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Revisions to the Continuous Emissions Monitoring Rule for the Acid Rain Program, NOX Budget Trading Program, the Clean Air Interstate Rule, and the Clean Air Mercury Rule
Note: EPA no longer updates this information, but it may be useful as a reference or resource.
[Federal Register: August 22, 2006 (Volume 71, Number 162)]
[Proposed Rules]
[Page 49253-49308]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr22au06-26]
[[Page 49254]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 72 and 75
[OAR-2005-0132; FRL-8208-1]
Revisions to the Continuous Emissions Monitoring Rule for the
Acid Rain Program, NOX Budget Trading Program, the Clean Air
Interstate Rule, and the Clean Air Mercury Rule
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
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SUMMARY: EPA is proposing rule revisions that would modify existing
requirements for sources affected by the federally administered
emission trading programs including the NOX Budget Trading
Program, the Acid Rain Program, the Clean Air Interstate Rule, and the
Clean Air Mercury Rule.
The proposed revisions are prompted primarily by changes being
implemented by EPA's Clean Air Markets Division in its data systems in
order to utilize the latest modern technology for the submittal of data
by affected sources. Other revisions address issues that have been
raised during program implementation, fix specific inconsistencies in
rule provisions, or update sources incorporated by reference. These
revisions would not impose significant new requirements upon sources
with regard to monitoring or quality assurance activities.
DATES: All public comments must be received on or before October 23, 2006.
ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2005-0132, by one of the following methods:
? Federal eRulemaking Portal: http://www.regulations.gov.
Follow the on-line instructions for submitting comments.
? E-mail: a-and-r-docket@epa.gov.
? Fax: (202) 566-1741.
? Hand Delivery: Air and Radiation Docket, Environmental
Protection Agency, 1301 Constitution Avenue, NW., Room B-108,
Washington, DC 20014. Such deliveries are accepted only during the
Docket's normal hours of operation and special arrangements should be
made for deliveries of boxed information.
? Mail: EPA Docket Center (EPA/DC), Environmental Protection
Agency, Mailcode 6102T, 1200 Pennsylvania Avenue, NW., Washington, DC
20460. Please include a total of two copies. We request that a separate
copy also be sent to the contact person identified below (see FOR
FURTHER INFORMATION CONTACT).
Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-
2005-0132. EPA's policy is that all comments received will be included
in the public docket without change and may be made available online at
http://www.regulations.gov including any personal information provided,
unless the comment includes information claimed to be Confidential
Business Information (CBI) or other information whose disclosure is
restricted by statute. Do not submit information that you consider to
be CBI or otherwise protected through http://www.regulations.gov or e-mail.
The http://www.regulations.gov Web site is an ``anonymous
access'' system, which means EPA will not know your identity or contact
information unless you provide it in the body of your comment. If you
send an e-mail comment directly to EPA without going through http://
www.regulations.gov, your e-mail address will be automatically captured
and included as part of the comment that is placed in the public docket
and made available on the Internet. If you submit an electronic
comment, EPA recommends that you include your name and other contact
information in the body of your comment with a disk or CD-ROM you
submit. If EPA cannot read your comment due to technical difficulties
and cannot contact you for clarification, EPA may not be able to
consider your comment. Electronic files should avoid the use of special
characters, any form of encryption, and be free of any defects or
viruses. Docket: All documents in the docket are listed in the
http://www.regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, will be publicly available only in hard copy.
Publicly available docket materials are available either electronically
in http://www.regulations.gov or in hard copy at the Air and Radiation
Docket, EPA/DC, EPA West, Room B102, 1301 Constitution Ave., NW.,
Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30
p.m., Monday through Friday, excluding legal holidays. The telephone
number for the Public Reading Room is (202) 566-1744, and the telephone
number for the Air and Radiation Docket is (202) 566-1742.
FOR FURTHER INFORMATION CONTACT: Matthew Boze, Clean Air Markets
Division, U.S. Environmental Protection Agency, Clean Air Markets
Division, MC 6204J, Ariel Rios Building, 1200 Pennsylvania Ave., NW.,
Washington, DC 20460, telephone (202) 343-9211, e-mail at
boze.matthew@epa.gov. Electronic copies of this document can be
accessed through the EPA Web site at: http://www.epa.gov/airmarkets.
SUPPLEMENTARY INFORMATION: Regulated Entities. Entities regulated by
this action primarily are fossil fuel-fired boilers, turbines, and
combined cycle units that serve generators that produce electricity,
generate steam, or cogenerate electricity and steam. Some trading
programs include process sources, such as process heaters or cement
kilns. Although Part 75 primarily regulates the electric utility
industry, certain State and Federal NOX mass emission
trading programs rely on subpart H of Part 75, and those programs may
include boilers, turbines, combined cycle, and certain process units
from other industries. Regulated categories and entities include:
------------------------------------------------------------------------
Examples of
Category NAICS code potentially regulated
industries
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Industry...................... 221112 and others Electric service
providers Process
sources with large
boilers, turbines,
combined cycle
units, process
heaters, or cement
kilns where
emissions exhaust
through a stack.
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This table is not intended to be exhaustive, but rather to provide
a guide for readers regarding entities likely to be regulated by this
action. This table lists the types of entities which EPA is now aware
could potentially be regulated by this action. Other types of entities
not listed in this table could also be regulated. To determine whether
your facility, company, business, organization, etc., is regulated by
this action, you should carefully examine the applicability provisions
in Sec. Sec. 72.6, 72.7, and 72.8 of title 40 of the Code of Federal
Regulations and in 40 CFR Parts 96 and 97. If you have questions
regarding the applicability of this action to a particular entity,
consult the person listed in the preceding FOR FURTHER INFORMATION
CONTACT section.
[[Page 49255]]
Submitting CBI. Do not submit this information to EPA through
http://www.regulations.gov or e-mail. Clearly mark the part or all of
the information that you claim to be CBI. For CBI information on a disk
or CD-ROM that you mail to EPA, mark the outside of the disk or CD-ROM
as CBI and then identify electronically within the disk or CD-ROM the
specific information that is claimed as CBI. In addition to one
complete version of the comment that includes information claimed as
CBI, a copy of the comment that does not contain the information
claimed as CBI must be submitted for inclusion in the public docket.
Information so marked will not be disclosed except in accordance with
procedures set forth in 40 CFR part 2.
World Wide Web (WWW). In addition to being available in the docket,
an electronic copy of the proposed rule is also available on the WWW
through the Technology Transfer Network Web site (TTN Web). Following
signature, a copy of the proposed rule will be posted on the TTN's
policy and guidance page for newly proposed or promulgated rules at
http://www.epa.gov/ttn/oarpg. The TTN provides information and
technology exchange in various areas of air pollution control.
Outline:
I. Detailed Discussion of Proposed Rule Revisions
A. Rule Definitions
B. General Monitoring Provisions
C. Certification Requirements
D. Missing Data Substitution
E. Recordkeeping and Reporting
F. Subpart H (NOX Mass Emissions)
G. Subpart I (Hg Mass Emissions)
H. Appendix A
I. Appendix B
J. Appendix D
K. Appendix E
L. Appendix F
M. Appendix G
N. Appendix K
II. Administrative Requirements
A. Executive Order 12866--Regulatory Planning and Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act
E. Executive Order 13132--Federalism
F. Executive Order 13175--Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045--Protection of Children From
Environmental Health and Safety Risks
H. Executive Order 13211--Actions That Significantly Affect
Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
I. Detailed Discussion of Proposed Rule Revisions
EPA is in the process of re-engineering the data systems associated
with the collection and processing of emissions, monitoring plan,
quality assurance, and certification data. The re-engineering project
includes the creation of a client tool, provided by EPA that sources
will use to evaluate and submit their Part 75 monitoring data. This
process change will enable sources to assess the quality of their data
prior to submitting the data using EPA established checking criteria.
The process will also allow sources to report their data directly to a
database. Having the data in a true database will allow the Agency to
implement and assess the program more efficiently and will streamline
access to the data. Also, this database structure will enable EPA to
implement process changes that will reduce the redundant reporting of
certain types of data. The re-engineered systems will be supported by a
new extensible markup language (XML) data format that will replace the
record type/column format currently used by EPA to collect electronic
data. EPA intends to transition existing sources to the new XML
electronic data report (XML-EDR) format during the 2008 reporting year.
For sources reporting in 2008 for the first time, the new XML-EDR
format should be used. All sources will be required to use the new
process beginning 2009.
A. Rule Definitions
The proposed changes to Part 72 include adding a definition for
``long-term cold storage'' to mean ``the complete shutdown of a unit
intended to last for an extended period of time (at least two calendar
years) where notice for long-term cold storage is provided under Sec.
75.61(a)(7). See Section II.E.4 of this preamble for further discussion.
EPA also proposes to modify the definition of ``capacity factor''
so that the Agency can use the reported maximum hourly gross load, as
currently reported in the electronic monitoring plan, to determine
whether a unit qualifies for peaking unit status, by recalculating the
capacity factor. This is important because the maximum hourly gross
load can be greater than the nameplate capacity. Also, when using heat
input to define capacity factor, the definition would be revised to
refer to maximum rated hourly heat input rate, which is defined in
Sec. 72.2.
