(h) to apply
to these HAP.** We believe that a work practice
standard will lead to a better environmental outcome
than would be obtained through a requirement to
measure a pollutant for which results may or may not
be obtained. We believe that the work practice
standard will result in actions being taken that will
reduce emissions of these HAP.
In addition, as discussed below, we are creating a
subcategory for limited use liquid oil-fired electric
utility steam generating unit with an annual capacity
factor of less than 8 percent of its maximum or
nameplate heat input and we are establishing work
practice standards applicable to such units pursuant
to CAA section 112(h).
We are finalizing that new or existing EGUs are
“coal-fired” if they combust coal more than 10 percent
of the average annual heat input during any 3
consecutive calendar years or for more than 15 percent
of the annual heat input during any one calendar year
%#® We would also note that the EPA, as a part of the Industrial
Boiler MACT reconsideration proposal that was signed on
December 2, 2011, is proposing to establish work practice stand-
ards for control of dioxins and furans from industrial boilers.
490a
and meet the final definition of “fossil fuel-fired.” We
are finalizing that an EGU is considered to be in the
coal-fired “unit designed for coal greater than or equal
to 8,300 Btu/Ib” subcategory if the EGU: (1) meets the
final definitions of “fossil fuel-fired” and “coal-fired
electric utility steam generating unit;” and (2) is not a
coal-fired EGU in the “unit designed for low rank
virgin coal” subcategory.
We are finalizing that the EGU is considered to be
in the “unit designed for low rank virgin coal”
subcategory if the EGU: (1) meets the final definitions
of “fossil fuel-fired” and “coal-fired electric utility
steam generating unit;” and (2) is designed to burn
and is burning nonagglomerating virgin coal having a
calorific value (moist, mineral matter-free basis) of
less than 19,305 kJ/kg (8,300 Btu/Ilb) and that is
constructed and operates at or near the mine that
produces such coal.*””
We are finalizing that the EGU is considered to be
an IGCC unit if the EGU: (1) Combusts a synthetic gas
derived from gasified coal or solid oil-derived fuel (e.g.,
petroleum coke, pet coke), (2) meets tle final definition
of “fossil fuel-fired,” and (3) is classified as an IGCC
unit. We are not subcategorizing IGCC EGUs based on
the source of the syngas used (e.g., coal, petroleum
coke). Based on information available to the Agency,
although the fuel characteristics of coal and petcoke
are quite different, the syngas products from both
feedstocks have similar HAP content and similar HAP
*” ASTM Method D388-05, “Standard Classification of Coals
by Rank” (incorporated by reference, see § 63.14).
49la
emissions characteristics that can be controlled in a
similar manner.“
We are finalizing that the EGU is considered to be
in the “Continental liquid oil-fired” subcategory if (1)
meets the final definitions of “oil-fired electric utility
steam generating unit” and “fossil fuel-fired;” and (2)
is located in the continental United States (U.S.).
We are finalizing that the EGU is considered to be
“Non-continental liquid oil-fired” subcategory if (1)
meets the final definitions of “oil-fired electric utility
steam generating unit” and “fossil fuel-fired;” and (2)
is located outside continental U.S.
We are finalizing that the EGU is considered to be
“solid oil-derived fuel-fired” if (1) the EGU is not a coal-
fired EGU and burns solid oil-derived fuel (e.g.,
petroleum coke, pet coke); and (2) meets the final
definitions of “oil-fired electric utility steam
generating unit” and “fossil fuel-fired.”
We are finalizing that the EGU is considered to be a
“limited-use liquid oil-fired” if (1) the EGU meets the
final definitions of “oil-fired electric utility steam
generating unit” and “fossil fuel-fired;” and (2) has an
annual capacity factor of less than 8 percent of its
maximum or nameplate heat input, whichever is
greater, averaged over a 24-month block contiguous
period commencing.
E. What are the requirements during periods of
startup, shutdown, and malfunction?
*¢ U.S. Department of Energy, Wabash River Coal Gaification
Repowering Project. Project Performance Summary; Clean Coal
Technology Demonstration Program. DOE/FE-0448. July 2002.
EPA-HQ-OAR-2009-0234-2933.
492a
As discussed below in section VI1.E., for startup and
shutdown, the requirements have changed since
proposal. For periods of startup and shutdown, the
EPA is finalizing work practice standards in lieu of
numeric emission limits. Numeric emission limits
apply for all other periods for all pollutants, except
organic HAP. For malfunctions, the EPA is finalizing
an affirmative defense for exceedances of the
numerics! emission limits that are caused by malfunc-
tions.
F. What are the testing and initial compliance
requirements?
We are requiring that you, as an owner or operator
of a new or existing coal- or oil-fired EGU, must
conduct performance tests to demonstrate compliance
with all applicable emission limits. For units using
certified continuous emissions monitoring systems
(CEMS) that directly measure the regulated pollutant
under final 40 CFR part 63, subpart UUUUU (e.zg., Hg
CEMS, HCl CEMS, HF CEMS, SO, CEMS (where an
SO[2] limit applies as the alternative equivalent
standard)), or sorbent trap monitoring systems, the
initial performance test consists of all valid data
recorded with the certified monitoring system in the
first 30 boiler operating days of data collected with the
certified monitoring system prior to the initial compli-
ance demonstration date specified in § 63.10005. A
source may also elect to use a PM CEMS to
demonstrate compliance with the filterable PM
emission limit. If this option is selected, then the same
provisions as noted above for other CEMS will apply.
(Note that EPA anticipates that the PM monitoring
device that may most often will be used is a PM
continuous parameter monitoring system (CPMS) in
conjunction with an operating limit, as more fully
493a
described below.) For units and pollutants not being
monitored via CEMS, the owner or operator of an
affected unit must perform the initial performance
testing in accordance with established EPA reference
test methods or the voluntary consensus standard
methods incorporated by reference. You, as the owner
or operator of an affected unit, must conduct the
following compliance tests where applicable:
(1) For coal-fired units, IGCC units, and solid oil-
derived fuel-fired units, if you elect to comply with the
filterable PM emission limit, you must conduct
filterable PM emissions testing using EPA Method 5
from Appendix A to part 60 of chapter 40 to determine
initial compliance. Alternatively, if you elect to comply
with the total non-mercury HAP metals emission limit
or the individual non-mercury HAP metals emissions
limits, you must conduct HAP metals testing using
40. Note for this rule that the filter temperature for
each Method 5 or 29 emissions test must be
maintained at 160 [degrees] +/- 14 [degrees] C (320
[degrees] +/- 25 [degrees] F), and the material in
Method 29 impingers must be analyzed for metals
content. Whenever metals testing is performed with
Method 29, you must report the front half and back
half analytical fractions separately.
(2) For coal-fired, IGCC, and solid oil-derived fuel-
fired units, you must use a Hg CEMS or a sorbent trap
monitoring system for both initial compliance and
monitoring provisions of Appendix A to 40 CFR part
63, subpart UUUUU, except where the low emitting
EGU (LEE) requirements apply (see below). The
initial performance test consists of all valid data
recorded with the certified Hg monitoring system in
494a
the 30 boiler operating days of data collected with the
certified monitoring system by the initial compliance
demonstration date specified in § 63.10005.
(3) For coal-fired and solid oil-derived fuel-fired
units and new or reconstructed IGCC units that
employ FGD technology and elect to meet the alterna-
tive SOzlimit in place of the HCl limit, you need not
conduct an initial stack test for HC] or. Instead, the 30
boiler operating days of data collected with the certi-
fied SO. CEMS by the initial compliance demonstra-
tion date specified in § 63.10005 are used to determine
initial compliance, and the SO[2] CEMS is used there-
after to demonstrate continuous compliance. If you
instead opt to meet the HCl limit and use an HCl
CEMS for compliance, you need not conduct an initial
stack test for HCl. Instead, the 30 boiler operating
days of data collected with the certified HC] CEMS by
the initial compliance demonstration date specified in
§ 63.10005 are used to determine initial compliance.
For units not using the SO[2] or HC] CEMS options,
you must conduct an initial stack test for HCl using
EPA Method 26, 26A, or 320 from Appendix A to part
60 of chapter 40. You may use EPA Method 26 or 320
or ASTM Method D6348-03 (Reapproved 2010) with
additional quality assurance if no entrained water
droplets exist in the exhaust gas, but you must use
Method 26A if entrained water droplets exist in the
exhaust gas.
(4) For liquid oil-fired units, you must conduct initial
performance testing as follows. If you elect to meet the
filterable PM limit instead of the non-mercury metals
limit (total or individual), then use Method 5 with the
filter material maintained at 160 [degrees] +/- 14
[degrees] C (320 [degrees) +/- 25 [degrees] F). Alterna-
tively, you may use a PM CEMS as discussed
495a
elsewhere in this preamble. If you elect to meet either
the total or individual HAP metals limit, you will use
Method 29 for all non-mercury HAP metals. For Hg,
conduct emissions testing using EPA Method 29 or
30B from Appendix A to part 60 of chapter 40, or
ASTM Method D6784-02 (Reapproved 2008). For acid
gases, conduct HC] and HF testing using EPA Method
26A, 320, or 26; or you may elect to comply by using an
HCl CEMS and/or an HF CEMS; or under certain
conditions you may choose to demonstrate compliance
by measuring fuel moisture to demonstrate that
moisture content is no greater than 1.0 percent. You
must measure daily if fuel is delivered continuously or
per shipment if fuel is delivered on a batch basis, or
you may use a fuel moisture content certification
provided by your fuel supplier. If you use a CEMS,
then use the 30 boiler operating days of data collected
with the certified monitoring system by the initial
compliance demonstration date specified in § 63.10005
to determine initial compliance.
(5) For the required performance stack tests, if you
are demonstrating compliance with a heat-input based
standard, you must conduct concurrent O[2] or carbon
dioxide (SO2) emission testing using EPA Method 3A
or 3B from appendix A to part 60 of chapter 40 or
ANSVASME PTC 19.10-1981 and then use an
appropriate equation, selected from among Equations
19-1 through 19-9 in EPA Method 19 from appendix A
to part 60 of chapter 40, to convert measured pollutant
concentrations to Ib/MMBtu values. Multiply the
lb/MMBtu value by one million to get the lb/TBtu
value (where applicable). If you choose to meet an
electrical output-based emissions limit, you must also
collect concurrent stack gas flow rate and electrical
production data.
496a
(6) For an existing unit that you believe will qualify
as LEE for Hg, you must condvct an initial Method
30B test over 30 days and follu.. the calculation
procedures in the final rule to document a potential to
emit less than 10 percent of the applicable Hg
emissions limit or less than 29 pounds of Hg per year.
If your unit qualifies as a LEE for Hg, you must
conduct subsequent performance tests on an annual
basis to demonstrate that the unit continues to
qualify. For all other pollutants, you must conduct the
initial compliance test, and then all other required
tests over a 3-year period, and in all such tests, your
emission results must be less than 50 percent of the
applicable emission limit. If you qualify as a LEE on
that basis, you must conduct subsequent performance
tests every 3 years to demonstrate that the unit
continues to qualify.
(7) You may use results from tests conducted no
earlier than 12 months before the compliance date of
this rule as the initial performance test for an
applicable pollutant, provided that:
a. You certify and keep records demonstrating
that no significant changes have occurred,
b. Tests were conducted using methods allowed in
this rule in accordance with § 63.10007 and Table 5,
c. You have records of all parameters needed to
convert results to units of the standard for the entire
period, and
d. For a CEMS-based performance test, you have
all the required data for the entire 30-boiler operating
day rolling average period.
Operating Limit for PM CEMS
497a
Under the final rule, you may elect to comply con-
tinuously with an operating limit, established during
the initial performance test, to demonstrate continu-
ous compliance with the filterable PM, total non-
mercury HAP metals, or individual non-mercury HAP
metals limit. You will use a PM CPMS to monitor
compliance with the operating limit. The PM CPMS
operating principle must be based on in-stack or
extractive light scatter, light scintillation, beta atten-
uation, or mass accumulation detection of the exhaust
gas or representative exhaust gas sample. The report-
able measurement output from the PM CPMS may be
expressed as milliamps, stack concentration, or other
raw data signal. Meeting the operating limit serves as
your demonstration of continuous compliance with the
filterable PM, total non-mercury HAP metals, or indi-
vidual non-mercury HAP metals limit. As mentioned
earlier, if you use this method to demonstrate contin-
uous compliance, you must install a PM CPMS and
establish the operating limit during the initia] compli-
ance test for filterable PM, total non-merecury HAP
metals, or individual non-mercury HAP metals. As
noted below, when you use this operating limit, you
can reduce stack testing frequency to demonstrate
ongoing compliance. You may also opt to install and
operate a PM CEMS certified in accordance with Per-
formance Specification 11 and Procedure 2 of 40 CFR
part 60, Appendices B and F, respectively. If you elect
to use this option, then the requirements for quarterly
testing with Method 5, or annual testing and use of a
PM CPMS, are no longer applicable.
Dioxins/Furans and Non-Dioxin/Furan Organic HAP
For dioxins and furans and non-dioxin/furan organic
HAP, you must submit documentation that you have
conducted a combustion process tune-up, a thorough
498a
equipment inspection, and an optimization to
minimize generation of CO and NO[X], all meeting the
requirements of this final rule. The work practice
standard involves maintaining and inspecting the
burners and associated combustion controls, tuning
the specific burner type to optimize combustion,
obtaining and recording CO and NO[X] values before
and after burner adjustments, keeping records of
activity and measurements, and submitting a report
for each tune-up conducted. You must collect CO and
NO[X] data and may use portable analyzers (which
include handheld or similar devices) to monitor and
verify the results. The specific details are addressed in
40 CFR 63.10021 of the final rule.
This same work practice standard also applies in
place of any emission limits for Hg, non-mercury
metals HAP, acid gas HAP, dioxins and furans, and
non-dioxin/furan organic HAP from a limited-use,
liquid oil-fired EGU (i.e., a unit that has an annual
capacity factor on oil of less than 8 percent of its
maximum or nameplate heat input, whichever is
greater). The EPA established this subcategory in
response to comments and a further analysis of the
units within this subcategory in the ICR database. For
these units, EPA believes that the required work
practice standards are appropriate and consistent
with the requirement of CAA section 112(h).
G. What are the continuous compliance requirements?
To demonstrate continuous compliance with the
emission limitations, the final rule includes the
following requirements:
(1) Use of CEMS. Where a CEMS or a sorbent trap
monitoring system is used for demonstrating initial
compliance, you also must use the CEMS or sorbent
499a
trap monitoring system on a continuous basis to
demonstrate ongoing compliance with the numerical
emission limits. CEMS or sorbent trap monitoring
system data are not used to determine compliance
with the work practice standards applicable during
periods of startup and shutdown, but sources that
install a CEMS or a sorbent trap monitoring system to
demonstrate compliance with the numerical emission
limits must operate the system at ail times, as EPA
intends to evaluate the continuous monitoring data
from start-up and shutdown periods as discussed
below. You must calculate a rolling average for each
successive 30-boiler operating day rolling average
period. All valid data collected during each successive
period will be used to demonstrate compliancr . except
for data collected during periods of startup and
shutdown; during those periods, the owner or operator
must meet work practice requirements instead of the
numerical emission limits. There is no numerical
minimum data availability required to constitute a
valid 30-boiler operating day rolling average; however,
you must monitor at all times that the process is in
operation (including during startups and shutdowns,
although emissions during these periods are not
included in the 30-boiler operating day average). You
must operate, maintain, and quality-assure the CEMS
or sorbent trap monitoring systems in accordance with
the provisions in 40 CFR 63.10010 and Appendix A
and B of the final rule (for Hg, HCl, and HF CEMS),
in accordance with Performance Specification 11 in
Appendix B to 40 CFR part 60 and Procedure 2 in
Appendix F to part 60 (for PM CEMS used for direct
compliance), or in accordance with 40 CFR part 75 (for
SO2z CEMS, and certain ancillary monitors such as a
diluent or moisture monitor).