The proposed changes to Sec. 72.2 would also modify the definition
of ``EPA Protocol Gas,'' and add a definition of ``EPA Protocol Gas
Verification Program'', to support the proposed calibration gas audit
program. EPA is also proposing to expand the definition of ``excepted
monitoring system'' to include the sorbent trap and low mass emissions
(LME) excepted methodologies for Hg. Finally, today's proposed rule
would add definitions of ``Air Emission Testing Body (AETB)'' and
``Qualified Individual'', to support the proposed stack tester
accreditation program. See Sections II.H.2 and II.H.3 of this preamble
for a discussion of these proposed programs.
B. General Monitoring Provisions
1. Update of Incorporation by Reference (Sec. 75.6)
Section 75.6 identifies a number of methods and other standards
that are incorporated by reference into Part 75. This section includes
standards published by the American Society for Testing and Materials
(ASTM), the American Society of Mechanical Engineers (ASME), the
American National Standards Institute (ANSI), the Gas Processors
Association (GPA), and the American Petroleum Institute (API). Changes
in Sec. 75.6 would reflect the need to incorporate recent updates for
many of the referenced standards. The proposed revisions would
recognize or adhere to these newer standards by updating references for
the standards listed in Sec. Sec. 75.6(a) through 75.6(f).
Additionally, new Sec. Sec. 75.6(a)(45) through 75.6(a)(48) and
75.6(f)(4) would incorporate by reference additional ASTM and API
standards that are relevant to Part 75 implementation.
2. Default Emission Rates for Low Mass Emissions (LME) Units
Today's proposed rule revisions would allow LME units to use site-
specific default SO2 emission rates for fuel oil combustion,
in lieu of using the ``generic'' default SO2 emission rates
specified in Table LM-1 of Sec. 75.19. To use this option, a federally
enforceable permit condition would have to be in place for the unit,
limiting the sulfur content of the oil. This revision would allow more
representative, yet still conservatively high, SO2 emissions
data to be reported from oil-burning LME units. The site-specific
default SO2 emission rate would be calculated using an
equation from EPA publication AP-42. The sulfur content used in the
calculations would be the maximum weight percent sulfur allowed by the
federally-enforceable permit. Sources choosing to implement this option
would be required to perform periodic oil sampling using one of the
four methodologies described in Section 2.2
[[Page 49256]]
of Appendix D to Part 75, and would be required to keep records
documenting the sulfur content of the fuel.
Today's proposed rule would also revise Sec. 75.19(c)(1)(iv)(G) to
clarify that fuel-and-unit-specific default NOX emission
rates for LME units may be determined using data from a Continuous
Emissions Monitoring System (CEMS) that has been quality-assured
according to either Appendix B of Part 75 or Appendix F of Part 60, or
comparably quality-assured under a State CEMS program. The current rule
simply states that 3 years (or 3 ozone seasons, if applicable) of
quality-assured CEMS data may be used for this purpose, but it does not
specify the acceptable level of QA required.
3. Default Moisture Value for Natural Gas
EPA is proposing to allow gas-fired boilers equipped with CEMS to
use default moisture values in lieu of continuously monitoring the
stack gas moisture content. Two default values are proposed: 14.0%
H2O under Sec. 75.11(b), and 18.0% H2O under
Sec. 75.12(b). The higher default value would apply only when Equation
19-3, 19-4, or 19-8 (from Method 19 in appendix A of Part 60) is used
to determine the NOX emission rate. These proposed default
values are based on supplemental moisture data provided to the Agency
in a December 13, 2004 petition from a gas-fired industrial source and
moisture data collected during EPA's development of flow rate reference
Methods 2F and 2G at two gas-fired facilities. (See Docket A-99-14;
Items II-A-1 and II-A-7).
EPA selected the 10th and 90th percentile values from these data,
rounded to the nearest whole number, as the proposed natural gas
default moisture values. The selection of conservative 90th or 10th
percentile values from representative moisture data sets is consistent
with the approach that the Agency has approved in response to past
petition under Sec. 75.66 requesting to use site-specific default
moisture values.
4. Expanded Use of Equation F-23
Today's proposed rule would revise Sec. 75.11(e)(1) to remove the
current restrictions on the use of Equation F-23 to determine the
SO2 mass emission rate. The current rule restricts the use
of this equation to units equipped with SO2 monitors and to
hours when only fuel that meets the Part 72 definition of ``pipeline
natural gas'' or ``natural gas'' is being combusted. EPA proposes to
allow Equation F-23 to be used whether or not the unit has an SO2
monitor and to expand its use to fuels other than natural gas.
Section 75.11(e) would be re-titled as ``Special considerations
during the combustion of gaseous fuels'', and the introductory text of
the section would be revised, so that the section would no longer apply
exclusively to units with SO2 monitors. Rather, it would
apply to units that use certified flow rate and diluent gas monitors to
quantify heat input. Such units would be required to implement the
provisions of either revised Sec. 75.11(e)(1) or revised Sec.
75.11(e)(3) when gaseous fuel is the only fuel combusted in the unit.
Section 75.11(e)(2) would be removed and reserved, as the use of
Appendix D methodology during gaseous fuel combustion is not
appropriate for a unit that uses flow and diluent monitors to measure
heat input. This is because only one heat input methodology is allowed
for each unit.
Revised Sec. 75.11(e)(1) would expand the use of Equation F-23
beyond natural gas combustion to include the combustion of any gaseous
fuel that qualifies for a default SO2 emission rate under
Section 2.3.6(b) of Appendix D. The proposed revisions to Sec.
75.11(e)(3) would be relatively minor. The option to use a certified
SO2 monitor during hours of gaseous fuel combustion would be retained.
A new paragraph (e)(4) would also be added to Sec. 75.11(e). This
new provision would allow Equation F-23 to be used for the combustion
of liquid and solid fuels that meet the definition of ``very low sulfur
fuel'' in Sec. 72.2, if a petition for a fuel-specific default
SO2 emission rate is submitted to the Administrator under
Sec. 75.66 and the Administrator approves the petition. Similar
petitions would also be accepted for the combustion of mixtures of
these fuels and for the co-firing of these fuels with gaseous fuel.
EPA believes that expanding the use of Equation F-23 will benefit
certain units that are subject to the Acid Rain Program or to the
SO2 provisions of the Clean Air Interstate Rule (CAIR). In
particular, the requirement to operate and maintain an SO2
CEMS could be waived for units that burn low-sulfur solid fuels such as
wood waste. Also, for units that combust non-traditional gaseous fuels,
Equation F-23 would provide an alternative way of quantifying
SO2 mass emissions that does not require either an
SO2 CEMS or a certified fuel flowmeter.
5. Calculation of NOX Emission Rate--LME Units
According to Sec. Sec. 75.58(f), 75.64(a)(4), and 75.64(a)(9), oil
and gas-fired units in the Acid Rain Program that qualify to use the
low mass emissions (LME) methodology in Sec. 75.19 are required to
report both NOX mass emissions (lb or tons, as applicable)
and NOX emission rate (lb/mmBtu) on an hourly, quarterly and
annual basis. However, the mathematics in Sec. 75.19(c)(4)(ii)
pertains only to NOX mass emissions, not NOX
emission rate. This is most likely because the criterion for initial
and on-going LME qualification is based on the total tons of
NOX emitted the calendar year, rather than on the
NOX emission rate.
Today's rule would re-title Sec. 75.19(c)(4)(ii) as
``NOX mass emissions and NOX emission rate'', and
would add a new subparagraph (D) to Sec. 75.19 (c)(4)(ii), providing
instructions for determining quarterly and cumulative NOX
emission rates for an LME unit. The NOX emission rate for
each hour (lb/mmBtu) would simply be the appropriate generic or unit-
specific default NOX emission rate defined in the monitoring
plan for the type of fuel being combusted and (if applicable) the
NOX emission control status. The quarterly NOX
emission rate would be determined by averaging all of the hourly
NOX emission rates and the cumulative (year-to-date)
NOX emission rate would be the arithmetic average of the
quarterly values.
6. LME Units--Scope of Applicability
Today's rule would revise Sec. 75.19(a)(1) to clarify that the low
mass emissions (LME) methodology is a stand-alone alternative to a CEMS
and/or the ``excepted'' monitoring methodologies in Appendices D, E,
and G. In other words, if a unit qualifies for LME status, the owner or
operator would be required either to use the LME methodology for all
parameters or not to use the method at all. No mixing-and-matching of
other monitoring methodologies with LME would be permitted. For
example, the owner or operator of a qualifying LME unit in the Acid
Rain Program would either be required to follow the provisions of Sec.
75.19 for all parameters (i.e., SO2 and CO2 mass
emissions, NOX emission rate, and unit heat input) or to
monitor these parameters using a CEMS, Appendices D, E, and G, or a
combination of these other methods. EPA has always intended for the LME
methodology to be applied this way, but this was not explicitly stated
in Sec. 75.19 and in other sections of the rule. In fact, Sec. Sec.
75.11(d)(3), 75.12(e)(3), and 75.13(d)(3)) suggest that mixing other
monitoring methodologies with LME might not be prohibited. Today's rule
would also make parallel revisions to
[[Page 49257]]
these other sections, consistent with the changes to Sec. 75.19(a)(1),
to clarify the Agency's intent.
7. Use of maximum controlled NOX emission rate when using
bypass stacks
Today's proposed rule would revise Sec. 75.17(d)(2) to allow for
the calculation and use of a maximum controlled NOX emission
rate (MCR) instead of the maximum potential NOX emission
rate (MER) whenever an unmonitored bypass stack is used, provided that
the add-on controls are not bypassed and are documented to be operating
properly. Documentation of proper add-on control operation for such
hours of operation would be required as described in Sec. 75.34(d).
The MCR would be calculated in a manner similar to the calculation of
the MER, except that the maximum expected NOX concentration
(MEC) would be used instead of the maximum potential NOX
concentration (MPC). EPA believes that this proposal would more fairly
account for controlled emissions when unmonitored bypass stacks are
used. The rule currently requires the use of the MER regardless of the
operation and usage of add-on controls. When Sec. 75.17(d)(2) was
originally promulgated, EPA assumed that the add-on controls would be
bypassed whenever a bypass stack is used. EPA is now aware that there
are situations where this is not the case. An example would be a coal-
fired unit equipped with FGD and SCR add-on emission controls. If the
SCR is documented to be working during an FGD malfunction and the
effluent gases are routed through an unmonitored bypass stack after
passing through the SCR, then the MEC, rather than the MER, would be
the more appropriate NOX emission rate to report for the
bypass hour(s).
C. Certification Requirements
1. Alternative Monitoring System Certification
The proposed rule would delete Sec. Sec. 75.20(f)(1) and (2) from
the rule, thereby removing the requirement for the Administrator to
publish each request for certification of an alternative monitoring
system in the Federal Register, with an associated 60-day public
comment period. This rule provision is considered unnecessary, in view
of the Agency's authority under Subpart E to approve alternative
monitoring systems and the rigorous requirements that alternative
monitoring systems must meet in order to be certified.
2. Part 60 Reference Test Methods
On May 15, 2006, EPA promulgated final revisions to EPA reference
test methods 6C, 7E, and 3A, which are found in Appendix A of 40 CFR
Part 60. (See 71 FR 28082, May 15, 2006). Today's proposed rule would
update, (as necessary), various section references to these reference
methods, as well as specify certain options that are not to be applied
to RATA testing under Part 75. Specifically, the following provisions
are not permitted unless specific approval is granted by the
Administrator of Part 75:
(1) Sec. 7.1 of the revised EPA Method 7E allowing for use of
prepared calibration gas mixtures that are produced in accordance with
Method 205 in Appendix M of 40 CFR Part 51. EPA maintains that for RATA
testing under Part 75, that reference gases be selected in accordance
with Sec. 5.1 of Appendix A of 40 CFR Part 75.
(2) Sec. 8.4 of the revised EPA Method 7E allowing for the use of
a multi-hole probe to satisfy the multipoint traverse requirement of
the method.
(3) Sec. 8.6 of the revised EPA Method 7E allowing for the use of
``Dynamic Spiking'' as an alternative to the interference and system
bias checks of the method. This proposed rule would allow for dynamic
spiking to be conducted (optionally) as an additional quality assurance
check for Part 75 applications.
3. Mercury Reference Methods
Today's proposed rule would add an alternative acceptance criterion
for the results of mercury (Hg) emission data collected with the
Ontario Hydro (OH) reference method and would allow the use of
alternative reference methods for RATAs and for the low mass Hg
emission testing described in Sec. 75.81(c).
On May 18, 2005, EPA published the Clean Air Mercury Rule (CAMR).
That rule requires coal-fired electric generating units (EGUs) to
reduce Hg emissions, starting in 2010, and to continuously monitor Hg
mass emissions according to Subpart I of Part 75, beginning in 2009.
Relative accuracy test audits (RATAs) of all continuous Hg
monitoring systems are required under CAMR, and Hg emission testing is
required for units seeking to qualify as low mass emitters under Sec.
75.81(c). The principal reference method specified for the RATAs and
the emission testing is the OH method. Alternatively, an instrumental
method approved by the Administrator may be used. When the OH method is
performed, Sec. 75.22(a)(7) requires paired sampling trains for each
test run, and the relative deviation (RD) of the results from the two
trains must not exceed 10 percent.
As part of the May 18, 2005 rulemaking, EPA also promulgated
revisions to Subpart Da of the New Source Performance Standards (NSPS)
regulations, requiring continuous Hg emission monitoring for new coal-
fired electric utility units constructed after January 1, 2004. Along
with the Subpart Da revisions, a performance specification, PS-12A, for
certifying the required continuous Hg monitors was published. PS-12A,
like Part 75, requires RATA testing of all Hg monitoring systems, using
paired reference method sampling trains; however, note that PS 12-A
allows EPA Method 29 (from Appendix A-8 of 40 CFR Part 60) to be used
as an alternative to the OH method, whereas Part 75 does not.
The principal acceptance criterion in Section 8.6.6.2 of PS 12-A
for the data from the paired reference method trains (10 percent RD) is
the same as in Sec. 75.22(a)(7). However, PS 12-A includes an
alternative acceptance criterion for sources with low Hg emissions. If
the average Hg concentration during the RATA is 1.0 [mu]g/m\3\ or less,
the RD specification is 20 percent. In view of this, today's proposed
rule would revise Sec. 75.22(a)(7), to include this same 20 percent
alternative RD specification for low-emitters. This would harmonize the
Part 60 and Part 75 RATA provisions for Hg monitors, thereby
facilitating compliance for sources subject to both sets of regulations.
EPA is also proposing revisions to Sec. Sec. 75.22(a)(7) and
75.81(c)(1) which would allow EPA Method 29 to be used as an
alternative to the OH method, both for RATA testing and for periodic
emission testing of units with low Hg mass emissions (< = 29 lb/yr).
Method 29 is an established test procedure that uses atomic absorption
spectroscopy to determine the concentration of various metals,
including Hg, in the stack gas. This method is more familiar to
emission testers than the OH method, and Method 29 data have been
accepted for compliance purposes by the State. Method 29 and the OH
method both measure the total vapor phase Hg in the effluent. The main
difference between the two methods is that the OH method performs
``speciation'' of the vapor phase Hg, i.e., it quantifies the elemental
and ionic portions of the vapor phase Hg separately, whereas Method 29
does not. However, the CAMR rule does not require speciation of the vapor
phase Hg. Therefore, Method 29 could be used instead of the OH method.
[[Page 49258]]
There would be two caveats on the use of Method 29. First, sources
electing to use Method 29 would be required to use paired sampling
trains (i.e., two trains sampling the source effluent simultaneously),
and the relative deviation specification in Sec. 75.22(a)(7) would
have to be met for each run. The test results for each valid run would
be based on the Hg collected in the back half of each sampling train
(i.e., the impinger catch), and the results from the two trains would
be averaged arithmetically.
Second, certain analytical and QA procedures in the OH method (ASTM
D6784-02) would be followed instead of the corresponding procedures in
Method 29. Specifically, testers would be required to replace the
procedures in sections 7.5.33 and 11.1.3 of Method 29 with the
corresponding procedures in sections 13.4.1.1 through 13.4.1.3 of ASTM
D6784-02, and to perform the QA/QC procedures in section 13.4.2 of the
OH method instead of the procedures in section 9.2.3 of Method 29. EPA
believes that implementing these sections of the OH method in lieu of
the corresponding Method 29 provisions will improve the quality of the
data, because the analytical and QA/QC requirements of the OH method
are more detailed and rigorous than those in Method 29.
EPA is also proposing to allow several of the sample recovery and
preparation procedures in the OH method to be followed instead of the
Method 29 procedures. In particular: (a) Sections 13.2.9.1 through
13.2.9.3 of the OH method could be followed instead of sections 8.2.8
and 8.2.9.1 of RM 29; (b) sections 13.2.10.1 through 13.2.10.4 of the
OH method could be followed instead of sections 8.2.9.2 and 8.2.9.3 of
RM 29; (c) section 8.3.4 of RM 29 could be replaced with section 13.3.4
or 13.3.6 of the OH method (as appropriate); and (d) section 8.3.5 of
RM 29 could be replaced with section 13.3.5 or 13.3.6 of the OH method
(as appropriate). Use of these alternative procedures would increase
the accuracy of moisture content determinations (by using a gravimetric
rather than a volumetric technique), and would eliminate of the need
for two separate analyses of the KMnO4 fraction.
Revisions to Sec. 75.59 and to Sections 6.5.10 and 7.6.1 of
Appendix A to Part 75 are also being proposed, for purposes of consistency
with the proposed changes to Sec. Sec. 75.22(a)(7) and 75.81(c)(1).
Finally, the Agency is soliciting comment on the use of sorbent
traps for reference method testing. At the 2006 Electric Utility
Environmental Conference (EUEC) in Tucson, Arizona, a stakeholder
meeting was held to discuss mercury monitoring issues. Many of the
participants expressed an interest in using portable sorbent trap
monitoring systems for Hg reference method testing, as an alternative
to the OH method. After much internal discussion, EPA believes that a
sorbent trap system could potentially serve as an alternative reference
method for Hg emission testing and RATA applications, if it can be
adequately demonstrated that the method does not have an inherent
measurement bias when compared to the OH method, and if sufficiently
rigorous quality-assurance (QA) procedures are developed and followed
when the system is used in the field. In view of this, EPA requests
comment on how such a demonstration might be made and what QA
procedures would be appropriate. In anticipation that a viable
reference method using sorbent trap technology may be developed in the
near future, the Agency is also proposing to add language to Sec.