500a
For each unit using HCl, HF, SO:, PM, or Hg CEMS
or a sorbent trap monitoring system for continuous
compliance, you must install, certify, maintain,
operate and quality-assure the additional CEMS (e.z.,
CEMS that measure O, or CO: concentration, stack
gas flow rate, and, if default moisture values are not
used, moisture content) needed to convert pollutant
concentrations to units of the emission standards or
operating limits. Where appropriate, you must certify
and quality-assure these additional CEMS according
to 40 CFR part 75.
For HC] and HF CEMS, the EPA is adding
monitoring provisions as Appendix B to 40 CFR part
63, subpart UUUUU. Appendix A references perfor-
mance specification (PS) 15 of Appendix B to 40 CFR
part 60 for Fourier Transform Infrared (FTIR) CEMS
for procedures to certify and conduct ongoing quality
assurance on these FTIR CEMS. In addition, we
expect to publish a PS specific to HC] CEMS in the
near future (prior to the compliance date of this rule).
In the meantime, you may petition the Administrator
under the procedure given in 40 CFR 63.7(f) for an
alternative approach to compliance monitoring or
testing for HCl or any other regulated pollutant.
When using a sorbent trap monitoring system, you
may use each pair of sorbent traps to collect Hg
samples for no more than 15 boiler operating days.
Under the general duty to monitor at all times, you
must replace traps in a timely manner to ensure that
Hg emissions are sampled continuously.
For Hg monitoring, the EPA is adding Hg monitor-
ing provisions as Appendix A to 40 CFR part 63,
subpart UUUUU, and requiring use of these provi-
sions to document continuous compliance with the rule
for coal-fired, IGCC, and solid oil derived-fired units
501la
that cannot qualify as LEEs. Appendix A consolidates
all Hg monitoring provisions.
Today’s rule provides two basic Hg continuous
monitoring options: Hg CEMS and sorbent trap
monitoring systems. Appendix A requires initial cer-
tification and periodic quality assurance (QA) testing
of the Hg CEMS and sorbent trap monitoring systems.
The certification tests required for the Hg CEMS are
a 7-day calibration error test; a linearity check, using
NIST-traceable elemental Hg standards; a 3-level
system integrity check (similar to a linearity check),
using NIST-traceable oxidized Hg standards; a cycle
time test; and a relative accuracy test audit (RATA).
Table A-1 of Appendix A summarizes the performance
specifications for the required certification tests. For
ongoing QA of the Hg CEMS, Appendix A requires
daily calibrations, weekly single-point system integ-
rity checks, quarterly linearity checks (or 3-level
system integrity checks), and annual RATAs. Table A-
2 in Appendix A summarizes these ongoing QA test
requirements and the applicable performance criteria
for Hg CEMS, which are consistent with those
published in support of CAMR and are, thus, familiar
to the industry.
For sorbent trap monitoring systems, a RATA is
required for initial certification, and annual RATAs
are required for ongoing QA. The performance
specification for these RATAs is the same as for the
RATAs of the Hg CEMS. Bias adjustment of the
measured Hg concentration data is not required. For
day-to-day operation of the sorbent trap system,
Appendix A requires you to follow the procedures and
QA/QC criteria in PS 12B in Appendix B to 40 CFR
part 60. PS 12B is nearly identical to the Appendix K
to 40 CFR part 75, published in support of CAMR and
502a
with which the industry is familiar. The 40 CFR part
75 concepts of:
a. Determining the due dates for certain QA tests
on the basis of “QA operating quarters” and
b. Grace periods for certain QA tests apply to both
Hg CEMS and sorbent trap monitoring systems.
Mercury concentrations measured by Hg CEMS or
sorbent trap systems are used together with hourly
flow rate, diluent gas, moisture, and electrical load
data, to express the Hg emissions in units of the rule,
on an hourly basis (i.e., |b/TBtu or lb/GWh). Section 6
of Appendix A provides the necessary equations for
these unit conversions.
For HCl and HF CEMS, the EPA is adding monitor-
ing provisions as Appendix B to 40 CFR part 63,
Subpart UUUUU. Appendix A references performance
specification (PS) 15 of Appendix B to 40 CFR part 60
for Fourier Transform Infrared (FTIR) CEMS for
procedures to certify and conduct ongoing quality
assurance on these FTIR CEMS. In addition, we
expect to promulgate a generic PS specific to HCl
CEMS prior to the compliance date of this rule. In the
meantime, you may petition the Administrator under
the procedure given in 40 CFR 63.7(f) for an
alternative approach to compliance monitoring or
testing for HC] or any other regulated pollutant.
(2) Use of stack tests. If you demonstrate initial com-
pliance on the basis of a stack test, you must demon-
strate continuous compliance by conducting periodic
stack tests on a quarterly basis. This includes filtera-
ble PM (or non-mercury HAP metals) and HC) from
coal-fired and solid oil-derived fuel-fired EGUs, and
filterable PM (or HAP metals) and HCl and HF from
liquid oil-fired EGUs with the following exceptions:
503a
a. If you use a PM CPMS and associated operating
limit, you may conduct the applicable Method 5 or
Method 29 test once annually rather than quarterly,
in which case you must re-establish the operating
limit during each performance test. A PM CPMS does
not need to meet the requirements for a PM CEMS
under PS 11. The final rule includes basic quality
checks that the PM CPMS must meet and a require-
ment for you to develop and follow a site-specific mon-
itoring plan to be approved by the delegated authority.
You must demonstrate compliance with the operating
limit by using all valid hourly data collected during
each successive 30-boiler operating day period rolled
daily. The 30-boiler operating day rolling average is
calculated by all of the valid hourly average PM CPMS
output values collected for the 30 boiler operating days
(excluding hours of startup and shutdown; See section
V.E. of this preamble).
b. If you combust liquid fuels and if your fuel
moisture content is no greater than 1.0 percent, you
may demonstrate ongoing compliance with HCl and
HF emissions limits by:
i. Measuring fuel moisture content of each
shipment of fuel if your fuel arrives on a batch basis;
ii. Measuring fuel moisture content daily if your
fuel arrives on a continuous basis; or
iii. Obtaining and maintaining a fuel moisture
certification from your fuel supplier.
Should the moisture in your liquid fuel be more than
1.0 percent, you must
i. Conduct HCl and HF emissions testing quar-
terly and establish site-specific monitoring to
504a
demonstrate continued acid gas control performance
between periodic tests, or
ii. Use an HC] CEMS and/or HF CEMS.
c. If your existing unit qualifies as an LEE for Hg,
you must conduct another 30-day Method 30B
performance test on your unit once per year to
reestablish that the unit continues to qualify as a LEE
for Hg. If the results of the LEE test show that the unit
exceeds 10 percent of the emissions limit or exceeds
the potential to emit 29 pounds of Hg per year, you will
lose LEE status for the unit. You can regain LEE
status for that unit if every required performance test
for a 3-year period shows that emissions from the unit
did not exceed the LEE limit. If LEE status is lost for
a solid fuel unit, you must commence quarterly
performance testing until you install, certify, and
operate a Hg CEMS or a sorbent trap monitoring
system, and you must complete the installation and
certification within 6 months of losing LEE status; for
a liquid fuel unit, you must commence quarterly
performance testing.
d. If a liquid oil-fired EGU has an annual capacity
factor on oil of less than 8 percent of its maximum or
nameplate heat input, whichever is greater, you must
demonstrate continuous compliance with the applica-
ble work practice standard by conducting at least once
every 36 calendar months (48 calendar months if a
neural network is employed) a combustion process
tune-up, a thorough equipment inspection, and an
optimization to minimize generation of CO and NOx,
all meeting the requirements of this final rule. You
must maintain and inspect the burners and associated
combustion controls, tuning the specific burner type to
optimize combustion, obtaining and recording CO and
NOx values before and after burner adjustments,
505a
keeping records of activity and measurements, and
submitting a report for each tune-up conducted. You
must collect CO and NOx data using portable analyz-
ers (which typically include handheld or similar
devices). Specific details are addressed in 40 CFR
63.10021 of the final rule. In addition, you must record
boiler operating hours, by fuel type, in each calendar
quarter.
e. The rule allows a grant of LEE status to
existing units with test results that show a history of
low, non-mercury emissions. As mentioned earlier,
LEE status reduces testing frequency for units. After
a 3-year period during which every emissions test for
a specific pollutant shows emissions no greater than
50 percent of the emissions limit, you may reduce the
emissions testing frequency for that specific non-
mercury pollutant to once every 36 months. If any
subsequent emissions test for that pollutant exhibits
emissions greater than 50 percent of the emissions
limit, you must revert to the original emissions testing
frequency until you re-establish a 3-year period of very
low emissions no greater than 50 percent of the
standard.
f. For liquid oil-fired units that demonstrate con-
tinuous compliance with quarterly performance tests
for HC] and HF emission limits rather than through
use of HC] and HF CEMS, the final rule requires a
site-specific monitoring plan in addition to the quar-
terly tests. For these pollutants, there is unlikely to be
any existing underlying monitoring (such as compli-
ance assurance monitoring) that serves as an addi-
tional tool to ensure the source’s operations remain
consistent with operating conditions during a recent
successful performance test. The requirement for a
site-specific monitoring plan fills this gap and ensures
506a
that in between tests, the source continues to operate
in a manner designed to maintain HC] and HF emis-
sions in compliance with the emission limits under
this rule. The appropriate parameters to monitor will
depend on the compliance strategy employed by a spe-
cific source, and thus EPA is enabling the monitori
approach to be established on a case-by-case basis.
Given the relatively small number of these units and
the other compliance options available, we anticipate
that this approach will apply to a small set of units.
The monitoring plan will identify the parameters mon-
itored, the monitoring methods, the QA/QC elements
that apply, and the data reduction elements (including
appropriate averaging periods, as applicable). See 40
CFR 63.10000(cX2 ii).
keeping records of activity and measurements, and
submitting a report for each tune-up conducted. A
combustion tune-up will involve optimizing combus-
tion of the unit consistent with manufacturer's
instruction as applicable, or in accordance with best
combustion engineering practice for that burner type.
H. What are the notification, recordkeeping and
reporting requirements?
All new and existing sources in al] subcategories
must comply with certain requirements of the General
507a
Provisions (40 CFR part 63, subpart A), which are
identified in Table 9 of this final rule. The General
Provisions include specific requirements for notifica-
tions, recordkeeping, and reporting. You must submit
a notification of compliance status report for each unit,
according to the schedule required by 40 CFR 63.9(h)
of the General Provisions, including a certification of
compliance.
Except for units that use CEMS for continuous
compliance, under this rule you must provide semian-
nual compliance reports, as required by 40 CFR
63.10(e)(3) of subpart A, that indicate whether a
deviation from any of the requirements in the rule
occurred and whether or not any process changes
occurred and compliance certifications were reevalu-
ated. As discussed below, we are finalizing a
requirement to use the 40 CFR part 75-based
Emissions Collection and Monitoring Plan System
(ECMPS) for reporting emissions and related data for
units using CEMS for most pollutants. Also, as
discussed below, for the PM CPMS, PM CEMS, and
performance test results, we require you to use EPA’s
WebFIRE*™ database for reporting.
This rule requires you to keep certain records to
demonstrate compliance with each emission limit and
work practice standard. The General Provisions to 40
CFR part 63 specify these recordkeeping requirements
(see Table 9 to this subpart). Among other specific
records, you must keep the following:
38 WebFIRE is the Internet version of FIRE. The Factor
Information Retrieval (FIRE) Data System is a database
management system containing EPA’s recommended emission
estimation factors for criteria and HAP. It includes information
about industries and their emitting processes, the chemicals
emitted, and the emission factors themselves.
508a
(1) All reports and notifications submitted to comply
with this rule.
(2) Continuous monitoring data as required in this
rule.
(3) Each instance in which you did not meet an
emission limit, work practice requirement, operating
limit, or other compliance obligation (i.e., deviations
from this rule).
(4) Daily hours of operation by each unit.
(5) As part of the general duty to keep all monitoring
data, fuel moisture content of liquid fuel, if you elect
to demonstrate compliance using that information.
(6) A copy of the results of all performance tests,
monitor certifications, performance evaluations, or
other compliance demonstrations conducted to demon-
strate initial or continuous compliance with this rule.
(7) A copy of your site-specific performance evalua-
tion test plans developed for this rule as specified in
40 CFR 63.8(e), if applicable.
(8) A copy of your acid gas control system parameter
monitoring plan under 40 CFR 63.10000(c2 ii).
You also must submit the following additional
notifications:
(1) Notifications required by the General Provisions.
(2) Initial Notification no later than 120 calendar
days after you become subject to this subpart.
(3) Notification of Intent to conduct performance
tests and/or compliance demonstration at least 60
calendar days before the performance test and/or
compliance demonstration is scheduled.
509a
(4) Notification of Compliance Status 60 calendar
days following completion of the performance test
and/or compliance demonstration.
Electronic reporting is becoming a common element
of modern life (as evidenced by electronic banking and
income tax filing), and the EPA is beginning to require
electronic submittal of environmental data. Electronic
reporting is already common in environmental data
collection and many media offices at EPA are reducing
reporting burden for the regulated community by
embracing electronic reporting systems as an alterna-
tive to paper-based reporting.
One of the major benefits of reporting electronically
is standardization, to the extent possible, of the data
reporting formats that provides more certainty to
users of what data are required in specific reports. For
example, electronic reporting software allows for more
efficient data submittal and the software’s validation
mechanism helps industry users submit fewer
incomplete reports. This alone saves industry report
processing resources and reduces transaction times.
Standardization also allows for development of
efficient methods to compile and store much of the
documentation required to be reported by this rule.
Use of Electronic Reporting System
We are requiring that you submit certain reports
electronically. In addition to supporting regulation
development, control strategy development, and other
air pollution control activities, having an electronic
database populated with these reports will save
industry, state, local, tribal agencies, the public, and
the EPA significant time, money, and effort while also
improving the transparency and quality of emission
inventories and, as a result, air quality regulations.
510a
The reports to be submitted electronically include
all performance test reports, notification of compliance
status reports, compliance, and continuous monitoring
data summaries specified in 40 CFR 63.10031 of this
rule. Performance tests are required to be conducted
as described in 40 CFR 63.7 of the General Provisions.
The data that must be submitted as the performance
test report are also described in 40 CFR 63.7. These
data must be submitted (except in limited cases) to
EPA’s WebFIRE database by using the electronic
reporting tool (ERT) and the Compliance and Emissions
Data Reporting Interface (CEDRI) that is accessed
through EPA’s Central Data Exchange (CDX), as
described below. The data requirements for the
notification of compliance status and compliance
reports are described in detail in the regulatory text
(40 CFR 63.10031) of this rule, but they essentially
mirror the requirements in 40 CFR 63.6 of the General
Provisions. These reports will also be submitted to
WebFIRE using an electronic form found in CEDRI
and through the CDX as described below. As required
in 40 CFR 63.10031(f)(2) of the final rule, the
continuous monitoring summaries are required to be
submitted quarterly. The quarterly reports must
include all of the calculated 30-boiler operating day
rolling average values derived from the PM CPMS.