75.22(a)(7), which would allow an ``other suitable'' reference method
approved by the Administrator to be used for Hg emission testing and RATAs.
D. Missing Data Substitution
1. Block Versus Step-Wise Approach
During periods of missing CEMS data, Part 75 requires substitute
data to be reported. Special mathematical algorithms are used to
determine the appropriate substitute data values. As the length of a
missing data period increases, the percent monitor data availability
(PMA) decreases, and the required substitute data values become
increasingly conservative each time that a particular PMA ``cut point''
is reached. The cut points are 95%, 90%, and 80% PMA for all parameters
except Hg. For Hg, the cut points are slightly lower, i.e., at 90%, 80%
and 70% PMA.
Historically, EPA's policy has required sources to use a ``block''
approach for missing data substitution. The PMA at the end of the
missing data period has been used to determine which mathematical
algorithm applies, and the substitute data value or values prescribed
by that one algorithm have been reported for each hour of the missing
data period.
However, EPA has recently revised its missing substitution data
policy. The revised policy guidance (see ``Part 75 Emission Monitoring
Policy Manual'', Question 15.5) allows sources to apply the missing
data algorithms in a stepwise manner instead of using the block
approach. Under the stepwise methodology, the various missing data
algorithms are applied sequentially. That is, the least conservative
algorithm is applied to the missing data hours until the PMA drops
below 95%. Then, the next algorithm is applied until the PMA has
dropped below 90%, and so on.
Part 75 is not clear about which of the two methods should be used
for missing data substitution. Today's proposed rule would revise the
text of certain paragraphs in Sec. Sec. 75.33 and 75.32(b), to clarify
that the stepwise, hour-by-hour method (which is the least stringent
approach) is the preferred one. The Agency favors this approach because
it prevents sources from being penalized by the retroactive application
of more stringent missing data algorithms to hours where the hourly PMA
merits the use of less conservative algorithms. EPA intends that only
the new stepwise, hour-by-hour method be used after January 1, 2009, or
whenever emissions data are to be submitted in XML-format. Until this
time, either method will be accepted.
2. Substitute Data Values for Controlled Units
For units with add-on emission controls, Sec. 75.34(a)(3) provides
that the designated representative (DR) may petition the Administrator
under Sec. 75.66 to report alternative substitute data values in
certain instances. Specifically, when the percent monitor data
availability (PMA) for SO2 or NOX is below 90.0
percent, the DR may petition to replace the maximum emission rate
recorded in the last 720 quality-assured monitor operating hours with
the maximum controlled emission rate recorded during that same lookback
period, for each missing data hour in which the add-on controls are
documented to be operating properly. Until recently, this petition
provision applied only to units with add-on SO2 or
NOX emission controls. However, revisions to Part 75 on May
18, 2005, extended it to include units with add-on Hg controls (see
Sec. 75.38(c)).
For several reasons, EPA believes it is appropriate to revise Sec.
75.34(a)(3). First, the 720 hour lookback is only appropriate for
SO2 and Hg. For NOX, the lookback should be 2,160
hours and should also be load-based. Second, for SO2, Hg,
and NOX concentration monitoring systems, the terms
``maximum emission rate'' and ``maximum controlled emission rate'' are
not appropriate and should be replaced by ``maximum concentration'' and
``maximum controlled concentration'', respectively. Third, the petition
provision, as written, applies to
[[Page 49259]]
all PMA values below 90.0 percent (that was the intent when it was
originally written), but in light of subsequent revisions to Part 75,
it should be restricted to a narrower range of PMA values. Fourth, and
most important, after more than ten years of implementing the Acid Rain
Program, EPA no longer believes that special petitions are necessary to
use maximum controlled values for missing data substitution, because
sources with add-on controls are required to implement a quality
assurance/quality control (QA/QC) program that includes the recording
of parametric data to document the hourly operating status of the
emission controls. This parametric information must be made available
to inspectors and auditors upon request. Therefore, any claim that the
emission controls were operating properly during a particular missing
data period can be easily verified through the audit process.
At the time the petition provision in Sec. 75.34(a)(3) was
written, there were only three missing data tiers in existence, i.e.,
for PMA values: (1) >= 95.0 percent; (2) >= 90.0 percent, but < 95.0
percent: and (3) < 90.0 percent. The provision was associated with the
third tier (PMA < 90.0 percent), for which the required substitute data
value is the maximum value recorded in a specified lookback period.
However, on May 26, 1999, EPA added a fourth CEMS missing data tier to
Part 75. The May 1999 rule revisions did not change the missing data
algorithms for the third tier, but the PMA ``cut off'' point for the
third tier was set at 80.0 percent, and below 80.0 percent PMA,
reporting of the maximum potential concentration (MPC) or the maximum
potential NOX emission rate (MER) was required for a missing
data period of any length.
Today's proposed rule would remove from Sec. 75.34(a)(3) and Sec.
75.66(f) the requirement to petition the Administrator to use the
maximum controlled SO2 or NOX concentration (or
maximum controlled NOX emission rate) from the applicable
lookback period. The proposed revisions would simply allow the maximum
controlled values to be reported whenever parametric data are available
to document that the emission controls are operating properly. The
proposed rule would further clarify that this reporting option applies
only to the third missing data tier, when the PMA is greater than or
equal to 80.0 percent, but less than 90.0 percent.
EPA is also proposing to add a new paragraph (a)(5) to Sec. 75.34,
which would allow units with add-on emission controls to report
alternative substitute data values for missing data periods in the
fourth tier, when the PMA is below 80.0 percent. Proposed Sec.
75.34(a)(5) would allow the owner or operator to replace the maximum
potential SO2 or NOX concentration (MPC) or the
maximum potential NOX emission rate (MER) with a less
conservative substitute data value, for missing data hours where
parametric data, (as described in Sec. Sec. 75.34(d) and 75.58(b)) are
available to verify proper operation of the add-on controls.
Specifically, for SO2 and NOX concentration, the
replacement value for the MPC would be the greater of: (a) The maximum
expected concentration (MEC); or (b) 1.25 times the maximum controlled
value in the standard missing data lookback period. For NOX
emission rate, the replacement value for the MER would be the greater
of: (a) The maximum controlled NOX emission rate (MCR); or
(b) 1.25 times the maximum controlled value in the standard missing
data lookback period. The NOX MCR would be calculated in the
same manner as the NOX MER (see Appendix A, section
2.1.2.1(b)), except that the MEC, rather than the MPC, would be used in
the calculation.
Finally, today's proposed rule would revise Sec. 75.38(c) to
extend the alternative missing data options for the third and fourth
tiers to mercury (Hg) concentration, and Sec. 75.58(b)(3) would be
revised to be consistent with the proposed revisions to Sec. Sec.
75.34(a)(3), 75.34(a)(5), and 75.38(c).
EPA believes that for missing data hours in which the emission
controls are working properly, these proposed rule revisions will
prevent gross overestimation of emissions during hours when the source
is operating its emission controls in a manner that is protective of
the environment. When the emission controls are working properly, there
can be as much as a tenfold difference between the MPC, MER, or maximum
value in a lookback period and the actual source emissions. The
proposed alternative substitute data values in Sec. Sec. 75.34(a)(3)
and (a)(5), though much closer to the actual emissions, would still be
conservatively high and would provide the owner or operator with a
strong incentive to keep the CEMS operational. The Agency also believes
that the proposed alternative data substitution methodology in Sec.
75.34(a)(5) ensures that the substitute data values for the fourth tier
will always be higher than the corresponding substitute data values for
the third tier.
3. Substitute Data Values for Hg
EPA is also proposing to revise the Hg missing data procedures.
First, for Hg CEMS, the text of Sec. 75.38(a) would be amended to make
it consistent with Table 1 in Sec. 75.33. Proposed Sec. 75.38(a)
clarifies that the percent monitor data availability (PMA) ``trigger
conditions'' for Hg monitoring systems are different from the trigger
conditions for all other parameters. For all parameters except Hg, the
trigger points that define the boundaries of the four missing data
tiers are 95 percent, 90 percent, and 80 percent PMA. However, for Hg
the corresponding trigger points are 90 percent, 80 percent and 70
percent, respectively.
Second, EPA proposes to completely revise the missing data
provisions in Sec. 75.39 for sorbent trap monitoring systems. In the
current rule, the missing data routines for sorbent trap systems are
substantially different from those for Hg CEMS. At the time of
publication of the Part 75 Hg monitoring provisions, the Agency
believed that a different approach to missing data substitution was
appropriate for sorbent traps, because unlike the Hg CEMS, a sorbent
trap system does not provide real-time hourly average emissions data.
Consequently, EPA prescribed a 12-month missing data ``lookback''
period for the sorbent trap systems. That is, the substitute data
values are based on a lookback through the previous 12 months of
sorbent trap sample results, instead of looking back through 720
quality-assured monitor operating hours, as is done for the Hg CEMS.
EPA has reconsidered the sorbent trap missing data methodology and
has concluded that it is unnecessarily complex and will likely be
difficult to implement and audit. In view of this, the Agency proposes
to amend the missing data procedures for sorbent trap systems, to make
them the same as for Hg CEMS. Section 75.39 would be revised to require
that the initial missing data procedures of Sec. 75.31(b) and the
standard Hg missing data provisions of Sec. 75.38 be followed for
sorbent trap systems. EPA believes that this missing data approach can
work because for the purposes of Part 75 reporting, the average Hg
concentration measured by a sorbent trap system is ``back-filled'' into
each hour of the data collection period to simulate hour-by-hour
concentration measurements (see Sec. 75.57(j)(1)(iii)). Thus, the
hourly Hg concentration data stream from a sorbent trap system will
look essentially the same as the data stream from a CEMS, except that
the Hg concentration will ``flat-line'' (i.e., will not change) during
each data collection period. Therefore, the required missing data
lookbacks through 720 hours of quality-assured data could be done on the
[[Page 49260]]
sorbent trap data stream, although in some cases, because of the flat-
line effect, when the 720 hours of data are arranged in rank order, the
90th percentile, 95th percentile, and maximum values in the lookback
might be identical.
Finally, a new paragraph ``(f)'' would be added to Sec. 75.39 to
address the case in which the owner or operator elects to use a primary
Hg CEMS and a redundant backup sorbent trap system (or vice-versa). In
that case, separate Hg concentration data streams would be recorded and
maintained for the two systems. For reporting purposes, data from the
primary monitoring system would be reported whenever that system is
able to provide quality-assured data (see Sec. 75.10(e)), and quality-
assured data from the redundant backup system (if available) could be
reported during primary monitoring system outages. However, when both
the primary and redundant backup monitoring systems are down and
quality-assured data from a reference method or approved alternative
monitoring system are also unavailable, proposed Sec. 75.39(f) would
require the appropriate substitute data values to be derived from a
lookback through the previous 720 hours of quality-assured data
reported in the electronic quarterly report, irrespective of the source
of those data, i.e., whether they were from the primary system, the
redundant backup system, a reference method, or an approved alternative
monitoring system.
4. Correction of Cross-References
For sources in the NOX Budget Program that report
emissions data only during the ozone season (i.e., May through
September), the quality assurance requirements for the continuous
emission monitoring systems are found in Sec. 75.74(c). In Sec. Sec.
75.74(c)(3)(xi) and (c)(3)(xii), data validation rules are provided for
situations in which required quality-assurance tests of the CEMS are
due by the end of the second or third calendar quarter, but are not
completed on time. In some cases, these rule provisions require the use
of missing data substitution, and refer to the ``appropriate missing
data routine in Sec. 75.31, Sec. 75.33 or Sec. 75.37''. These
references to specific missing data sections are inadequate, because
they only cover initial missing data (for all parameters) and the
standard missing data procedures for NOX , flow rate, and
moisture. Sections 75.34 through 75.36 are not referenced, which
address missing data substitution for units with add-on emission
controls and for diluent gas (O2 or CO2) data
used for heat input rate determination. Many NOX Budget
Program units are equipped with add-on NOX emission
controls, and a great number use data from a CO2 or
O2 monitor to determine the hourly heat input rate. In view
of this, today's rule would revise Sec. Sec. 75.74(c)(3)(xi) and
(c)(3)(xii) by replacing each of the cross-references to specific
missing data sections with a more general reference to the entire block
of CEMS missing data sections, i.e., Sec. Sec. 75.31 through 75.37.
E. Recordkeeping and Reporting
1. Revisions to the General Monitoring Plan Recordkeeping Requirements
EPA proposes to revise the monitoring plan recordkeeping
requirements in Sec. 75.53, to accommodate its new, re-engineered XML
reporting format, which will replace the current electronic data
reporting (EDR) format in 2009. The Subpart H monitoring plan record
keeping provisions in Sec. 75.73(c)(3) (for sources reporting
NOX mass emissions) and the Subpart I monitoring plan record
keeping provisions in Sec. 75.84 (for sources reporting Hg mass emissions)
would be similarly revised to reflect the transition to XML format.
EPA proposes to add two new paragraphs, (g) and (h), to Sec.
75.53, which describe the required monitoring plan data elements in
EPA's re-engineered XML data structure. Proposed Sec. 75.53(a)(1)
would require all affected units to follow the provisions of paragraphs
(g) and (h) instead of the existing recordkeeping requirements of
paragraphs (e) and (f), on and after January 1, 2009. However, early
implementation of the XML format would be allowed or, in some cases,
required. In 2008, existing sources would be allowed to choose between
the EDR format and XML, and new sources reporting for the first time in
2008 would be required to use XML.
Table 1 summarizes the data elements or requirements in Sec. 75.53
that would be removed, replaced or added as a result of transitioning
from the current EDR to XML EDR format.
Table 1.--Monitoring Plan Changes Associated With XML Format
------------------------------------------------------------------------
Data element(s) or Proposed
requirement(s) action(s) Comments
------------------------------------------------------------------------
? Facility short name.. Remove........... These data elements
? Unit program would be collected
classification. and maintained
? Unit boiler type..... through the
? Date of commence Certificate of
operation (Subpart H units). Representation form,
? Date of commence the CAMD Business
commercial operation (Acid System, or
Rain units). internally by EPA.
? Unit retirement date.
? Program code.........
? Reporting frequency..
? Program participation
date.
? State regulation code
? State or local agency
code.
? EIA cross-reference
information..
? Recording and Relocate......... Relocate the
reporting of information requirement to
associated with monitoring record and report
system certification, this information to
recertification, and other Sec. 75.59, the
events. quality-assurance
recordkeeping
section.
? Fuel classification Remove........... These data elements
for boiler. are deemed
? Primary/secondary unnecessary for the
control indicator. new XML reporting
? Type of fuel format.
associated with each
monitoring methodology.
? Primary/secondary
methodology indicator.
? Appendix E
correlation curve segment
data..
[[Page 49261]]
? Component status..... Replace.......... In Sec. 75.53(g),
? Formula status....... use activation date/
? Submission status of hour and
fuel flowmeter data.. deactivation date/
hour instead of
status codes to
better track updates
to monitoring
components,
formulas, and fuel
flowmeter
information.
? Indicator of Add.............. These new data
exemption from multi-load elements are needed
flow RATAs. to properly assess
? Shape of stack or specific Part 75
duct cross-section. quality assurance/
? Stack/duct material quality control (QA/
of construction. QC) requirements and
? Flag to indicate that exemptions.
a monitored location is a
duct.
? Indicator of non-load
based units..
? Analyzer range code.. Add.............. Provide the
? Moisture measurement measurement range
basis.. (high, low, dual)
and moisture basis
(wet or dry) for
each CEMS component
type (SO2, NOX, CO2,
etc.)
? Provide the Replace.......... For each parameter,
monitoring methodologies for associate the
each individual unit. monitoring
? Represent bypass methodology with the
stack monitoring as a monitored lcoation
separate methodology.. (unit, stack or
duct). Integrate
bypass stack
monitoring with
other methodologies.
Only one monitoring
methodology per
paramter would be
allowed.
? For dual-range Add.............. Many times data begin
applications, indicate the to be recorded on
trigger point at which the the high scale at a
component switches from the certain ``trigger
normal measurement scale to point'', before the
the secondary scale. full-scale of the
low range is
reached. EPA needs
this information to
determine when
certain QA tests of
the high-scale are
required.
? Require operating Revise........... In Sec. 75.53(g),
range and normal load require operating
information to be reported range and maximum
for units with CEMS and units load information for
using optional fuel flow-to- all affected units.
load ratio test. Require normal load
determination for
all except peaking
units. Separate the
date of historical
load analysis from
activation date of
the operating range
and load
information.
? Duct width at test Add.............. Add data elements to
section. Sec. 75.53(e) and
? Duct depth at test (g), describing
section. monitoring plan
? WAF.................. requirements for
? Method of determining units with
WAF. rectangular ducts
? WAF effective date that apply a wall
and hour. effects adjustment
? WAF no longer factor (WAF) to
effective date and hour. their flow rate
? WAF determination data. (See Section
date. II.E.2 for further
? Number of WAF test discussion.)
runs.
? Number of Method 1
traverse points in WAF test.
? Number of test ports
in WAF test.
? Number of Method 1
traverse points in reference
flow RATA..
------------------------------------------------------------------------
2. Discussion of Wall Effects Adjustment Requirements for Rectangular Ducts
In 1999, EPA published a new reference method, Method 2H, in
Appendix A of 40 CFR Part 60. Method 2H allows the owner or operator of
a unit with an installed flow monitor to correct the measured gas flow
rates for velocity decay near the stack wall (i.e., ``wall effects'').
Applying Method 2H greatly reduces the possibility of over-reporting
SO2 and NOX mass emissions, which are directly
proportional to the stack flow rate. However, Method 2H applies only to
circular stacks. Consequently, Acid Rain and NOX Budget
Program units with flow monitors installed on rectangular stacks or
ducts (estimated at about 10 percent of the affected units with flow
monitors) were unable to benefit from the use of a wall effects
adjustment factor (WAF).