These reports will also be submitted to WebFIRE
using an electronic form found in CEDRI and through
the CDX, as described below. This same approach will
apply if a source elects to use a PM CEMS or receives
approval to use a HAP metals CEMS as an alternative
monitoring method.
The availability of electronic reporting for sources
subject to the Subpart UUUUU will provide efficiency,
improved services, better accessibility of information,
5lia
and more transparency and accountability. Addition-
ally, submittal of these required reports electronically
provides significant benefits for regulatory agencies,
industry, and the public. The compliance data
electronic reporting system (CEDRI and CDX) is being
developed such that once a facility’s initial data entry
into the system is established and a report is gener-
ated, subsequent data submittal will only consist of
electronic updates to existing information in the
system. Such a system will effectively reduce the bur-
den associated with submittal of data and reports by
reducing the time, costs, and effort required to submit
and update hard copies of documentation. State, local,
and tribal air pollution control agencies will also ben-
efit from having access to the more streamlined and
accurate electronic data submitted to the EPA.
Electronic reporting will allow for an electronic review
process rather than a manual data assessment, mak-
ing review and evaluation of the source-provided data
and calculations easier and more efficient. Electronic
reporting will also benefit the public by generating a
more transparent review process and increasing the
ease and efficiency of data accessibility. Furthermore,
electronic reporting will reduce the burden on the reg-
ulated community by reducing the effort involved in
data collection and reporting activities. In the future,
we anticipate there will be fewer and less substantial
data collection requests in conjunction with prospec-
tive required residual risk assessments or technology
reviews. Electronic reporting will substantially reduce
this burden, because the EPA will already have these
data available and consolidated in an electronic data-
base named WebFTIRE. We anticipate that using elec-
tronic reporting for the required reports will result in
an overall reduction in reporting costs; for a discussion
512a
of the economic and cost impacts of electronic report-
ing, see section XII.D. of this preamble.
Another benefit of electronic data submittal is that
these data will greatly i improve the overall quality of
existing and new emissions factors by supplementing
the pool of emissions test data for establishing
emissions factors and by ensuring that the factors are
more representative of current industry operational
procedures. A common complaint heard from industry
and regulators is that emission factors are outdated or
not representative of a particular source category.
With timely receipt and incorporation of data from
most performance tests, the EPA will be able to ensure
that emission factors, when updated, represent the
most current range of operational practices.
Data entry of these electronic reports will be
through the CEDRI that is accessed through EPA’s
CDX (www.epa.govu/cdx). Data submitted electronically
through CEDRI will be stored in CDX as an official
copy of record.
Once you have accessed CEDRI, you will select the
applicable subpart for the report that you are
submitting. You will then select the report being
submitted, enter the data into the form, and click on
the submit button. In some cases, such as with
submittal of a notification of compliance status report,
you will select the report icon, enter basic facility
information, and then upload the report in a specified
file format.
In addition, we believe that there will be value in
allowing other reporting forms to be developed and
used in cases where the other reporting forms can
provide an alternate electronic file consistent with
EPA’s form output format. This approach has been
513a
used successfully to provide alternatives for other
electronic forms (e.g., income tax submittal).
In cases where performance test data are to be
submitted to the EPA, you must enter the performance
test data and information into the electronic reporting
tool (ERT) which can be accessed at http://www.
epa.gou/ttn/chief/ert /index.html. In CEDRI, the user
must then upload the ERT file. CEDRI submits a copy
of the ERT project data file directly to WebFIRE where
the data are made available. Where performance test
reports are submitted, WebFIRE notifies the
appropriate state, local, or tribal agency contact that
an ERT project data file was received from the source.
Submitting performance test data electronically to
the EPA will apply only to those performance tests
conducted using test methods that will be supported
by the ERT. The ERT contains a specific electronic
data entry form for most of the commonly used EPA
reference methods. A listing of the pollutants and test
methods supported by the ERT is available at the ERT -
Web site listed above.
I. Submission of Emissions Test Results to the EPA
The EPA has determined that harmonization of the
monitoring and reporting requirements of this final
rule with 40 CFR part 75 is appropriate, where the
affected industry already has a well-defined system for
continuous monitoring and reporting of emissions
under that part. Therefore, the Agency is finalizing
monitoring and reporting requirements for most
CEMS that are consistent with 40 CFR part 75. You
must report CEMS data (other than PM CEMS data
or data from alternative monitoring subject to site-
specific approval such as a HAP metals CEMS) to the
5l4a
EPA electronically, on a quarterly basis, using the
ECMPS.
The ECMPS process divides electronic data into
three categories, the first of which is monitoring plan
data. You must maintain the electronic monitoring
plan separately and can update it at any time if
necessary. The monitoring plan documents the
characteristics of the affected units (e.g., unit type,
rated heat input capacity, etc.) and the monitoring
methodology used for each parameter (e.g., CEMS).
The monitoring plan also describes the type of
monitoring equipment used (hardware and software
components), includes analyzer span and range
settings, and provides other useful information.
Nearly all coal-fired EGUs are subject to the ARP and
thus have established electronic monitoring plans that
describe their required SO2, flow rate, CO2 or Oz, and,
in some cases, moisture monitoring systems. The EPA
will adjust the ECMPS monitoring plan format to
accommodate this same type of information for Hg,
HCl, and HF CEMS, with the addition of a few codes
for the new parameters.
The second type of data collected through ECMPS is
certification and QA test data. These data include data
from linearity checks, RATAs, cycle time tests, 7-day
calibration error tests, and a number of other QA tests
that are required to validate the emissions data. You
may submit the results of these tests to the EPA as
soon as you obtain the results, with one notable
exception. Daily calibration error tests are not treated
as individual QA tests, due to the large number of
records generated each quarter. Rather, these tests
must be included in the quarterly electronic reports,
along with the hourly emissions data. The ECMPS
system is set up to receive and process certification
515a
and QA data from SO2, COs, Ox, flow rate, and
moisture monitoring systems that are installed,
certified, maintained, operated, and quality-assured
according to 40 CFR part 75. EGUs routinely submit
these data to the EPA under the ARP and other
emissions trading programs.
To accommodate the certification and QA tests for
Hg CEMS, other CEMS, and sorbent trap monitoring
systems, the structure and functionality of ECMPS
needs relatively few changes, because most of the tests
are the same as those required for other gas monitors.
For reporting Hg, HCl, SO2, and HF CEMS data under
this rule, we are disabling ECMPS’ 40 CFR part 75
bias test (which is required for certain types of
monitors under the EPA’s SO, and NOx emissions
trading programs). The bias adjustment of the data
from these monitors is unnecessary for compliance
with the rule.
The third type of data collected through ECMPS is
the hourly emissions data, which, as previously noted,
is reported on a quarterly schedule. You must submit
reports within 30 days after the end of each calendar
quarter. The emissions data format requires hourly
reporting of all measured and calculated emissions
values, in a standardized electronic format. You must
report direct measurements made with CEMS, such as
gas concentrations, in a Monitor Hourly Value (MHV)
record. A typical MHV record for gas concentration
includes data fields for:
(1) The parameter monitored (e.g., SO2);
(2) The unadjusted and bias-adjusted hourly
concentration values (note that if bias adjustment is
not required, only the unadjusted hourly value is
reported);
516a
(3) The source of the data, i.e., a code indicating
either that each reported hourly concentration is a
quality assured value from a primary or backup
monitor, or that quality-assured data were not
obtained for the hour; and
(4) The percent monitor availability (PMA), which is
updated hour-by-hour. This generic record structure
could easily accommodate hourly average measure-
ments from CEMS used under this rule.
The ECMPS reporting structure is quite flexible,
which makes it useful for assessing compliance with
various emission limits. The Derived Hourly Value
(DHV) record allows calculations of a wide variety of
quantities from the reported hourly emissions data.
For instance, if an emission limit is expressed in units
of Ib/MMBtu, the DHV record can be used to report
hourly pollutant concentration values in these units of
measure, since the Ib/MMBtu values can be derived
from the hourly pollutant and diluent gas (CO, or O2)
concentrations reported in the MHV records. The
ECMPS can also accommodate multiple DHV records
for a given hour in which more than one derived value
is required to be reported. The system will support
reporting hourly data in the units of the emission
standards (e.g., Ib/MMBtu, lb/TBtu, Ib/GWh, etc.)
when hourly Hg concentration data are reported
through ECMPS using the DHV record, in conjunction
with the appropriste equations and auxiliary
information such as heat input and electrical load (all
of which are reported hourly in the emissions reports).
One change in this rule from standard 40 CFR part
75 emissions data reporting is elimination of the
requirement to provide substitute data calculations
within ECMPS. The ARP and other emissions trading
programs that report emissions data to the EPA using
517a
40 CFR part 75 require provision of a complete data
record. Emissions data are required to be reported for
every unit operating hour. When CEMS are out of
service, substitute data must be reported to fill in the
gaps. However, for the purposes of compliance with a
NESHAP, reporting substitute data during monitor
outages is not necessary, as quantification of total
mass emissions is not the focus of the rule. Hours
when a monitoring system is out of service would be
counted as hours of monitor down-time and may be a
deviation from the monitoring requirements of this
rule unless the rule provides an exception, as it does
for routine quality control and maintenance activities.
In contrast to the CEMS-related data that would be
submitted through ECMPS, you must submit reports
of performance tests and PM CPMS data to EPA’s
WebFTRE database by using CEDRI that is accessed
through EPA’s CDX (www.epa.gouv/cdx). You must
submit performance test data in the file format
generated through use of EPA’s ERT (see http://www.
epa.gou/ttn/chief/ert /index.html) within 60 days
of performance test completion. Electronic data
submittal requirements are described in section V.H.
of this preamble.
Other notifications and reports not currently
accepted by the electronic reporting system will be
submitted in hardcopy form at this time.
VI. Summary of Significant Changes Since
Proposal
The previous section described the requirements
that EPA is finalizing in this rule. This section will
discuss in greater detail the key changes EPA is
making from the proposed. These changes result from
EPA’s review of the additional data and information
518a
provided to us and our consideration of the man’
substantive and thoughtful comments submitted on
the proposal. While our approach and methodology to
establishing the standards remain the same, the
changes make the final rule more flexible and cost-
effective, reduce reliability concerns and improve
clarity, while fully preserving, or improving, the public
health and environmental protection required by the
CAA.
A. Applicability
Since proposal, the EPA has made certain changes
to the applicability provisions of the final rule to
provide clarity. These changes do not change the
universe of sources subject to the rule.
The EPA is revising a number of the proposed
definitions and adding a definition for “natural gas-
fired electric utility steam generating unit” in the final
rule to provide clarity to the regulated community
concerning the standards applicable to coal and oil-
fired EGUs.
In the proposed rule, the EPA defined “(ellectric
utility steam generating unit” consistent with the CAA
section 112(aX8) definition:
A fossil fuel-fired combustion unit of more than 25
megawatts electric (MWe) that serves a generator that
produces electricity for sale. A fossil fuel-fired unit
that cogenerates steam and electricity and supplies
more than one-third of its potential electric output
capacity and more than 25 MWe output to any utility
power distribution system for sale is considered an
electric utility steam generating unit.
40 CFR 63.10042.
519a
We also indicated how we would determine whether
units were coal-fired or oil-fired fired EGUs: “If an
EGU burns coal (either as a primary fuel or as a
supplementary fuel), or any combination of coal with
another fuel (except solid waste as noted below), the
unit is considered to be coal fired under this proposed
rule. If a unit is not a coal-fired unit and burns only
oil, or oil in combination with another fuel other than
coal (except as noted below), the unit is considered to
be oil fired under this proposed rule.” 76 FR 25020.
We proposed a definition for the term “fossil fuel-
fired” because that term was not defined in the statute
and we wanted to clarify the level of fossil fuel
combustion necessary to satisfy the CAA section
112(a\8) definition of EGU. The definition focused on
coal and oil combustion because the EPA was only
regulating coal- and oil-fired EGUs in this final rule.
The proposed definition contained two primary
elements: (1) the unit must be capable of combusting
sufficient amounts of coal or oil to generate the
equivalent of 25 megawatts electrical output; and (2)
the unit must have fired coal or oil for more than 10.0
percent of the average annual heat input during the
previous 3 calendar years or for more than 15.0
percent of the annual heat input during any one of
those calendar years. 76 FR 25025. We further stated
that for a unit to be “capable of combusting” coal or oil
the unit must have a permit that authorized the
combustion of coal or oil and also have the appropriate
fuel handling facilities on-site. Id.
As explained in the proposed rule, natural gas-fired
EGuUs were not included in the December 2000 listing
so such units that otherwise met the CAA section
112(aX8) definition of EGU because of natural gas
combustion are not subject to the final rule. In the
520a
proposed rule, we stated that an EGU that “combusts
natural gas exclusively or natural gas in combination
with another fuel where the natural gas constitutes 90
percent or more of the average annual heat input
during the previous 3 calendar years or 85.0 percent
or more of the annual heat input during any one of
those calendar years” was not subject to the rule. Jd.
The references to 90 percent natura! gas combustion
over 3 years and 85 percent natural gas combustion in
any one year were included to align with the
definitions of “fossil fuel-fired” so that it would be clear
that units combusting primarily natural gas would not
be considered coal-fired, oil-fired, or IGCC EGUs if
they burned 10 percent or less of coal, oil, or synthetic
gas derived from coal or solid oil over 3 years or 15
percent or less of such fuels in any one year. We did
not intend to suggest that to be considered a fossil fuel-
fired EGU a natural gas-fired unit that is not a coal-
fired or oil-fired EGU would have to combust natural
gas that exceeded the 10 percent/15 percent thresholds
set forth in the proposed rule. In fact, in 40 CFR
63.9983 of the proposed rule, we stated that “lajny
EGU that is not a coal- or oil-fired EGU and combusts
natural gas more than 10.0 percent of the average
annual heat input during the previous 3 calendar
years or for more than 15.0 percent of the annual heat
input during any one of those calendar years” is not
subject to this subpart.
We further explained that the percentages included
in the definition of “fossil fuel-fired” would prevent
units that primarily combusted fuels other than fossil
fuels from being subjected to the final rule:
Units that do not meet the definition of fossil-fuel
fired would, in most cases, be considered IB units
subject to one of the Boiler NESHAP. Thus, for
521la
example, a biomass-fired EGU, regardless of size, that
utilizes fossil fuels for startup and flame stabilization
purposes only (i.e., less than or equal to 250 MMBtu/hr
and used less than 10.0 percent of the average annual
heat input during the previous 3 calendar years or less
than 15.0 percent of the annual heat input during any
one of those calendar years) is not considered to be a
fossil fuel-fired EGU under this proposed rule. The
EPA has based its threshold value on the definition of
“oil-fired” in the ARP found at 40 CFR 72.2. As EPA
has no data on such use for (e.g.) biomass co-fired
EGUs because their use has not yet become common-
place, we believe this definition also accounts for the
use of fossil fuels for flame stabilization use without
inappropriately subjecting such units to this proposed
rule. Id.