To remedy this situation, a wall effects correction method for
rectangular stacks and ducts was developed. The method, known as CTM-
041, has been adopted as a conditional test method by EPA. A
conditional test method differs from a reference method in that it is
not in the Code of Federal Regulations, but it is recognized as having
technical merit. Sources interested in using a conditional method in a
particular program must obtain permission from the regulatory agency
administering the program.
Since 2004, when CTM-041 was adopted as a conditional EPA test
method, many Acid Rain and NOX Budget Program sources have
requested (and received) permission from EPA to use it for Part 75
monitoring. As a condition of these approvals, the sources were asked
to report the essential wall effects information in their quarterly
electronic data reports (EDRs). However, EPA had not developed the
necessary electronic record types (RTs) to accommodate the rectangular
duct WAF information. Therefore, the Agency issued guidance,
instructing the sources to use existing EDR record type 910 to report
the WAF data. But record 910, unlike the other EDR record types, has no
fixed data elements or fields. This created problems when the WAF
information began to be reported. Even though detailed examples were
provided in the EPA guidance, a significant portion of the WAF data
were being entered into the wrong columns of the 910 records, making it
difficult to perform electronic audits of the information.
In view of this, EPA created two new EDR record types, RT 532 and
RT 617, to handle the rectangular duct WAF data. Record type 532, which
is a monitoring plan record, summarizes the results of each WAF
determination. Record type 617 is a quality-assurance record and is
submitted along with the results of each flow RATA performed at a
rectangular stack or duct, when EPA Method 2 is used and a wall effects
correction is applied.
The Agency provided a mechanism (the ``Monitoring Data Checking''
(MDC) Software) by which a source could
[[Page 49262]]
create the new EDR records and add them to the quarterly report,
without having to upgrade the data acquisition and handling system
(DAHS). To date, use of the new record types has been voluntary, and
the affected sources have been cooperative. Nevertheless, today's rule
would make mandatory the recording and reporting of the key rectangular
duct WAF data elements using these record types. The proposed
requirements to record and report the results of the WAF determinations
in the monitoring plan are found in Sec. Sec. 75.53(e) and (g) and in
Sec. 75.64. For a discussion of the proposed requirement to record and
report the RATA support data, see Section II.E.5.k, below.
3. Revisions to General Recordkeeping Provisions for Specific Situations
Today's proposed rule would make a series of modifications to Sec.
75.58 to support the new XML data structure. These are summarized in
Table 2.
Table 2.--Proposed Changes to the General Recordkeeping Requirements in
Sec. 75.58
------------------------------------------------------------------------
Data element(s) or Proposed
requirement(s) action(s) Comments
------------------------------------------------------------------------
? For Appendix D units, Add to Sec. This would be
report ID numbers of formulas 75.58(c). required on and
used to calculate SO2 mass after January 1,
emissions and heat input rate. 2009.
? For Appendix E units, Add to Sec. This would be
report the heat input rate 75.58(d). required on and
formula ID for each unit after January 1,
operating hour. 2009.
? For LME units that Revise Sec. Report the fuel type
combust more than one type of 75.58(f). that produces the
fuel, report the fuel type highest emission
that produces the highest NOX rate for each
emission rate. parameter
individually (i.e.,
for SO2, NOX, and
CO2, as applicable).
? For LME units under Add to Sec. This flag is needed
Sec. 75.19(c)(1)(iv)(C)(9), 75.58(f). to ensure that the
indicate whether unit is proper NOX emission
operating at base or peak factor is being
load, each hour. applied.
? For LME units, flag Add to Sec. This flag is needed
each hour in which multiple 75.58(f). to ensure that the
fuels are combusted. proper emission
factors are used for
multiple-fuel hours.
? For LME units using Revise Sec. Require only the
long-term fuel flow, report 75.58(f). system ID. Long-term
the component and system ID fuel flow systems
codes. have only one
component.
------------------------------------------------------------------------
4. Proposed Revisions to the QA/QC Recordkeeping Provisions
EPA is proposing to make a series of revisions and additions to the
quality assurance and quality control recordkeeping provisions in Sec.
75.59, in support of the XML data format. These are summarized in Table
3.
Table 3.--Proposed Changes to the QA/QC Recordkeeping Provisions of Sec.
75.59
------------------------------------------------------------------------
Data element(s) or Proposed
requirement(s) action(s) Comments
------------------------------------------------------------------------
? Describe each Revise Sec. Expand to include
recertification event, and 75.59(a)(8). events that require
the date and type of each certification and
recertification test. diagnostic testing.
Add requirement to
report conditional
data validation
begin date (if
applicable).
Corresponds to
current EDR record
type 556.
? Record component and Revise Sec. Sec. Require only the
system ID codes for daily 75.59(a) and component ID for
calibrations, 7-day (b). these tests. This
calibration error tests, requirement would be
cycle time tests, linearity effective on and
checks, flow monitor leak after January 1,
checks and interference 2009. The cycle time
tests, and fuel flowmeter test for NOX-diluent
accuracy tests. systems would be
simplified.
? Record the test Revise Sec. Clarify that test
number and reason for test, 75.59(a)(1)(viii number and reason
for daily calibrations and 7- ). for test code apply
day calibration error tests. only to 7-day
calibration error
tests, not to daily
calibrations.
? Report the span value Remove from Sec. The span value in the
with the results of each 75.59(a)(3)(ii). monitoring plan
linearity check. records will be used
to evaluate the
linearity checks.
? Provide an on-line or Add to Sec. This flag is needed
off-line indicator flag for 75.59(a)(1). to properly assess
all calibration error tests. the hour-by-hour
quality-assurance
status of CEMS
following
calibration error
tests.
? For flow-to-load Add, as Sec. This addition is
tests of multiple stack 75.59(a)(4)(vii) needed for
configurations, indicate (M). consistency with the
whether separate reference flow-to-load test
ratios are calculated for reporting
each stack. instructions
(current EDR record
type 605).
? Report sufficient Remove and EPA's checking
information to validate all reserve Sec. software no longer
grace period claims. 75.59(a)(12)(iii needs this
). information to
evaluate grace
periods.
? Record the component Revise Sec. On and after January
and system ID codes for each 75.59(b)(4)(i)(A 1, 2009, record only
fuel flow-to-load ratio test. ). the system ID for
these tests.
? Report Appendix E Revise Sec. On and after January
correlation curve test data 75.59(b)(5). 1, 2009, report this
on a monitoring system basis. data on a component
basis.
? Report the type(s) of Remove Sec. This information is
fuel(s) combusted during each 75.59(b)(5)(i)(H not needed in the
run of an Appendix E ). new XML format and
correlation curve test. would not be
reported after
December 31, 2008.
? Report the monitoring Add, as Sec. This requirement is
system ID code with reference 75.59(b)(4)(ii)( consistent with the
fuel flow-to-load ratio test N). reporting
data. instructions for the
reference fuel flow-
to-load ratio
(current EDR record
type 629).
[[Page 49263]]
? For LME units, Add, as Sec. This requirement is
indicate which test runs are 75.59(d)(1)(xiii consistent with the
used to calculate fuel-and- ). reporting
unit-specific NOX emission instructions for NOX
rates. emission testing of
LME units (current
EDR version 2.2,
record type 650).
? For LME units, Revise Sec. This requirement
multiply the tested NOX 75.59(d)(2)(iii) applies only to
emission rate by 1.15, if and add new Sec. turbines that
applicable. Sec. operate only at base
75.59(d)(2)(vi) or peak load.
and (vii). Consistent with the
reporting
instructions
(current EDR version
2.2, record type
650), reporting of
an hourly base or
peak load indicator
and the default NOX
emission rate for
peak load operation
would be required.
? Record the date and Add Sec. This requirement
hour of completion of all 75.59(f). would be effective
required DAHS verifications, on and after January
whether for initial 1, 2009. EPA needs
certification, this information to
recertification, or other properly establish
events. provisional
certification or
recertification
dates. Proposed
changes to Sec.
75.63(a)(2)(iii)
would allow this
information to be
reported
electronically as
part of the
certification or
recertification
application.
? Record the Add Sec. For periodic testing
appropriate reference method 75.59(e). of low mass emission
data elements for Hg emission units, recording of
tests of low-emitting units. the reference method
data elements in
either Sec.
75.59(a)(7)(vii),
(viii), or (x) would
be required,
depending on which
reference method is
used for the
testing.
? Monitoring system ID Add, as Sec. Recording of certain
? Test number.......... 75.59(a)(7)(ix). data elements and
? Operating level...... test results would
? RATA end date and be required for
time. units with
? Number of Method 1 rectangular ducts/
traverse points. stacks that apply a
? Wall effects wall effects
adjustment factor. adjustment factor
(WAF) to correct
their flow rate
data. These data
elements would be
required for each
flow RATA.
? Percent CO2 and O2 in Add, as Sec. Recording of certain
the stack gas, dry basis 75.59(a)(7)(x). data elements would
? Moisture content of be required when
the stack gas (percent H2O). using Method 29 for
? Average stack gas the RATA of a Hg
temperature ([deg]F). monitoring system.
? Dry gas volume These data elements
metered (dscm). would be required
? Percent isokinetic... for each RATA run.
? Particulate Hg
collected in the front half
of the sampling train,
corrected for the front-half
blank value ([mu]g).
? Total vapor phase Hg
collected in the back half of
the sampling train, corrected
for the back-half blank value
([mu]g).
------------------------------------------------------------------------
5. Other Reporting Issues
a. Long-Term Cold Storage and Deferred Units
The proposed changes to Part 75 would clarify the issue of ``long-
term cold storage (LTCS)''. First, as previously noted, a definition of
``long-term cold storage'' would be added to Sec. 72.2. LTCS would
mean that the unit has been completely shut down and placed in storage
and that the shutdown is intended to last for an extended period of
time (at least two calendar years). Second, a new paragraph, (a)(7),
would be added to Sec. 75.61. Proposed Sec. 75.61(a)(7) would require
the owner or operator to provide notifications when a unit is placed in
LTCS and when the unit re-commences operation. Third, Sec. 75.20(b)
would be modified to require recertification of all monitoring systems
when a unit re-commences operations after a period of long-term cold
storage. If a source claiming LTCS status re-commenced operation sooner
than two years after being placed in LTCS, the notification and
recertification requirements would apply. Fourth, the proposed rule
would exempt a unit in LTCS from quarterly emissions reporting under
Sec. 75.64 until the unit recommences operation. Parallel rule
provisions and appropriate cross-references regarding quarterly
reporting requirements for Subpart H and Subpart I units would be added
to Sec. Sec. 75.73(f)(1) and 75.84(f)(1), respectively. Finally, EPA
notes that these proposed LTCS provisions are not intended to apply to
periods of non-operation of units that are ``on-call'' and available
for dispatch.
EPA also proposes to revise the provisions of Sec. Sec. 75.4(d)
and 75.61(a)(3) pertaining to ``deferred'' units, i.e., units for which
a planned or unplanned outage prevents the required continuous
monitoring systems from being certified by the compliance date. The
scope of Sec. 75.4(d) would be broadened beyond the Acid Rain Program
to include units in a State or Federal pollutant mass emissions
reduction program that adopts the monitoring and reporting provisions
of Part 75. Examples of such programs include the Clean Air Interstate
Regulation (CAIR), which is scheduled to begin in 2008 and the Clean
Air Mercury Regulation (CAMR), which goes into effect in 2009. The
revisions to Sec. Sec. 75.4(d) and 75.61(a)(3) are deemed necessary
because the CAIR and CAMR rules do not address deferred units.
Revised Sec. 75.4(d) would require the owner or operator of a
deferred unit to provide notice of unit shutdown and recommencement of
commercial operation, either according to Sec. 75.61(a)(3) (for
planned shutdowns such as scheduled maintenance outages and for
unplanned, forced unit outages) or Sec. 75.61(a)(7) (for units in
long-term cold storage). For all of these circumstances involving
deferred units, the Part 75 continuous monitoring systems would have to
be certified within 90 unit operating days or 180
[[Page 49264]]
calendar days (whichever comes first) of the date that the unit
recommences commercial operation. In the time interval between the unit
re-start and the completion of the required certification tests, the
owner or operator would be required to report emissions data, using
either: (1) Maximum potential values; (2) the conditional data
validation procedures of Sec. 75.20(b)(3); (3) EPA reference methods;
or (4) another procedure approved by petition to the Administrator
under Sec. 75.66.
Today's proposed rule would revise the notification requirements of
Sec. 75.61(a)(3) to be consistent with the changes to Sec. 75.4(d).
For planned unit outages, the owner or operator would be required to
provide notice of shutdown at least 21 days prior to the compliance
date. For unplanned outages, notice would be provided within 7 days
after the shutdown. For both planned and unplanned outages, notice of
the date on which the unit is expected to resume operation would be
provided at least 21 days prior to that date. Proposed Sec.
75.61(a)(3) also includes provisions to address situations in which
there are changes to any of the planned or projected dates.
b. Notice of Initial Certification Deadline
EPA proposes to revise Sec. 75.61(8) to require new and newly-
affected sources to notify EPA when the monitoring system certification
deadline is reached. Depending on the program(s) to which the unit is
subject and whether the unit is new or newly-affected, this date will
be the earlier of 90 unit operating days or 180 calendar days after the
unit: (a) Commences commercial operation; (b) commences operation; or
(c) becomes an affected unit. The Agency must know this date to
correctly assess when to begin counting emissions against allowances
pursuant to Sec. 72.9. Knowing this date also confirms that the monitoring
systems either have or have not been certified by the legal deadline.
c. Monitoring Plan Submittal Deadline
Today's proposed rule would change the submittal deadline for the
initial monitoring plan for new and newly-affected units from 45 days
to 21 days prior to the initial certification testing. This proposed
revision would synchronize the initial monitoring plan submittal with
the initial test notice (see proposed changes to Sec. Sec. 75.62(a)(1)
and (2), Sec. Sec. 75.73(e)(1) and (2) for Subpart H units, and
Sec. Sec. 75.84(e)(1) and (e)(2) for Subpart I units).
EPA also proposes to remove the requirement in Sec. 75.62(a)(1)
that the monitoring plan must be submitted ``in each electronic
quarterly report''. Rather, inclusion of the monitoring plan in the
report would be optional, and monitoring plan updates would be made
either prior to or concurrent with (but not later than) the date of
submission of the quarterly report. These proposed revisions would
allow sources to maintain their monitoring plan information separate
from the quarterly report. However, this flexibility would only be
available to sources reporting in the new XML-EDR format under the re-
engineered data submission process. Until re-engineering of the data
systems is complete, EPA will continue to collect and process all
electronic monitoring plan data submitted in quarterly reports in the
current EDR format.
d. EPA Form 7610-14
For each certification and recertification application, Sec. Sec.
75.63(a)(1) and (a)(2) require hardcopy EPA form 7610-14 to be
submitted to the Administrator along with the certification or
recertification test results in EDR format. However, significant
upgrades to EPA's data systems have been made in recent years, and Form
7610-14 is no longer needed to process the applications. Therefore,
Sec. Sec. 75.63(a)(1)(i)(A) and (a)(2)(i) would be revised to remove
the requirement to submit Form 7610-14 to the Administrator.
e. LME Applications
EPA is proposing to remove the requirement from Sec.
75.63(a)(1)(ii)(A) for a hardcopy LME certification application to be
submitted to the Administrator. Only the electronic portion of the
application, including the monitoring plan and LME qualification
records, would be sent to EPA. The hardcopy portion of the LME
application would be sent to the State and to the EPA Regional Office.
f. Reporting Test Data for Diagnostic Events
EPA proposes to revise Sec. 75.63(a)(2)(iii) to make the reporting
of the results of diagnostic tests more flexible. Rather than requiring
these test results to be reported in the electronic quarterly report
for the quarter in which the tests are performed, they could either be
submitted prior to or concurrent with that quarterly report. However,
this flexibility in the reporting of diagnostic test results would only
be available to sources reporting in the new XML-EDR format under the
re-engineered data submission process. Until re-engineering of the data
systems is complete, EPA will continue to collect and process all
diagnostic test results submitted in quarterly reports in the current
EDR format.
g. Modifications to Sec. 75.64
As part of its data systems re-engineering effort, EPA proposes to
revise Sec. 75.64(a) to incorporate language describing the transition
from the current reporting requirements of paragraphs (a)(1), (a)(2)
and (a)(8) through (a)(15) to the new requirements of paragraphs (a)(3)
through (a)(15). Note that only the requirements of paragraphs (a)(1)
and (a)(2) of the current rule would be replaced, by the requirements
of paragraphs (a)(3) through (a)(7). Proposed paragraphs (a)(3) through
(a)(7) better describe the separation of the monitoring plan and
quality assurance test information from the quarterly emissions report.
Current paragraphs (a)(3) through (a)(7) and (a)(9) through (a)(11)
would remain unchanged, but would be renumbered as paragraphs (a)(8)
through (a)(15). Current paragraph (a)(8) would be removed.
h. Steam Load Reporting
Historically, Part 75 has required units that produce electrical or
thermal output to report unit load either in megawatts or in thousands
of pounds per hour of steam. Today's proposed rule would add a third
option, i.e., to report load in units of mmBtu/hr of steam thermal
output. This option is needed to accommodate emissions trading programs
in which allowance allocations are made on an electrical or thermal
output basis, rather than a heat input basis. Certain units in these
programs (e.g., industrial boilers) do not produce electrical output
and would have to report thermal output instead. In the current rule,
steam load is expressed only in thousands of pounds per hour, which
does not provide the necessary thermal output information. EPA
therefore proposes to add text to the following sections of Part 75,
describing the new thermal output reporting option: Sec. Sec.