Thus, in the proposed rule, we intended to create
thresholds to determine when a unit is fossil fuel-fired
and for which fossil fuel the unit is fossil fuel-fired. We
intended to include a unit combusting more than the
defined amount of coal in one of the coal-fired EGU
subcategories. If a unit is not coal-fired and it is
combusting more than the defined amount of oil, we
intended to include the unit in one of the oil-fired EGU
subcategories. We also intended to make clear that
EGUs that are neither coal-fired nor oil-fired but
combust more than the defined amount of natural gas
are natural gas-fired EGUs not subject to the final
standards. However, the definitions, as proposed, were
not sufficiently descriptive.
For example, we included a definition for “coal-fired
electric utility steam generating unit” that did not
include the requirement that the unit must combust
coal for at least 10 percent of the heat input over 3
years or 15 percent of the heat input in any one year.
522a
Instead, in the proposed rule we indicated that a unit
was coal-fired if it burned coal in any amount. We did
not intend to define a unit as coal-fired if it burned coal
that accounted for 10 percent or less over 3 years or 15
percent of less in any one year, as that would be
inconsistent with the definition of fossil fuel-fired and
the definitions for the oil-fired EGU subcategories.
Under the proposed rule construct, a unit that
combusts mostly biomass and less than 10 percent coal
over 3 years would not be a coal-fired EGU because it
would not meet the “fossil fuel-fired” definition. But a
unit burning mostly petroleum coke and less than 10
percent coal over 3 years might be considered a coal-
fired EGU because it would meet the definition of
“fossil fuel-fired” and be burning some coal, even
though that level of coal combustion alone would not
be sufficient to make the unit “fossil fuel-fired” for coal.
That result is at odds with our intent. The same would
hold true for an EGU that combusts mostly natural
gas and less than 10 percent synthetic gas derived
from coal] over a 3-year period. Our proposal preamble
makes clear that we did not intend this result because
we specifically stated that units burning 90 percent or
more natural gas over a 3-year period would be
considered natural-gas fired EGUs. 76 FR 25025.
In addition, we proposed to define “[u]nit designed
to burn solid oil fuel subcategory” to include any EGU
that burned a solid fuel derived from oil for more than
10.0 percent of the average annual heat input during
the previous 3 calendar years or for more than 15.0
percent of the annual heat input during any one of
those calendar years, either alone or in combination
with other fuels. We also included the 10 percent/15
percent thresholds in the definition for the liquid oil
subcategory, but, as stated above, we did not include
the thresholds in the definition of “coal-fired” EGU.
523a
Therefore, there would be some confusion for a source
that blended coal with solid oil derived fuel (e.g.,
petroleum coke). For example, the owner or operator
of an EGU that burned sufficient solid oil-derived fuel
that accounted for 80 percent of the heat input in a
given year and the remainder of the fuel was coal
would not be sure which standard applied because the
definitions in the proposed rule were internally
inconsistent.
For these reasons, we are revising the definitions for
“coal-fired electric utility steam generating unit,”
“integrated gasification combined cycle electric utility
steam generating unit,” and “oil-fired electric utility
steam generating unit,” and we are adding a definition
of “natural-gas fired electric utility steam generating
unit” as set out in 40 CFR 63.10042.
In addition to these changes, we are revising the
definition of “fossil fuel-fired” based on comments. We
are revising the definition to remove the heat input
equivalent of 25 MW because commenters noted that
the equivalency used (taken from 40 CFR part 60,
subpart Da) could not be applied consistently because
of differing boiler efficiencies. Commenters noted that
owners/operators were familiar with the use of the
“MW” term for the boilers and boilers include
nameplate capacities that are readily identifiable.
We are also including a revision to the definition so
that the fossil fuel combustion thresholds of 10 percent
over 3 consecutive years and 15 percent in one year are
evaluated after the applicable compliance date of the
final rule on a rolling basis. Commenters correctly
noted that some existing coal- and oil-fired EGUs will
convert their units to alternative fuels (e.g., natural
gas or biomass) and if the definition were finalized as
524a
proposed such units could be improperly subjected to
the final standards.
The new definition is set out in 40 CFR 63.10042.
For clarity, we are also removing the definition of
“[ujnit designed to burn liquid oil fuel subcategory,”
revising the definition of “[u]nit designed to burn solid
oil fuel subcategory,” adding definitions for the
continental and non-continental liquid oil-fired EGU
subcategories, and adding a definition of a limited-use
liquid oil-fired EGU as set out in 40 CFR 63.10042.
In the proposed rule, we stated that we believed
EGUs may at times not meet the definition of an EGU
subject to this subpart. For example, we explained
that there may be some cogeneration units that are
determined to be covered under the Boiler NESHAP.
Such unit(s) may make a decision to increase the
proportion of production output being supplied to the
electric utility grid, thus causing the unit(s) to meet
the EGU cogeneration criteria (i.e., greater than one-
third of its potential output capacity and greater than
25 MW). In the preamble to the proposed rule, we
indicated that a unit subject to one of the Boiler
NESHAP that increases its electricity output and
meets the definition of an EGU would be subject to the
EGU NESHAP for the 6-month period after the unit
meets the EGU definition. n310 76 FR 25026.
Assuming the EGU did not meet the definition of an
EGU following that initial occurrence, at the end of the
6-month period it would revert back to being subject to
the Boiler NESHAP, or other applicable standard. We
solicited comment on the extent to which situations
like this might occur, how the EPA should address
situations where units change applicability, and
whether we should include provisions similar to those
525a
included in the final CISWI (40 CFR 60.2145) to
address such situations. Jd.
n310 Although we clearly stated the intent to
require sources to comply for 6 months after meeting
the definition of an EGU, we inadvertently failed to
include the provision in the proposed rule.
Several commenters asked the Agency to include
provisions in the final rule that would address
situations like the ones described in the preamble to
the proposed rule. Because appiicability to the final
rule is based in part on the statutory definition of an
EGU is CAA section 112(aX8), similar to the situation
with units combusting solid waste under CAA section
129(g)(1) (e.g., CISWI Rule), we are adopting provi-
sions in the final rule that are based on the fuel
switching provisions of the final CISWI Rule (See
Final CISWI Rule, 40 CFR 60.2145). For example, a
cogeneration unit that did not historically provide
more than one third of its potential electrical output
capacity to a power distribution system could change
its output and provide more than 25 megawatts
electrical output to any power distribution system for
sale. Such units would be subject to MATS. If the
cogeneration unit later reduced its output such that it
no longer met the definition of an EGU, that source
would nevertheless remain subject to MATS for at
least 6 months from the date that the unit first
qualified as an EGU.
In addition, we are finalizing a provision whereby
you may opt to remain subject to the provisions of this
final rule, unless you combust solid waste, in which
case you are a solid waste incineration unit subject to
standards under CAA section 129 (e.g., 40 CFR part
60, subpart CCCC (New Source Performance Standards
(NSPS) for Commercial and Industrial Solid Waste
526a
Incineration Units), or subpart DDDD (Emissions
Guidelines (EG) for Existing Commercial and
Industrial Solid Waste Incineration Units)). We
believe the provision to opt to remain subject to this
final rule will ameliorate conditions where EGUs may
potentially move between NESHAP on a relatively
frequent basis. Notwithstanding the provisions of this
final rule, an EGU that starts combusting solid waste
is subject to standards under CAA section 129, and the
unit remains subject to those standards until the unit
no longer meets the definition of a solid waste
incineration unit consistent with the provisions of the
applicable CAA section 129 standards.
The changes to the definitions described above
provide clarity to sources, permitting agencies, and
the public about the applicability of the rule and help
ensure that sources are appropriately covered by the
regulation.
B. Subcategories
In this final rule, the EPA is adding subcategories
for limited-use oil-fired units and non-continental oil-
fired units and revising the definitions for the coal-
fired EGU subcategories.
The proposed rule subcategorized EGUs burning
coal into two subcategories: EGUs designed for coal
>/=8,300 Btu/lb and EGUs designed for virgin coal <
8,300 Btu/lb (low rank virgin coal). We received a
number of comments indicating that the definition of
the low rank virgin coal subcategory was technically
deficient.
Under CAA section 112(d\1), the Administrator has
the discretion to “* * * distinguish among classes,
types, and sizes of sources within a category or
subcategory in establishing * * *” standards. The EPA
o27a
maintains that, normally, any basis for subcategoriza-
tion (i.e., class, type, or size) must be related to an
effect on HAP emissions that is due to the difference
in class, type, or size of the units. See 76 FR 25036-
25037. The EPA believes it is not reasonable to
exercise our discretion without such a difference
because if sources can achieve the same level of
emissions reductions notwithstanding a difference in
class, type, or size, the purposes of CAA section 112
are better served by requiring a similar level of control
for all such units in the category or subcategory. See
Lignite Energy Council v. EPA, 198 F. 3d 930, 933
(D.C. Cir. 1999) (“EPA is not required by law to
subcategorize—section 111[b][2] merely states that the
Administrator may distinguish among classes, types,
and sizes within categories of new sources” (emphasis
original)); See also CAA section 112(d)(1) (containing
almost identical language to CAA section 111, CAA
section 112(dX1) provides that “the Administrator
may distinguish among classes, types, and sizes of
sources within a category or subcategory in establish-
ing {] standards * * *”). Even if we determine that
emissions characteristics are different for units that
differ in class, type, or size, the Agency may still
decline to subcategorize if there are compelling policy
justifications that suggest subcategorization is not
appropriate. Jd.
When developing the proposed rule, we examined
the EGUs in the top performing 12 percent of sources
for Hg emissions. We determined that:
There were no EGUs designed to burn a non-
agglomerating virgin coal having a calorific value
(moist, mineral matter-free basis) of 19,305 kJ/kg
(8,300 Btu/lb) or less in an EGU with a height-to-depth
ratio of 3.82 or greater among the top performing 12
528a
percent of sources for Hg emissions, indicating a
difference in the emissions for this HAP from these
types of units. The boiler of a coal-fired EGU designed
to burn coal with that heat value is bigger than a boiler
designed to burn coals with higher heat values to
account for the larger volume of coal that must be
combusted to generate the desired level of electricity.
Because the emissions of Hg are different between
these two subcategories, we are proposing to establish
different Hg emission limits for the two coal-fired
subcategories. For all other HAP from these two
subcategories of coal-fired units, the data did not show
any difference in the level of the HAP emissions and,
therefore, we have determined that it is not reasonable
to establish separate emissions limits for the other
HAP. 76 FR 25036-67.
Based on this determination, we proposed to
establish two subcategories with separate Hg limits.
Comments on the proposed rule indicate that we
correctly identified the EGUs that should be included
in each subcategory, but the comments also demon-
strated that we made certain incorrect conclusions
that require us to revise the definitions of our coal-
fired EGU subcategories. The revised definitions
ensure that the EGUs we identified at proposal as
having different Hg emissions remain in one
subcategory.
As stated above, we believed at proposal that the
boiler size was the cause of the different Hg emissions
characteristics that led us to propose subcategorization,
but many commenters indicated that it was not the
boiler size but the fact that the EGUs burned a
nonagglomerating virgin coal having a calorific value
(moist, mineral matier-free basis) of less than 19,305
kJ/kg (8,300 Btu/Ib) (low rank virgin coal) that causes
529a
the disparity in Hg emissions. Several commenters
indicated that their EGUs were designed to burn and
burned low rank virgin coal but the units did not meet
the height-to-depth ratio that EPA proposed. For
example, the height-to-depth ratio of certain EGUs in
this subcategory is in fact 3.5, not 3.82. Further, there
are other EGUs in this subcategory that are
circulating fluidized bed (CFB) combustion units
which do not meet the height-to-depth ratio parame-
ters in the proposed rule, nor are they anything like
the pulverized coal (PC) EGUs we initially identified
as having the 3.82 height-to-depth ratio.
In addition to the comments concerning EGUs firing
this coal, we received comments from at least two
commenters indicating that the EPA should clarify in
which subcategory a unit belongs when it does not
burn low rank virgin coal but is designed to combust
low rank virgin coal and has a height-to-depth ratio of
greater than 3.82. Commenters also indicated that
CFB units that are burning coal-refuse*™ or other
nonagglomerating virgin coal having a calorific value
(moist, mineral matter-free basis) of 19,305 kJ/kg
(8,300 Btu/lb) or greater are “designed to burn” any
type of coal. Owners of CFB units that are not firing
low rank virgin coal asked which subcategory they
belong to based on their ability to burn any type of coal
(including low rank virgin coal) without modification.
These commenters also indicated that some coal
refuse that is combusted has a heating value less than
8,300 Btu/lb but is not “virgin coal.” It was unclear to
which subcategory they belonged since the proposed
511 Tt is our understanding that no unit combusts coal-refuse
from nonagglomerating virgin coal having a calorific value
(moist, mineral matter-free basis) of less than 19,305 kJ/kg (8,300
Btw/Ib).
530a
rule did not in fact require the unit to burn any specific
coal, instead only requiring the unit be “designed” to
burn lower Btu coal.
Based on the comments received, we reevaluated the
subcategory definitions because we were concerned that
the definitions we proposed would improperly
categorize a number of the EGUs in both subcatego-
ries. We concluded that we should not maintain the
proposed definition for “[uJnits designed for coal <
8,300 Btu/lb” and exclude the CFB units and PC EGUs
with a height-to-depth ratio less than 3.82 that
combusted low rank virgin coal.
We were equally concerned that the subcategory
definitions not be revised in a manner that would
move EGUs that we believed the data show could
comply with a more stringent standard into a
subcategory with a less stringent standard because,
aside from the type of EGUs we identified, all other
classes, types, and sizes of EGUs were represented
among the top performing 12 percent for Hg in the
>/=8,300 Btu/lb subcategory. We were particularly
concerned about the CFB units because other CFB
units are well represented among the best performing
EGUs for Hg in the >/=8,300 Btu/lb subcategory, but
the CFB units burning low rank virgin coal are not
achieving the same levels of Hg emissions control.
Including the best performing CFB units from the
other subcategory in the low rank virgin coal
subcategory would likely lead to a Hg standard as
stringent as the standard for EGUs in the >/=8,300
Btu/lb subcategory because the CFB units from the
other subcategory would be used to establish the floor.
We believe that result would be inconsistent with the
intent of the proposed rule. We were also concerned
about the information that some EGUs that fired low
53la
rank virgin coal had a height-to-depth ratio of 3.5, not
3.82, and that some EGUs that fired other ranks of
coal had a height-to-depth ratio greater than 3.82. For
these reasons, we did not revise the definition to
include CFB units and PC EGUs with a height-to-
depth ratio greater than 3.5.
After fully considering the available information,
including the comments received, we have concluded
that it is appropriate to continue to base the
subcategory definitions, at least in part, on whether
the EGUs were designed to burn and, in fact, did burn
low rank-virgin coal, but that it is not appropriate to
continue to use the height-to-depth ratio criteria
because that approach would potentially exclude
EGUs we identified as having different Hg emission
characteristics and include EGUs that did not have
different emissions characteristics. We recognize that
some commenters have taken the position that it is
unlawful to subcategorize based on factors such as fuel
type but nothing in the statute prohibits such an
approach and the case law supports this approach to
the extent courts have considered subcategorization
based on such factors. See Sierra Club v. Costle, 657 F
2d 298, 318-19 (D.C. Cir. 1981) (differing pollutant
content of input material can justify a different
standard based on subcategorization authority to
“distinguish among classes, types and sizes within
categories of new sources”). Furthermore, we believe
had Congress intended to prohibit the EPA from
subcategorizing based on an EGU being designed to
use and using a certain material input (e.g., fuel) it
would have clearly stated such intent in the CAA.
However, we believe the Agency could decline to
exercise its discretion to subcategorize even if the
potential result would be the prohibition of the use of
some materials if the circumstances warranted. We
532a
note that even if we did not subcategorize on the final
basis selected, the Hg emissions standard of 1.2E0
Ib/Tbtu for the “unit designed for coal >/=8,300 Btu/1b”
would remain the same.
We considered basing the subcategory solely on an
EGU being designed to burn and burning low rank
virgin coal. We decided not to do so because we were
concerned that such a definition would allow sources
to potentially meet the definition by combusting very
small amounts of low rank virgin coal. For example,
an EGU on the east coast (or any other region) that
was not designed to burn and did not routinely burn
low rank virgin coal could import one truck full of low
rank virgin coal and burn a very small quantity of it
periodically to meet the subcategory definition. To
avoid creating this potential loophole, we considered
other characteristics that would distinguish EGUs
combusting low rank virgin coal.
We determined that these EGUs are universally
constructed “at or near” a mine containing low rank
virgin coal because it is not cost-effective to transport
large quantities of such fuel long distances. Further-
more, we believe that this subcategory of EGUs are
almost always built at a mine and limited
transportation of the coal is only required as the mine
face moves over the course of time. Many such EGUs
construct dedicated rail lines, private roads, or
conveyor systems to transport the coal to the EGU as
the mine face moves. We obtained information from
data acquired to develop the CSAPR indicating that
the longest distance any EGU firing low rank virgin
coal transports that coal is 40 miles. We believe that
this distance is near the outer limits for the transport
of such coal, but, even for those EGUs, the EGUs were
constructed closer to a now idle mine or closer to the
533a
working face of a mine that has now expanded away
from the EGU site. For these reasons, we are including
a requirement that the unit be constructed and
operated at or near a mine containing the low rank
virgin coal it burns.
We are revising the coal-fired EGU subcategory
definitions as set out in 40 CFR 63.10042.
We believe the revised subcategory definitions are
reasonable for all the reasons set forth above. The
revised definitions maintain the EGUs we identified
as having different Hg emissions characteristics in one
subcategory and the definitions prevent other EGUs
that are not firing low rank virgin coal from being
required to comply only with the less stringent Hg
emission standard.
As discussed in response to comments, we do not
believe that additional subcategorization of other coal-
fred EGUs is reasonable or appropriate. All other
coal-fired EGUs that are not designed to burn and are
burning low rank virgin coal are represented among
the best performing sources for Hg, such that no
ent exists to support that the Hg emissions from
those EGUs are different. In any case, even if
emissions are somewhat different as some comment-
ers suggest, we would decline to exercise our discretion
because the data demonstrate that the best
performing EGUs designed to burn and burning all
other ranks of coal are able to achieve the MACT level
of control using currently available controls and other
HAP emission reduction mechanisms (e.Z., coal
washing) for the >/=8,300 Btu/lb subcategory.
A second issue related to subcategorization concerns
non-continental liquid oil-fired EGUs. At proposal, the
EPA did not have sufficient emissions data from non-
534a
continental liquid oil-fired EGUs upon which to base a
subcategory and took comment on the issue. The data
have since been provided in response to the ICR and
we received comments suggesting that a non-
continental subcategory is appropriate based on the
location of such units, the limited availability of
alternative fuel sources, and the fact that the
emissions characteristics of such units are distinct
from continental liquid oil-fired EGUs. The EPA has
evaluated the data and comments and we agree that a
subcategory is warranted based for the reasons
suggested by the commenters. Therefore, the Agency
is finalizing the liquid oil-fired EGU subcategories of
“continental” and “non-continental.”
Lastly, the EPA did not have sufficient information
on limited-use liquid oil-fired EGUs upon which to
base a subcategory at proposal because some sources
required to test under the ICR did not submit the data
until after proposal. We took comment on whether a
limited-use subcategory was warranted. Commenters
indicated that their units were a different class and
type of units because many of them were only called to
service to address reliability issues associated with, for
example, natural gas curtailments. The commenters
further indicated that their units are different because
of the generally infrequent use and the sporadic, and
at times frequent, start-up and shutdown periods (e.z.,
they are often only required to run for a couple of
hours). These factors would lead to differences in the
emissions characteristics for these units such that a
numeric standard based on base load units would not
likely be achievable during the very limited times that
these limited use oil-fired units operate. Based on
comments received and our own analysis, we are
finalizing a subcategory for limited-use liquid oil-fired
535a
EGUs as discussed further elsewhere in this
preamble.
C. Emission Limits
The proposed rule included numerical emission
limits for PM, Hg, HCl, HF, SO:2, total HAP metals,
and individual HAP metals, depending on the
subcategory and specific situation. These proposed
limits resulted from calculations of MACT floors using
information and data available to the Agency prior to
proposal, as required by CAA section 112. Based on
information and data received during the comment
period, we have made data and calculation corrections
where necessary and then re-ranked the best
performing units in the MACT floor pools. Based on
the new ranking, a limited number of the emission
limits in the final rule have changed from those
proposed.
In addition to adjustments to the emission limits
themselves, we are finalizing several] other changes to
the emission standards that will simplify and improve
compliance for sources without compromising the
toxics reductions achieved. One key change, as
discussed elsewhere in this notice, is that we have
changed the surrogate for non-mercury metallic HAP
from total particulate matter (PM) to filterable PM for
coal-fired and solid oil-derived EGUs. This change is
based on information provided in comments and our
own conclusion that measurement of filterable PM
provided assurance of equivalent HAP emissions
control. Most of the non-mercury metal HAP, for which
PM is a surrogate, are filterable PM and the one that
is not (Se) is well controlled by the limit on acid gases.
Using filterable PM as the surrogate will allow us to
use continuous PM monitoring systems, which
536a
measure filterable (but not total) PM, thereby
providing a more continuous measure of compliance.
For liquid oil-fired EGUs, based on comments
received and corrections made to the data submitted,
we have added a filterable PM limit in the final rule
as an alternative equivalent standard for the total
metal-HAP limit in the proposed rule. In addition, as
discussed elsewhere in this notice, we have added
measurement of the moisture content of the oil (with a
1 percent limit) as an alternate compliance assurance
measure for liquid oil-fired EGUs for determining
compliance with the HCl and HF limits. Direct
measurement of HCl] and HF remains a compliance
demonstration method in the final rule. Finally, as
discussed in section VI.D of this notice, the final work
practice standard consisting of burner tune-ups, much
like those required for organic HAP control, for those
limited-use liquid oil-fired EGUs whose annual
capacity factor is less than 8 percent.
D. Work Practice Standards for Organic HAP
Emissions
As noted earlier in section V.D., the final rule
includes a work practice standard for organic HAP,
including dioxins and furans, applicable to all EGUs.
As noted in section V.D. above, the majority of
emissions of these pollutants are below the detection
levels of EPA test methods and, therefore, are
impractical to measure. The work practice standard,
described below, is a practical approach to ensuring
that equipment is maintained and run so as to
minimize emissions of dioxins and furans, and we
expect it to be more effective than establishing a
numeric standard that cannot reliably be measured or
monitored. The work practice also applies to the
537a
limited-use liquid oil-fired subcategory included in the
final rule.
The work practice involves maintaining and
inspecting the burners and associated combustion
controls (as applicable), tuning the specific burner
type to optimize combustion, obtaining and recording
CO and NOx values before and after the burner
adjustments, keeping records of activity and
measurements, and submitting a report for each tune-
up conducted. In Table 3 of the final regulation, we
have clarified that this refers to performance tune-
ups, not tests, and have addressed the frequency
requirement as discussed in response to comments
about the appropriateness of the 18-month frequency.
The provisions of 40 CFR 63.10006(h\i) refer to 40
CFR 63.10021(e) for the specific steps required to be
part of the periodic tune-up. We have also adjusted the
language in the final rule to recognize the value of
automated boiler optimization tools such as neural
network systems.
Under the final rule, the tune-up must be conducted
at each planned major outage and in no event less
frequently than every 36 calendar months, with an
exception that if the unit employs a neural-network
system for combustion optimization during hours of
normal unit operation, the required frequency is a
minimum of once every 4 years (48 calendar months).
Initial compliance with the work practice standard of
maintaining burners must occur within 180 days of
the compliance date of the rule. The initial compliance
demonstration for the work practice standard of
conducting a tune-up may occur prior to the
compliance date of the rule, but must occur no later
than 42 months (36 months plus 180 days) from the
compliance date of the rule or, in the case of units
538a
employing neural network combustion controls, 54
months (48 months plus 180 days). If the tune-up
occurs prior to the compliance date of the rule, you
must maintain adequate records to show that the
tune-up met the requirements of this standard.
We have made a number of specific changes to
address what to do for repairs that may require longer
term corrective actions, additional methods for
evaluating combustion effectiveness, and clarification
on procedures for recording CO and NOx information.
There were specific comments that opposed the
reference to manufacturer specifications, if available.
We retained this language in the final rule, but note
that these specifications apply only to the extent
applicable. Specifically, if manufacturer specifications
only address equipment or conditions that are no
longer present given current boiler operations, then
those specifications are not applicable and other
combustion engineering best practice procedures for
that burner type would apply. We have also clarified
that portable emission monitoring equipment may be
used to collect the required emissions optimization
data regarding pre- and post-tune-up CO and NOx
emission levels.
E. Requirements During Startup, Shutdown, and
Malfunction
We proposed numerical emission standards that
would apply at all times, including during periods of
startup, shutdown, and malfunction. Although at
proposal we stated that we were not setting a different
standard for startup and shutdown, we did propose
different standards for startup and shutdown by our
inclusion of the default values described below, which
applied only during startup and shutdown. Specifi-
cally, we stated:
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To appropriately determine emissions during
startup and shutdown and account for those emissions
in assessing compliance with the proposed emission
standards, we propose use of a default diluent value of
10.0 percent O[2] or the corresponding fuel specific
CO[2] concentration for calculating emissions in units
of Ib/MMBtu or lb/TBtu during startup or shutdown
periods. For calculating emissions in units of Jb/MWh
or lb/GWh, we propose source owners use an electrical
production rate of 5 percent of rated capacity during
periods of startup or shutdown. We recognize that
there are other approaches for determining emissions
during periods of startup and shutdown, and we
request comment on those approaches. We “urther
solicit comment on the proposed approach described
above and whether the values we are proposing are
appropriate.
We proposed application of the respective emission
limits during periods of startup and shutdown and use
of default values to calculate the emission limits. The
standards that apply at all times other than startup
and shutdown are production-based limits, which is
why we proposed the default values. The default
values were meant to account for the fact that during
startup and shutdown events, production (in this case
the generation of electricity) is by definition nonexist-
ent. Thus, in effect, we proposed a separate standard
to apply during startup and shutdown.
We received a variety of comments on the proposed
standards that would apply during startup and
shutdown. Many commenters pointed to the lack of
data in the record concerning emissions that occur
during periods of startup and shutdown. They further
asserted that emissions during these periods can be
highly variable in light of the sequence of events that
540a
occurs during the startup and shutdown of an EGU.
Although a number of commenters supported the use
of the diluent factor approach, including the default 5
percent of rated capacity, during startup/shutdown
periods, other commenters questioned the feasibility
of collecting additional data during such periods and
had concerns regarding the reliability of measure-
ments obtained from EGUs during such periods.
In reaponse to the Agency's ICR to the utility
industry, seven owners or operators indicated that
they provided startup and shutdown data for their
EGUs. These data were submitted in response to the
requirement in the ICR to provide all available data
from the 5 years prior to the date the ICR was issued.
Of these data, there were almost no HAP data for
startup and shutdown periods and almost all of the
data failed to meet our data quality requirements.*”
312 In response to the ICR, we also received SO, CEMS data
and the Agency had additional SO, CEMS data available through
the CAMD ARP database. We are not able to identify specific
periods of start-up and shutdown in either the ICR CEMS data
or the CAMD ARP data, and the ICR respondents do not indicate
that the ICR data includes periods of startup and shutdown. We
set the emission limits for SO,and HC) using the data provided
to the EPA from the 2010 ICR, not the CAMD data, since those
data were taken concurrently under the same specified operating
conditions using the same fuel. We used the SO,CEMS data that
was submitted in response to the ICR by converting it to single
point data to correlate to the data from units that did not provide
CEMS data from the relevant testing period. The emissions limits
for the NESHAP incorporated variability by applying the 99
percent UPL to the average emissions developed from the stack
test data and SO, CEMS data that was converted to stack test
data. Thus, we did not have data on which to establish an SO,
standard during periods of startup and shutdown and the
numeric standards do not apply to those periods in the final rule.
In contrast, the NSPS for SO, is applicable during periods of
startup and shutdown since the long term CAMD ARP CEMS
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Thus, we do not have sufficient data on emissions that
occur during startup and shutdown on which to set
emission standards. We are therefore establishing
work practice standards rather than numeric
emissions standards for periods of startup and
shutdown in the final rule. Before we describe those
work practices, we first address what constitutes
startup and shutdown.
Several commenters had an expansive view of what
constitutes startup and shutdown. We disagree with
these commenters that asserted that periods of “load
swings” should be considered “startup” or “shutdown,”
as they are generally routine, normal operations with
production (i.e., generation of electricity) taking place.
We maintain that the standards as promulgated
account for any variability in emissions that may occur
during these periods over a 30-day averaging period,
and commenters have provided no data that cause us
to doubt that determination. We have included
definitions of startup and shutdown in the final rule
that are consistent with the definitions in the proposed
rule. At proposal, we defined startup as the setting in
operation of an affected source or portion of an affected
source for any purpose, and shutdown as the cessation
of operation of an affected source or portion of an
affected source for any purpose.
Commenters sought more clarity regarding the
meaning of these terms as applied to EGUs, so we are
data were used to determine the average performance of the best
demonstrated technology. Those long term data were assumed to
incorporate process variability including that associated with fuel
and process/operational changes and periods of startup and
shutdown.
542a
revising the definitions in the final rule as set out in
40 CFR 63.10042.
These interpretations are tailored for EGUs and are
consistent with the definitions of “startup” and “shut-
down” contained in the 40 CFR part 63, subpart A
General Provisions. We believe these revised defini-
tions address the comments and are rational based on
the fact that EGUs function to provide electricity
primarily for sale to the grid but also at times for use
on-site; therefore, EGUs should be considered to be
operating normally at all times electricity is gener-
ated. We further believe these revised definitions
address what some commenters describe as “warm”
and “hot” startups as long as the EGU is shutdown
(i.e., no fuel fired and no electricity generation) prior
to the “warm” or “hot” startup period.
As for the work practices, in this final rule, the EPA
is requiring sources to operate using either natural gas
or distillate oil for ignition during startup. The EPA
also is requiring sources to vent emissions to the main
stack(s) and operate all control devices necessary to
meet the normal operating standards under this final
rule (with the exception of dry scrubbers and SCRs)
when coal, solid oil-derived fuel, or residual oil is fired
in the boiler during startup or shutdown. It is the
responsibility of the operators of EGUs to start their
dry scrubber and SCR systems appropriately to
comply with relevant standards applicable during
normal operation.
The EPA carefully considered fuels and potential
operational constraints of air pollution control devices
(APCDs) when designing its work practices for periods
of startup and shutdown. The EPA notes that there is
no technical barrier to burning natural gas or
distillate oil for longer portions of startup or shutdown
543a
periods, if needed, at a boiler, and the HAP emission
reduction benefits warrant additional utilization of
such fuels until the temperature and stack emissions
pressure is sufficient to engage the APCDs. The EPA
is aware that SCR systems with ammonia injection
need to be operated within a prescribed and relatively
narrow temperature window to provide NOx reduc-
tions. Further, the EPA is aware that dry scrubbers
also need to be operated close to flue gas saturation
temperature. Because these devices have specific
temperature requirements for proper operation, the
EPA notes in its work practices that it is the
responsibility of the operators of EGUs to start their
SCR and dry scrubber systems appropriately to
comply with relevant standards applicable during
normat operation.
Some commenters have asserted that firing of fuel
oil during periods of startup and shutdown constrains
operation of PM controls (ESPs and baghouses)
because under cooler conditions, acids and tars can
condense on surfaces in these controls. The comment-
ers assert that such condensation can cause
detrimental impacts on hardware and operation of
these controls, and could cause safety concerns. The
EPA understands that concerns with acidic and tarry
deposits are related to firing of heavy (residual) oil and
hot distillate oil. Accordingly, with residual fuel oil
firing, site-specific flue gas temperature and oxygen
(O2) concentration thresholds may be applicable to
minimize condensation of acids and tars and thereby
minimize any potential for detrimental impacts on
hardware and any safety concerns. However, the EPA
fotes that its work practice requirements provide
flexibility to the operator to take appropriate site-
specific remedial measures, if needed. The EPA
further notes that boilers have several options to
544a
prevent detrimental impacts by: (1) Using startup
fuels, natural gas or distillate oil, until appropriate
flue gas conditions have been reached and then fire
residual oil; (2) pre-coating the PM control surfaces*®
with an alkaline powder (e.g., limestone); (3) installing
chemically resistant bags*™ in baghouses if applicable;
and (4) using low-sulfur oils. The EPA also notes that
currently the industry has many operational residual
oil-fired boilers that are started up with either natural
gas or distillate fuel oil. At these boilers, the transition
from the startup fuel, distillate oil or natural gas, to
residual oil is already being practiced without unac-
ceptable impacts on APCDs including PM controls,
which are operated to meet applicable opacity limits.
Based on this experience and the options described
above, those boilers where residual oil is used for
either a part of the startup period, or as the main fuel,
will also be able to operate their PM controls to meet
the work practice requirements of the rule. Note that
coal firing is done at high enough temperatures that
concerns with condensation are not relevant. None of
the commenters have specifically commented on this
aspect of coal firing.
The EPA is not aware of any operational constraints
applicable to operation of wet scrubbers during
startup that could cause detrimental impacts on wet
scrubber hardware and safety concerns and none of
the commenters have commented on this aspect of wet
scrubber operation.
313 Coal Power, May 1, 2007: Attp:/ /www.coal powermag.com /
plant_design / Coal-Plant-O-and-M-River-Locks-and-Barges-Are-
an-Aging-Workforce-Too 36.html.
344 Neundorfer: Lesson #r, p.4-7, Table 4-1: Attp://www.
neundorfer.com / FileUploads/CMSFiles/Fabric%20Filter%#20M
aterial [0].pdf.
545a
Finally, the EPA notes that dry sorbent injection
(DSI) can be applied across a very broad temperature
range and will be engaged when residual oil or coal is
fired in a boiler to comply with HC] requirements.
Again, no comments have been received on this aspect
of DSI operation.
This final rule requires work practice standards for
emissions during startup and shutdown, and the rule
requires sources to measure and report their
emissions at al] times, including periods of startup and
shutdown, when continuous monitoring is used to
demonstrate compliance. Data collected under this
final rule will provide the EPA with information to
more fully analyze this issue and address it during the
8-year review established under CAA section 112.
We now address malfunctions. In contrast to the
exclusion of startup and shutdown period emissions
from 30-boiler operating day rolling average emis-
sions, the final rule requires inclusion of emissions
during periods of source or APCD malfunction. We
have concluded that when combined with the availa-
bility of an affirmative defense as described below, this
is an appropriate and practical approach.
As mentioned earlier, periods of startup, normal
operations, and shutdown are all predictable and
routine aspects of a source’s operations. However, by
contrast, malfunction is defined as a “sudden,
infrequent, and not reasonably preventable failure of
air pollution control and monitoring equipment,
process equipment or a process to operate in a normal
or usual manner * * *” (40 CFR 63.2). The EPA has
determined that CAA section 112 does not require that
emissions that occur during periods of malfunction be
factored into development of CAA section 112
standards. Under CAA section 112, emissions standards
546a
for new sources must be no less stringent than the
level “achieved” by the best controlled similar source
and for existing sources generally must be no less
stringent than the average emission limitation
“achieved” by the best performing 12 percent of
sources in the category. There is nothing in CAA
section 112 that directs the Agency to consider
malfunctions in determining the level “achieved” by
the best performing or best controlled sources when
setting emission standards. Moreover, while the EPA
accounts for variability in setting emissions standards
consistent with the CAA section 112 case law, nothing
in that case law requires the Agency to consider
malfunctions as part of that analysis. Clean Air Act
section 112 uses the concept of “best controlled” and
“best performing” unit in defining the level of
stringency that CAA section 112 performance
standards must meet. Applying the concept of “best
controlled” or “best performing” to a unit that is
malfunctioning presents significant difficulties, as
malfunctions are sudden and unexpected events.
Further, accounting for malfunctions would be
difficult, if not impossible, given the myriad different
types of malfunctions that can occur across all sources
in the category and given the difficulties associated
with predicting or accounting for the frequency,
degree, and duration of various malfunctions that
might occur. As such, the performance of units that are
malfunctioning is not “reasonably” foreseeable. See,
e.g., Sierra Club v. EPA, 167 F. 3d 658, 662 (D.C. Cir.
1999) (The EPA typically has wide latitude in
determining the extent of data-gathering necessary to
solve a problem. We generally defer to an agency's
decision to proceed on the basis of imperfect scientific
information, rather than to “invest the resources to
conduct the perfect study.”). See also, Weyerhaeuser v.
547a
Costle, 590 F.2d 1011, 1058 (D.C. Cir. 1978) (“In the
nature of things, no general limit, individual permit,
or even any upset provision can anticipate all upset
situations. After a certain point, the transgression of
regulatory limits caused by uncontrollable acts of
third parties, such as strikes, sabotage, operator
intoxication or insanity, and a variety of other
eventualities, must be a matter for the administrative
exercise of case-by-case enforcement discretion, not for
specification in advance by regulation.”). In addition,
the goal of a best controlled or best performing source
is to operate in such a way as to avoid malfunctions of
the source and accounting for malfunctions could lead
to standards that are significantly !ess stringent than
levels that are achieved by a well-performing non-
malfunctioning source. The EPA’s approach to
malfunctions is consistent with CAA section 112, and
we believe it is a reasonable interpretation of the
statute. This approach to malfunctions has been used
consistently in CAA section 112 and CAA section 129
rulemaking actions since the D.C. Circuit’s decision in
Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008)
vacated the SSM exemption contained in CFR
63.6(f)(1) and 40 CFR 63.6(h)(1). (See, e.g., National
Emission Standards for Hazardous Air Pollutants
From the Portland Cement Manufacturing Industry
and Standards of Performance for Portland Cement
Plants, 75 FR 54970 (September 9, 2010); Standards
of Performance for New Stationary Sources and
Emission Guidelines for Existing Sources: Sewage
Sludge Incineration Units; Final Rule, 76 FR 15372
(March 21, 2011).
In the event that a source fails to comply with the
applicable CAA section 112(d) standards as a result of
a malfunction event, the EPA would determine an
appropriate response based on, among other things,
548a
the good faith efforts of the source to minimize emis-
sions during malfunction periods, including preventa-
tive and corrective actions, as well as root cause
analyses to ascertain and rectify excess emissions. The
EPA would also consider whether the source’s failure
to comply with the CAA section 112(d) standard was,
in fact, “sudden, infrequent, not reasonably preventa-
ble” and was not instead “caused in part by poor
maintenance or careless operation.” 40 CFR 63.2 (def-
inition of malfunction).
Finally, the EPA recognizes that even equipment
that is properly designed and maintained can
sometimes fail and that such failure can sometimes
cause an exceedance of the relevant emission standard.
(See, e.g., State Implementation Plans: Policy
Regarding Excessive Emissions During Malfunctions,
Startup, and Shutdown (Sept. 20, 1999); Policy on
Excess Emissions During Startup, Shutdown,
Maintenance, and Malfunctions (Feb. 15, 1983)). The
EPA is therefore adding to the final rule an affirmative
defense to civil penalties for exceedances of emission
limits that are caused by malfunctions. See 40 CFR
63.10042 (defining “affirmative defense” to mean, in
the context of an enforcement proceeding, a response
or defense put forward by a defendant, regarding
which the defendant has the burden of proof, and the
merits of which are independently and objectively
evaluated in a judicial or administrative proceeding).
We also have added other regulatory provisions to
specify the elements that are necessary to establish
this affirmative defense; the source must prove by a
preponderance of the evidence that it has met all of the
elements set forth in 63.10001. (See 40 CFR 22.24).
The criteria ensure that the affirmative defense is
available only where the event that causes an
exceedance of the emission limit meets the narrow
549a
definition of malfunction in 40 CFR 63.2 (i.e., sudden,
infrequent, not reasonable preventable and not caused
by poor maintenance and or careless operation). For
example, to assert the affirmative defense success-
fully, the source must prove by a preponderance of the
evidence that excess emissions “[w]jere caused by a
sudden, infrequent, and unavoidable failure of air
pollution control and monitoring equipment, process
equipment, or a process to operate in a normal or usual
manner * * *” The criteria also are designed to ensure
that steps are taken to correct the malfunction, to
minimize emissions in accordance with section
63.10001 and to prevent future malfunctions. For
example, the source must prove by a preponderance of
the evidence that “[rjepairs were made as
expeditiously as possible when the applicable emission
limitations were being exceeded * * *” and that “[a]Jll
possible steps were taken to minimize the impact of
the excess emissions on ambient air quality, the
environment and human health * * *” In any judicial
or administrative proceeding, the Administrator may
challenge the assertion of the affirmative defense and,
if the respondent has not met its burden of proving all
of the requirements in the affirmative defense,
appropriate penalties may be assessed in accordance
with CAA section 113 (See also 40 CFR 22.27).
The EPA is including an affirmative defense in the
final rule as we have in other recent MACT rules so as
to balance the tension, inherent in many types of air
regulation, to ensure adequate compliance while
simultaneously recognizing that despite the most
diligent of efforts, emission limits may be exceeded
under circumstances beyond the control of the source.
The EPA must establish emission standards that
“limit the quantity, rate, or concentration of emissions
of air pollutants on a continuous basis.” 42 U.S.C.
550a
7602(k) (defining “emission limitation and emission
standard”). See generally Sierra Club v. EPA, 551 F.3d
1019, 1021 (D.C. Cir. 2008). Thus, the EPA is required
to ensure that section 112 emissions limitations are
continuous. The affirmative defense for malfunction
events meets this requirement by ensuring that even
where there is a malfunction, the emission limitation
is still enforceable through injunctive relief. While
“continuous” limitations, on the one hand, are
required, there is also case law indicating that in some
situations it is appropriate for the EPA to account for
the practical realities of technology. For example, in
Essex Chemical v. Ruckelshaus, 486 F.2d 427, 433
(D.C. Cir. 1973), the D.C. Circuit acknowledged that
in setting standards under CAA section 111 “variant
provisions” such as provisions allowing for upsets
during startup, shutdown and equipment malfunction
“appear necessary to preserve the reasonableness of
the standards as a whole and that the record does not
support the never to be exceeded’ standard currently
in force.” See also, Portland Cement Association v.
Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973). Though
intervening case law such as Sierra Club v. EPA and
the CAA 1977 amendments calls into question the
relevance of these cases today, they support the EPA’s
view that a system that incorporates some level of
flexibility is reasonable. The affirmative defense
simply provides for a defense to civil penalties for
excess emissions that are proven to be beyond the
control of the source. By incorporating an affirmative
defense, the EPA has formalized its approach to upset
events. In a Clean Water Act setting, the Ninth Circuit
required this type of formalized approach when
regulating “upsets beyond the control of the permit
holder.” Marathon Oil Co. v. EPA, 564 F.2d 1253,
1272-73 (9th Cir. 1977). But see, Weyerhaeuser Co. v.
55la
Costle, 590 F.2d 1011, 1057-58 (D.C. Cir. 1978)
(holding that an informal approach is adequate). The
affirmative defense provisions give the EPA the
flexibility to ensure both that its emission limitations
are “continuous” as required by 42 U.S.C. 7602(k), and
account for unplanned upsets and thus support the
reasonableness of the standard as a whole.
F. Testing and Initial Compliance
We have carefully evaluated the wide-ranging
comments on testing, continuous monitoring, and
other provisions regarding initial compliance demon-
strations, and we have made adjustments intended to
help streamline implementation while still ensuring
adequate demonstration of compliance with the
emission limits and other standards established under
this final rule. The significant changes include:
1. No Fuel Analysis Requirements
Apart from an alternative that allows you to analyze
fuel moisture for liquid oil-fired EGUs rather than
measuring HC! and HF, the final rule does not include
any of the fuel analysis requirements that were in the
proposed rule, either as part of initial compliance
demonstrations or ongoing compliance demonstra-
tions. In reviewing the results of the fuel analyses and
the expected range of results that would be received
from laboratories conducting the proposed analyses,
we determined that too many results would be
returned as “below detection level” and, thus, provide
little information to assist with rule implementation
and compliance oversight. Given the costs and efforts
involved, we determined that the proposed fuel
analysis requirements would not be an effective
compliance monitoring tool for this final rule.
552a
2. Clarification of Testing
We have clarified that where options for emission
limits apply (such as filterable PM versus non-
mercury HAP metals, or SO2 versus HCl), you need
only perform stack testing to demonstrate compliance
with the selected emission limit. For example, if you
elect to meet the individual non- mercury HAP metals
standards, you must conduct the Method 29 test for
the metals, and you do not have to conduct a Method
5 test for PM.
3. Low Emitting EGU Qualification
We have significantly modified the proposed
requirements to qualify as a LEE unit for a pollutant
other than Hg based on an initial performance test.
Under the proposed rule, the operating limit monitor-
ing provided additiona) assurance of compliance for a
source qualified for non-mercury LEE status based on
an initial compliance demonstration. Under the final
rule, to qualify for LEE status for pollutants other
than Hg, a unit must meet the LEE criteria for a series
of performance tests over a 3-year period to
demonstrate that the unit continues to perform well
below the standard for which the source has obtained
LEE status.
G. Continuous Compliance
The most significant changes to the testing and
monitoring requirements involve the procedures for
demonstrating continuous compliance. The proposed
rule contained different options involving CEMS,
periodic stack tests, fuel analysis, and various PM and
control device operating limits. The final rule greatly
simplifies the requirements and provides two basic
approaches for most situations: use of continuous
553a
monitoring (either CEMS or PM continuous paramet-
ric monitoring system, CPMS) or periodic quarterly
testing. The final rule does not contain the proposed
fuel analysis requirements. For periodic testing, the
proposed rule required testing every month or every 2
months. For those EGU owners or operators who
choose to use emissions testing to demonstrate
compliance, the final rule requires quarterly filterable
PM or non-mercury metals HAP, whether individual
or total metals, testing for coal- and liquid oil-fired
units. The rule requires quarterly HC] testing for coal-
fired units and quarterly HC) and HF testing, along
with site-specific monitoring for liquid oil-fired units
to ensure compliance with the HCl and HF standards.
The final rule also has a separate compliance
demonstration for those liquid oil-fired EGUs that
have an annual capacity factor of less than 8 percent
(emission limits do not apply, just the tune-up work
practice standard). For those EGU owners or
operators who choose to use emissions testing to
demonstrate compliance, the final rule requires
quarterly filterable PM or non-mercury metals HAP,
whether individual or total metals, testing for coal-
and liquid oil- fired units; quarterly HC] testing for
coal-fired units and quarterly HCl and HF testing,
along with site-specific parameter monitoring for
liquid oil-fired units to ensure compliance with the
HCl and HF standards.
The continuous monitoring options remain gener-
ally intact from the proposed rule, with relatively
minor clarifications concerning calculation of 30-boiler
operating day averages and QA requirements.
The final rule eliminates all operating limits for PM
except for the use of a PM CPMS. For the PM CPMS,
the final rule clarifies procedures for setting this
554a
operating limit and how it is distinct from the PM
emission limit. The PM CPMS will not be correlated
as a PM CEMS under PS 11 and will produce data in
terms of a signal you define. That signal could be
milliamps, stack concentration, or other output signal
instead of PM emissions in units of the standard. The
operating limit will be set using the highest hourly
average obtained from the PM CPMS during the
performance test. Compliance with the limit is based
on a 30-boiler operating day rolling average basis.
However, the final rule also does provide for the use of
a PM CEMS to determine compliance with the
filterable PM emission limit if the source elects to use
this approach. The EPA believes that some sources
may be interested in adopting this direct approach,
and so has included that option in the final rule. If this
approach is selected, the PM CEMS is used as the
direct method of compliance and no additional testing
is required other than tests that are required as part
of the QA requirements in PS 11 and Procedure 2. To
use this option, the source must elect to meet the
filterable PM standard, and not one of the HAP metals
standards.
Apart from the operating limit for site-specific
monitoring associated with liquid oil-fired EGUs, we
removed the other operating limits for control devices
based on a review of the comments, after considering
other programs in place to ensure proper operations of
controls at EGUs. Those other programs include
compliance assurance monitoring under part 64, part
70, and New Source Review permit conditions, and
other SIP and NSPS requirements for operating and
maintaining equipment in accordance with good air
pollution control practices. Those requirements, in
combination with the CEMS, PM CPMS, and frequent
periodic testing provisions under the final rule, will
555a
enhance the monitoring of continuous compliance with
the requirements of this rule.
Because the EPA is concerned that there will be
little or no monitoring in these underlying applicable
requirements for acid gases at liquid oil-fired EGUs,
the final rule requires a site-specific monitoring plan
for those units in this subcategory that demonstrate
compliance with the HCl and HF standards through
quarterly performance tests. With the exception for
limited-use liquid oil-fired EGUs and other monitoring
options available (such as fuel moisture monitoring or
HCVHF CEMS), the EPA believes this provision will
apply to few units. The owner or operator will submit
the site-specific plan to identify appropriate
parameters that ensure that the operations of the unit
critical to meeting the HCI/HF emission limits remain
consistent with conditions during performance
testing. This will be approved similarly to an alterna-
tive monitoring request. The plan should include the
parameters, monitoring approach, QA/QC elements,
and data reduction (including averaging period)
elements. Like the PM CPMS operating limit, the
operating limit for acid gas control devices on liquid
oil-fired EGUs will be set using the highest hourly
average obtained during the HC! and HF performance
teats. Compliance with the limit is based on a 30-boiler
operating day rolling average basis.
Finally, we have changed the continuous compliance
requirements for the performance tune-up work
practice standard since the proposal. Our intent was
that this work practice standard could be performed in
conjunction with routine maintenance operations at a
facility and be a logical extension of routine best
practices for boiler inspection and optimization. Based
on the comments received, we have reduced the
556a
required frequency for this inspection to every 3 years
and provided incentives for neural network combus-
tion management and optimization practices by
providing a longer interval of 4 years between
inspections when such systems are in use at a given
EGU.
H. Emissions Averaging
We are finalizing that owners and operators of
existing affected sources may demonstrate compliance
by emissions averaging for existing EGUs that are
located at the same facility that are within a single
subcategory and that rely on emissions testing as the
compliance demonstration method. In response to our
request for comments on the suitability of emissions
averaging and need for a discount factor, we received
a range of suggestions, including requests for
clarification regarding eligibility, points for and
against the need for a discount factor, and suggestions
to ease implementation.
As we noted at proposal, part of the EPA’s general
policy of encouraging the use of flexible compliance
approaches where they can be properly monitored and
enforced is to include emissions averaging. Emissions
averaging can provide sources the flexibility to comply
in the least costly manner while still maintaining a
regulation that is workable and _ enforceable.
Emissions averaging would not be applicable to new
affected sources and could only be used between EGUs
in the same subcategory at a particular facility. Also,
owners or operators of existing sources subject to the
EGU NSPS (40 CFR part 60, subparts D and Da)
would be required to continue to meet the PM emission
standard of that NSPS regardless of whether or not
they are using emissions averaging (i.e, an EGU
subject to 40 CFR part 60, subpart D or Da must meet
557a
its applicable NSPS filterable PM emission limit even
if it is included in a 40 CFR part 63, subpart UUUUU,
emissions averaging group for filterable PM).
Emissions averaging allows owners and operators of
a facility that includes existing EGUs within a
subcategory to demonstrate that the source complies
with the proposed emission limits by averaging the
emissions from an individual affected EGU that is
emitting above the proposed emission limits with
other affected EGUs at the same facility that are
emitting below the proposed emission limits and that
are within the same subcategory. Although some
commenters note that the MACT limits are low, based
on the data available to the Agency, we believe that
dozens of existing EGUs are achieving all of the limits
and, thus, emissions averaging is a possible approach.
The fina) rule includes an emissions averaging
compliance alternative because emissions averaging®*®
represents an equivalent, more flexible, and less costly
alternative to controlling certain emission points to
MACT levels. We have concluded that averaging in the
proposed rule could be implemented and that it would
not lessen the stringency of the MACT floor limits and
would provide flexibility in compliance, cost and
energy savings to owners and operators. We also
recognize that we must ensure that any emissions
averaging option can be implemented and enforced,
will be clear to sources, and most importantly, will be
no less stringent than unit-by-unit implementation of
the MACT floor limits.
In the final rule, the EPA is providing that sources
may average emissions from existing EGUs at the
318 As long as required emission rates are designed to account
for factors such as changes in averaging times.
558a
same facility and within the same subcategory.
Further, for Hg emissions only from existing EGUs
within the same subcategory, such EGUs in an
emissions averaging plan may use an alternate
compliance approach consisting of a 90-boiler
operating day rolling average emission limit of 1.0
Ib/TBtu or 1.1E-2 lb/GWh.
In the memo entitled “The Impact of Emission
Averaging Time on the Stringency of an Emission
Standard” in the docket, we have illustrated why a
longer-term average results in a lower limit. In
essence, longer-term averages allow particularly high
(or low) measurements to be averaged with many more
measurements closer to the mean. This results in the
highest averages from a longer-term averaging period
(e.g., 90 days) being lower than the highest averages
in a shorter term averaging period (e.g., 30 days).
We have illustrated this concept by taking Hg
CEMS data and calculating rolling 30-day averages
and rolling 90-day averages. The 30-day averages
have greater variability and, thus, higher peaks and
valleys. The 90-day average has less variability;
therefore, the same unit is able to meet a tighter 90-
day limit.
The EPA is providing this alternate 90-day rolling
average compliance approach for Hg only. A 90-day
rolling average is appropriate for Hg, and only for Hg,
because the health and environmental impacts
associated with Hg are related to environmental
loading rather than shorter term inhalation or other
acute exposure, as is the case with HC) and PM. We
believe that this alternative compliance approach will
provide at least the same level of environmental
protection while allowing companies greater flexibility
to use emissions averaging. For example, such an
959a
approach would allow for the averaging of an
infrequently operated unit that is operating slightly
above the standard with a more frequently operated
unit that is operating below the standard in the
instances when the more frequently operated unit is
in a multi-day or multi-week maintenance outage.
The EPA has concluded that it is permissible to
establish within a NESHAP a unified compliance reg-
imen that permits averaging within the same facility
across individual existing EGUs subject to the same
standards under certain conditions. As mentioned ear-
lier, individual EGUs within an emissions averaging
group would be allowed to have emissions greater
than, less than, or equivalent with the emissions limit
for their subcategory, provided that the average emis-
sions comprised from individual EGU emissions do not
exceed the emissions limit for their subcategory.
Averaging across affected units is permitted only if it
can be demonstrated that the total quantity of any
particular HAP that may be emitted by that portion of
a contiguous major source that is subject to the same
standards in the NESHAP will not be greater under
the averaging mechanism than it could be if each indi-
vidual affected EGU in the subcategory complied
separately with the applicable standard. Under this
test, the practical outcome of averaging is equivalent
to compliance with the MACT floor limits by each dis-
crete EGU, and the statutory requirement that the
MACT standard reflect the maximum achievable
emissions reductions is, therefore, fully effectuated.
As noted in the proposal preamble, in past
rulemakings, the EPA has generally imposed certain
limits on the scope and nature of emissions averaging
programs. These limits include: (1) No averaging
between different types of pollutants; (2) No averaging
560a
between sources that are not part of the same affected
source; (3) No averaging between individual sources
within a single major source if the individual sources
are not subject to the same NESHAP; and (4) No
averaging between existing sources and new sources.
The final rule fully satisfies each of these criteria.
First, emissions averaging would only be permitted
between individual existing sources at a single
stationary source (i.e., the facility), and would only be
permitted between individual sources in the same
subcategory in the final EGU NESHAP. Further,
emissions averaging would not be permitted between
two or more different affected sources. Finally, new
affected sources could not use emissions averaging.
Accordingly, we have concluded that the averaging of
emissions across affected units in the same existing
source subcategory is consistent with the CAA. In
addition, the final rule requires each facility that
intends to utilize emissions averaging to develop an
emissions averaging plan, which provides additional
assurance that the necessary criteria will be followed.
In this emissions averaging plan, the facility must
include the identification of: (1) All units in the
averaging group; (2) the control technology installed;
(3) the process parameter that will be monitored; (4)
the specific control technology or pollution prevention
measure to be used; (5) the test plan for the
measurement of the HAP being averaged; and (6) the
operating parameters to be monitored for each control
device. A state, local, or tribal regulatory agency that
is delegated authority for this rule could require the
emissions averaging plan to be submitted or even
approved before emissions averaging could be used.
Upon receipt, the regulatory authority would not be
able to approve an emissions averaging plan differing
from the eligibility criteria contained in the rule.
561la
The final rule excludes new affected sources from
the emissions averaging provision. The EPA does not
believe the statute authorizes emissions averaging for
new affected sources. One reason we allow emissions
averaging is to give existing sources flexibility to
achieve compliance at diverse points with varying
degrees of add-on control already in place in the most
cost-effective and technically reasonable fashion.
With the monitoring and compliance provisions that
are being finalized, there is additional assurance that
the environmental benefit will be realized. Further,
the emissions averaging provision would not apply to
individual EGUs if the EGU shares a common stack
with units in other subcategories, because in that
circumstance it is not possible to distinguish the
emissions from each individual unit.**®
The rule allows EGUs that rely on CEMS for
compliance demonstrations to be able to participate in
emissions averaging and the emissions limits are not
subject to a discount. The EPA believes that the data
certainty provided by units that use CEMS would be
ideal for emissions averaging and the flexibility and
cost-effectiveness it offers. Given the homogeneity of
fuels within the rules subcategories, along with other
emissions averaging criteria, the Agency believes use
of a discount factor to be unwarranted for this rule.
The emissions averaging provisions in this final rule
are based in part on the emissions averaging
provisions in the Hazardous Organic NESHAP (HON).
The legal basis and rationale for the HON emissions
6 The EPA has reviewed monitoring data submitted to the
Agency under the Title [TV Acid Rain Program. Based on that
review, the EPA is unaware of any coal- and oil-fired units that
share a common stack.
562a
averaging provisions were provided in the preamble to
the final HON.*"’ We do not believe that we have the
authority to provide for emissions averaging among
EGUs in different subcategories or among EGUs not
physically located at the same affected facility.
I. Notification, Recordkeeping, and Reporting
Compared to the proposed rule, the reduced
continuous compliance requirements in the final rule-
-primarily reduced testing frequencies and removal of
fuel analyses and control device or fuel operating
parameter monitoring-considerably reduces the
overall burden associated with recordkeeping and
reporting. Based on evaluation of the comments
received, we have established a provision in the final
rule for submission of most CEMS data (including
monitoring plan, emissions data, and QA data)
through ECMPS, so that the affected industry uses a
common reporting tool for submitting CEMS data.
For data other than most CEMS data, the final rule
requires electronic reporting of certain data, including
performance test reports, PM CPMS data, PM CEMS
data, and, if approved as part of an alternative
monitoring request, HAP metals CEMS data. Other
reports, such as notifications, must be submitted in
hard copy format or in accordance with the procedures
established by state and local agencies that receive
delegation for implementing this rule. In the proposed
rule, we took comment on these approaches and stated
our anticipation of adopting these approaches. In the
final rule, we have extended the ECMPS reporting to
most CEMS data to promote harmonization for CEMS
*\” Hazardous Organic NESHAP (59 FR 19,425; April 22, 1994).
563a
data from the industry, while leaving reporting of non-
CEMS data in a separate reporting system.
J. Technical / Editorial Corrections
In this final action, we are making a number of
technical corrections and clarifications to 40 CFR part
63, subpart UUUUU. These changes clarify proce-
dures for implementing the emission limitations for
affected sources. We are also clarifying several
definitions to help affected sources determine
applicability of this rule. We have modified some
proposed regulatory language based on public com-
ments. In addition, in response to comments received
(including the May 2010 notice from the Utility Air
Regulatory Group (UARG) of calculation errors in the
proposed Hg MACT floor limits), we have checked al]
calculations and made corrections where necessary.
In several places throughout the subpart, including
the associated tables, we have corrected the cross-
references to other sections and paragraphs of the
subpart.
Vil. Public Comments and Responses to the
Proposed NESHAP
A. MACT Floor Analysis
1. New Data/Technical Corrections to Old Data
Comment: Many commenters identified errors in the
emissions database compiled through information
provided by industry in response to the 2010
information collection request (ICR) that supported
development of this rule. Commenters submitted
corrections to the EPA during the public comment
period.
564a
Response: The EPA has incorporated technical
corrections and new data submitted prior to the end of
the comment period. The corrections and new data are
described in detail in a memorandum in the docket.
The EPA re-ranked the sources in the MACT floor
pools to the extent necessary based on the new or
corrected data, and we recalculated the MACT floors
as necessary based on the re-ranking of sources. The
revised MACT floors were established using the same
methodology set forth in the proposed rule.
2. Pollutant-by-Pollutant Approach
Comment: Many commenters raised concerns about
the way the EPA determined the MACT floors using a
pollutant-by-pollutant approach. Commenters con-
tended that such a methodology produced limits that
are not achievable in combination, and as such, the
limits do not comport with the intent of the statute or
the recent court decision (NRDC v. EPA, 2007).
Commenters further added that the CAA directs the
EPA to set standards based on the overall performance
of “sources” and CAA sections 112(d\1), (2), and (3)
specify that emissions standards be established on the
“in practice” performance of a “source” in the category
or subcategory. Commenters stated that if Congress
had intended for the EPA to establish MACT floor
levels considering the achievable emission limits of
individual HAP, it could have worded CAA section
112(d\(3) to refer to the best-performing sources “for
each pollutant.” Many commenters added that the
EPA’s discretion in setting standards is limited to
distinguishing among classes, types, and sizes of
sources. Commenters contend that although Congress
limited the EPA’s authority to parse units and sources
with similar design and types, it does not allow the
EPA to “distinguish” units and sources by individual
565a
pollutant as proposed in this rule (Sterra Club v. EPA,
551 F.3d 1019, 1028 (D.C. Cir. 2008)). By calculating
each MACT floor independently of the other
pollutants, commenters contend that the combination
of HAP limits results in a set of standards that only a
hypothetical “best performing” unit could achieve.
Response: We disagree with the commenters who
believe MACT floors cannot be set on a pollutant-by
pollutant basis. Contrary to the commenters’ sugges-
tion, CAA section 112(d)(3) does not mandate a total
facility approach. A reasonable interpretation of CAA
section 112(dX3) is that MACT floors may be
established on a HAP-by-HAP basis, so that there can
be different pools of best performers for each HAP.
Indeed, as illustrated below, the total facility approach
not only is not compelled by the statutory language but
can lead to results so arbitrary that the approach may
simply not be legally permissible.
Clean Air Act section 112(d)(3) is not explicit as to
whether the MACT floor is to be based on the perfor-
mance of an entire source or on the performance
achieved in controlling particular HAP. Congress spec-
ified in CAA section 112(d)(3) the minimum level of
emission reduction that could satisfy the requirement
to adopt MACT. For new sources, this floor level is to
be “the emission control that is achieved in practice by
the best controlled similar source.” For existing
sources, the floor level is to be “the average emission
limitation achieved by the best performing 12 percent
of the existing sources” for categories and subcatego-
ries with 30 or more sources, or “the average emission
limitation achieved by the best performing 5 sources”
for categories and subcategories with fewer than 30
sources. Commenters point to the statute’s reference
566a
to the best performing “sources,” and claim that Con-
gress would have specifically referred to the best
performing sources “for each pollutant” if it intended
for the EPA to establish MACT floors separately for
each HAP.
The EPA disagrees. The language of the Act does not
address whether floor levels can be established HAP-
by-HAP or by any other means. The reference to
“sources” does not lead to the assumption the com-
menters make that the best performing sources can
only be the best-performing sources for the entire suite
of regulated HAP Instead, the language can be
reasonably interpreted as referring to the source as a
whole or to performance as to a particular HAP.
Similarly, the reference in the new source MACT floor
provision to “emission control achieved by the best
controlled similar source” can mean emission control
as to a particular HAP or emission control achieved by
a source as a whole.
Commenters also stressed that CAA section 112(d)
requires that floors be based on actual performance
from real facilities. The EPA agrees that this language
refers to sources’ actual operation, but again the
language says nothing about whether it is referring to
performance as to individual HAP or to single facility’s
performance for all HAP. Industry commenters also
said that Congress could have mandated a HAP-by-
HAP result by using the phrase “for each HAP” at
appropriate points in CAA section 112(d). The fact that
Congress did not do so does not compel any inference
that Congress was sub-silentio mandating a different
result when it left the provision ambiguous on this
issue. The argument that MACT floors set HAP-by-
HAP are based on the performance of a hypothetical
facility, so that the limitations are not based on those
567a
achieved in practice, just reiterates the question of
whether CAA section 112(d)(3) refers to whole
facilities or individual HAP. All of the limitations in
the floors in this rule reflect sources’ actual perfor-
mance and were achieved in practice. As to
commenters’ claims that standards set in this manner
cannct be met by any actual sources, we have
determined that there are approximately 69 existing
coal-fired EGUs that meet all of the final existing
source MACT emission limits (out of 252 EGUs that
reported data for Hg, PM, and HC! in the 2010 ICR)
and at least one EGU that meets all of the final new
source MACT emission limits.
Commenters also point to the EPA’s subcategoriza-
tion authority, and claim that because Congress
authorized the EPA to distinguish among classes,
types, and sizes of units, the EPA cannot distinguish
units by individual pollutant, as they allege the EPA
did in the proposed rule. However, that statutory
language addresses the EPA’s authority to subcatego-
rize sources within a source category prior to setting
standards, which the EPA has done for certain EGUs.
The EPA is not distinguishing within each
subcategory based on HAP emitted. Rather, it is
establishing emissions standards based on the
emissions limits achieved by units in each sub-
category. Therefore, the EPA’s subcategorization
authority is irrelevant to the question of how the EPA
establishes MACT floor standards once it has made
the decision to distinguish among sources and create
subcategories.
The EPA’s long-standing interpretation of the Act is
that the existing and new source MACT floors are to
be established on a HAP-by-HAP basis. One reason for
this interpretation is that a whole plant approach
568a
could yield least common denominator floors--that is,
floors reflecting limited or no control, rather than
performance which is the average of what best
performers have achieved. See 61 FR 173687 (April 19,
1996); 62 FR 48363-64 (September 15, 1997) (same
approach adopted under the very similar language of
CAA section 129(aX2)). Such an approach would allow
the performance of sources that are outside of the best-
performing 12 percent for certain pollutants to be
included in the floor calculations for those same
pollutants, and it is even conceivable that the worst
performing source for a pollutant could be considered
a best performer overall, a result Congress could not
have intended. Inclusion of units that are outside of
the best performing 12 percent for particular
pollutants would lead to emission limits that do not
meet the requirements of the statute.
For example, if the best performing 12 percent of
facilities for HAP metals were also the worst perform-
ing units for acid gas HAP and the best performers for
acid gas HAP were the worst performers for HAP
metals, the floor for acid gases or metals would end up
not reflecting best performance. In such a situation,
the EPA would have to make a value judgment as to
which pollutant reductions were most critical to decide
which sources are best controlled.*** Such value
judgments are antithetical to the direction of the
statute at the MACT floor-setting stage.
Commenters suggested that a multi-pollutant
approach could be implemented by weighting
318 See Petitioners Brief in Me ical Waste Institute et al. v.
EPA, No. 09-1297 (D.C. Cir.) pointing out, in this context, that
“the best performers for some pollutants are the worst performers
for others” (p. 34) and “[slome of the best performers for certain
pollutants are among the worst performers for others.”
569a
pollutants according to relative toxicity and calculat-
ing weighted emissions totals to use as a basis for
identifying and ranking best performers. This
Suggested approach would require the EPA to
essentially prioritize the regulated HAP based on
relative risk to human health of each pollutant, where
risk is a criterion that has no place in the
establishment of MACT floors, which are required by
statute to be based on technology.
The central purpose of the amended air toxics
provisions was to apply strict technology-based
emission controls on HAP. See, e.g., H. Rep. No. 952,
10ist Cong. 2d sess. 338. An interpretation that the
floor level of control must be limited by the
performance of devices that only control some of these
pollutants effectively guts the standards by including
worse performers in the averaging process, whereas
the EPA’s interpretation promotes the evident
Congressional objective of having the floor reflect the
average performance of best performing sources.
Because Congress has not spoken to the precise
question at issue, and the Agency’s interpretation
effectuates statutory goals and policies in a reasonable
manner, its interpretation must be upheld. See
Chevron v. NRDC, 467 U.S. 837 (1984). n319
n319 Because industry commenters argued that the
statute can only be read to allow floors to be
determined on a single source basis, commenters
offered no view of why their reading could be viewed
as reasonable in light of the statute’s goals and
objectives. It is not evident how any statutory goal is
promoted by an interpretation that allows floors to be
determined in a manner likely to result in floors
reflecting emissions from worst or mediocre performers.
570a
The EPA notes, however, that if optimized perfor-
mance for different HAP is not technologically possible
due to mutually inconsistent control technologies (for
example, if metals performance decreased as organics
reduction is optimized), then this would have to be
taken into account by the EPA in establishing a floor
(or floors). The Senate Report indicates that if certain
types of otherwise needed controls are mutually exclu-
sive, the EPA is to optimize the part of the standard
providing the most environmental protection. S. Rep.
No. 228, 101st Cong. 1st sess. 168 (although, as noted,
the bill accompanying this Report contained no floor
provisions). It should be emphasized, however, that
the D.C. Circuit has stated that “the fact that no plant
has been shown to be able to meet all of the limitations
does not demonstrate that all the limitations are not
achievable.” Chemical Manufacturers Association v.
EPA, 885 F. 2d at 264 (upholding technology-based
standards based on best performance for each pollu-
tant by different plants, where at least one plant met
each of the limitations but no single plant met all of
them).
All available data for EGUs indicate that there is no
technical problem achieving the floor levels contained
in this final rule for each HAP simultaneously, using
the MACT floor technology. Data demonstrating a
technical conflict in meeting all of the limits have not
been provided, and, as stated above, based on the
available data, there are approximately 64 EGUs that
meet all of the final existing source emission limits
and at least one EGU that meets all of the final new
source emission limits.
3. Minimum Number of EGUs To Set Floors
Comment: Many commenters indicated that CAA
section 112 requires that data from a minimum of 5
571la
units are required to set MACT floors for existing
sources. Commenters noted that the EPA’s use of less
than 5 units for subcategories with greater than 30
units is a legalistic reading of CAA section 112 that
could result in such absurd results as using 5 units to
set MACT floors for a subcategory with 29 units and
data for only 10 units, but using a single unit to set
MACT floors for a subcategory with 31 units and data
for only 10 units.
Response: The EPA does not agree that CAA section
112(d)(3) mandates a minimum of 5 sources in all
instances, notwithstanding the incongruity of having
less data to establish floors for larger source categories
than is mandated for smaller ones. The literal
language of the provision appears to compel this
result. CAA section 112(d\3) states that for categories
and subcategories with at least 30 sources, the MACT
floor for existing sources shall be no less stringent
than the average emission limitation achieved by the
best-performing 12 percent of the sources for which
the Administrator has emissions information. The
plain language of this provision requires the use of
fewer data points for large source categories than for
small source categories where the Administrator only
has emissions information on a small number of units
for categories and subcategories with 30 or more
sources. Furthermore, commenters contend that
Congress could not have intended the floors for a
subcategory with 29 sources to be based on 5 sources
and a subcategory with 31 sources to be based on less
than that number; but we maintain this contention is
without merit because 12 percent of 31 is 3.72
(rounded to 4) so the EPA would not base standards
for a subcategory with 31 sources on 5 sources even if
‘we had data on all 31 sources in the subcategory. For
these reasons, we decline to adopt commenters’
572a
position and continue to adhere to the clear statutory
directive.
4. Treatment of Detection Levels
Comment: Commenters stated that when setting the
MACT floors, non-detect values are present in many of
the datasets from best performing units. Commenters
provided input on how these non-detect values should
be treated in the MACT floor analysis. Some
commenters agreed that it is appropriate to keep the
detection levels as reported, while certain commenters
suggested that the detection levels should be replaced
using a value of half the method detection limit (MDL).
Many other commenters stated that data that are
below the detection limit should not be used in setting
the floors, and these data should be replaced with a
higher value -including either the MDL, limit of
quantitation (LOQ), practical quantitation limit
(PQL), or reporting limit (RL) for the purposes of the
MACT floor calculations. Other commenters stated all
non-detect values should be excluded from the floor
analysis, or all values should be treated as zero.
Some commenters stated it is necessary to keep the
data as reported because changing values would lead
to an upward bias. Additional commenters agreed
with this basic premise, but suggested that replacing
non-detect data with a value of half the MDL is
appropriate while still minimizing the bias. They
noted that treating measurements below the MDL as
occurring at the MDL is statistically incorrect and
violates the statute’s “shall not be less stringent than”
requirement for MACT floors. One commenter also
provided a reference for a statistical method based on
a log-normal distribution of the data which estimated
the “maximum likelihood” of data values; this result is
slightly higher than half the MDL.
573a
Some commenters stated that it is necessary to
substitute the MDL value when performing the MACT
floor calculations. With MDL defined as the lowest
concentration that can be distinguished from the
blank at a defined level of statistical significance, this
is an appropriate value. If MDL values are not
reported, one commenter suggested an approach for
estimating an MDL equivalent value, but recognized
that the background laboratory and test report files
may not be available to the EPA in order to derive
these estimates.
Most commenters representing industry and
industry trade groups argued that either LOQ or PQL
values should replace non-detects. The LOQ is defined
as the smallest concentration of the analyte which can
be measured. These commenters contended that the
LOQ leads to a quantifiable amount of the substance
with an acceptable level of uncertainty. A few
commenters provided calculations showing some of
the proposed MACT floors were below the LOQ.
Additionally, some of these commenters stated that
using LOQ or PQL values also incorporates additional
sources of random and inherent sampling error
throughout the testing process, which is necessary.
These errors occur during sample collection, sample
recovery, and sample analysis; MDL values only
account for method specific (e.g., instrument) errors.
These commenters contended that the three times the
MDL approach discussed in the proposal accounts for
some measurement errors but does not account for
these unavoidable sampling errors. The commenters
also noted that an LOQ is calculated as 3.18 times the
MDL, and PQL is calculated as 5 to 10 times the MDL.
Many of the commenters in support of using either an
LOQ or PQL value ultimately believed a work practice
is more appropriate where a MACT floor limit is below
574a
either of these two values. They cited CAA section
112(hX1) which allows work practices under CAA
section 112(h)(2) if “the application of measurement
methodology to a particular class of sources is not
practicable due to technological and economic limita-
tions”. These commenters stated that the inability of
sources to accurately measure a pollutant at the level
of the MACT floor qualifies as such a technological
limitation that warrants a work practice standard.
Commenters stated that where the proposed MACT
floor is below the LOQ or PQL then that source
category has a technological measurement limitation.
A few commenters suggested RL values should be used
when developing the floor limits. They stated that the
RL is the lowest level at which the entire analytical
system gives reliable signals and includes an
acceptable calibration point. They added that use of an
acceptable calibration point is critical in showing that
numbers are real versus multiplying the MDL by
various factors.
Several commenters stated that all non-detect val-
ues should be excluded from MACT floor calculations.
They believed that excluding all non-detect values
would eliminate any potential errors or accuracy
issues related to testing for compliance. Due to incon-
sistencies of the MDL value reported for non-detect
data, one comwenter suggested treating all such val-
ues as zero. This would provide a consistent approach
for setting the floor as well! as determining compliance.
Several commenters provided input on the EPA’s
proposed method of three times the MDL as an option
for setting limits. A few commenters in support noted
that this approach provided a reasonable method to
account for data variability as it took into account
more than just analytical instrument precision. Many
575a
other commenters argued that this method results in
limits which are too low, namely that it is still lower
than the LOQ value which they are in favor of as a
su
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