75.16(e)(3), 75.57(b)(3), 75.59(b)(4)(ii); Appendix A, Sections 7.7(a)
and 7.7(c); Appendix B, Sections 2.2.5(a) and 2.2.5(a)(2); Appendix D,
Sections 2.1.7.1(a), 2.1.7.1(c), 2.1.7.2(a), and 2.1.7.2(c); and
Appendix E, Section 2.4.1.
i. Test Notification Requirements--Hg Low Mass Emission Units
Section 75.61(a)(5) of the current rule requires the owner or
operator or the designated representative to provide 21-day advance
notice for various periodic quality-assurance tests. In particular,
this notice must be provided to the
[[Page 49265]]
Administrator, to the appropriate EPA Regional Office and to the State
or local agency (unless a particular agency issues a waiver from the
requirement) for the semiannual or annual relative accuracy tests of
CEMS, and for re-tests of both Appendix E peaking units and low mass
emissions (LME) units.
Under Subpart I of Part 75, certain low-emitting units covered by
CAMR may qualify under Sec. Sec. 75.81(b) through (d) to perform
periodic (semiannual or annual) Hg emission testing in lieu of
operating and maintaining continuous Hg monitoring systems. Today's
proposed rule would expand Sec. 75.61(a)(5) and add corresponding
introductory text to Sec. 75.61(a)(1) to require the owner or operator
or the designated representative to provide 21 day notice of these
periodic Hg emission tests to EPA and to the State.
j. Hardcopy Reports for Retests of Hg Low Mass Emission Units
Sections 75.60(b)(6) and (b)(7) of the current rule require the
designated representative (DR) to submit the results of certain
periodic quality-assurance tests to the appropriate EPA Regional Office
or to the State or local agency, when the test results are requested in
writing (or by electronic mail). In particular, the results of
semiannual or annual RATAs of CEMS and the routine re-tests of Appendix
E units may be requested. If requested, the test results must be
submitted within 45 days after the test is completed or within 15 days
of the request, whichever is later. Today's rule would add a new
paragraph (b)(8) to Sec. 75.60, requiring the DR to provide, upon
request from EPA or the State, the results of the semiannual or annual
mercury emission tests required under Sec. 75.81(d)(4) for low-
emitting units covered by CAMR. The time frame for submitting these Hg
emission test results would be the same as for the RATAs and Appendix E
re-tests.
k. Wall Effects Adjustment Factors
As previously discussed in Section II.E.2 of this preamble, today's
rule would require sources with flow monitors installed on rectangular
stacks or ducts to report the results of wall effects adjustment factor
(WAF) determinations in the monitoring plan, whenever Conditional
Method CTM-041 is used to adjust the measured stack gas flow rates for
the effects of velocity decay near the stack wall.
For sources with flow monitors installed on circular stacks,
reporting of wall effects information is currently required when Method
2H is used in conjunction with Method 2, 2F or 2G (see Sec. Sec.
75.64(a)(2)(xiii), 75.73(f)(1)(ii)(K) and 75.84(f)(1)(ii)(I)). The wall
effects data elements that must be reported are found in Sec. Sec.
75.59(a)(7)(ii) and (a)(7)(iii). These data are not reported in the
monitoring plan, but are submitted along with flow RATA results, as
supplementary information.
For rectangular stacks and ducts, some of the same supporting data
elements in Sec. Sec. 75.59(a)(7)(ii) and (a)(7)(iii) are needed for
flow RATAs performed using Method 2F or 2G, when wall effects
corrections are applied. Additional supporting data elements, not in
the current rule, are also needed for Method 2 flow RATAs when wall
effects adjustments are made. In view of this, today's rule would
revise the text of Sec. Sec. 75.64(a)(2)(xiii), 75.73(f)(1)(ii)(K) and
75.84(f)(1)(ii)(I) and would add RATA support data elements to a new
paragraph, (vii), in Sec. 75.59(a)(7). EPA believes that these
proposed changes will clarify which wall effects data elements must be
reported for circular stacks, which ones are reported for rectangular
stacks and ducts, and which data elements must be reported for both
types of stacks.
F. Subpart H (NOX Mass Emissions)
1. Subpart H Diluent Monitoring Systems
For coal-fired Subpart H units that calculate NOX mass
emissions as the product of NOX concentration and flow rate
and are required to monitor and report the unit heat input, Sec.
75.71(a)(2) requires the installation of an ``O2 or
CO2 diluent gas monitor''. Consistent with the definition of
a CEMS in Sec. 72.2, this diluent monitor, which is only used for the
heat input determination, should be described as an ``O2 or
CO2 monitoring system''. Today's proposed rule would revise
the text of Sec. 75.71(a)(2) accordingly.
2. Identifying a NOX Mass Methodology
EPA is proposing to revise Sec. 75.72 to clarify that only one
NOX mass emissions methodology may be identified in the
monitoring plan at any given time. Designation of primary and secondary
NOX mass calculation methodologies would no longer be
allowed. EPA believes that one methodology for NOX mass
emissions is sufficient. If a source is subject to both Subpart H and
to the Acid Rain Program (ARP) and is concerned about losing
NOX data when the diluent component of the NOX
emission rate system is out-of-control, that source should choose the
NOX concentration times flow rate calculation method as the
NOX mass calculation methodology. This would require a
NOX concentration system to be identified in the monitoring
plan, in addition to the NOX emission rate system. The
NOX concentration system would be used only to determine
NOX mass emissions, and the NOX emission rate
system would be used only to meet the ARP requirement to report
NOX in lb/mmBtu.
Although it is possible with the current EDR format to identify
multiple methodologies for a parameter, this was intended for ARP
applications, not for NOX mass emission measurement.
Multiple methodology records for SO2 are sometimes necessary
when a bypass stack is used. However, as discussed in Section II.E.1 of
this preamble, the reporting of monitoring methodologies is being
restructured as part of EPA's re-engineering effort. Bypass stack
methods are being integrated with other monitoring methods and will no
longer be considered stand-alone methodologies.
3. Reporting of Subpart H Facility Information
Consistent with the proposed revisions to Sec. 75.64, EPA proposes
to revise Sec. 75.73(f)(1), to phase out the requirement of Sec.
75.73(f)(1)(i)(B) to include facility location information in each
quarterly report.
4. Linearity Check Requirements for Ozone Season-Only Reporters
For Subpart H sources that report emissions data on an ozone
season-only (OSO) basis, today's proposed rule would revise the
linearity check provisions in Sec. Sec. 75.74(c)(2), (c)(2)(i),
(c)(2)(ii), (c)(3)(ii), (c)(3)(vi), and (c)(3)(viii). Currently, OSO
reporters are required to do a pre-season linearity check, an in-season
second quarter linearity check (in May or June, if the unit operates
for >=168 hours in May and June), and a third quarter linearity check,
if the unit operates for >=168 hours in that quarter. Many sources have
misunderstood these rule provisions, particularly the requirement to
perform an in-season linearity check in the second quarter.
Since the beginning of the NOX Budget Program, there
have been a number of instances where sources have performed pre-season
linearity checks in April, but have not done the required in-season
linearity checks in May or June. In some cases, this has resulted in
CEMS out-of-control periods and has required the use of missing data
substitution. These sources apparently believed that the April tests
were sufficient to satisfy both the pre-season and second quarter
linearity check requirements because for year-round
[[Page 49266]]
reporters, linearity checks are required only once per quarter.
The current rule also requires OSO reporters to operate and
maintain each CEMS and to perform daily calibration error tests, in the
time period extending from the hour of completion of the pre-season
linearity check through April 30. EPA has found that this rule
provision is not well-understood by the affected sources. It is also
difficult for the Agency to assess compliance with the provision, since
sources are not required to report the results of any off-season
calibration error tests done prior to April. Further, when pre-season
linearity checks are done several months before the ozone season, the
quality of the data at the start of the ozone season is somewhat
questionable.
In view of these considerations, today's proposed rule would revise
Sec. 75.74(c)(2) to restrict the time period in which pre-season
linearity checks may be conducted. EPA proposes to require the pre-
season linearity checks to be done in the month of April. All
references to performing the pre-season linearity checks at other times
would be deleted, along with the requirement to keep the off-season
daily calibration error tests in a format suitable for inspection.
Today's proposed rule would also revise Sec. 75.74(c)(2)(i)(D) by
removing the conditional grace period provision and adding a cross-
reference to proposed Sec. 75.74(c)(3)(ii)(E), which addresses data
validation. If the April linearity check is not completed prior to the
start of the ozone season, data from the monitor would be considered
invalid as of May 1, unless the conditional data validation procedures
of Sec. 75.20(b)(3) are applied. Proposed Sec. 75.74(c)(3)(ii)(E)
would allow a probationary calibration error test to be done, to begin
a period of conditional data validation. Then, the linearity check
would be done ``hands-off'' within a 168 unit operating hour period
following the calibration error test. If the linearity check is passed
within the allotted time, the conditionally valid data would be
considered quality-assured, back to the hour of the probationary
calibration error test. If the linearity check is failed, all data from
the monitor would be invalidated back to the beginning of the ozone
season and would remain invalid until a linearity check is passed. If
the linearity check is done after the 168-hour period expires, data
validation would be done according to Sec. 75.20(b)(3)(viii), subject
to the restrictions of Sec. 75.74(c)(3)(xii).
Today's proposed rule would add a new paragraph (F) to Sec.
75.74(c)(3)(ii), stating that a pre-season linearity check done in
April fulfills the second quarter linearity check requirement. Related
Section 75.74(c)(3)(viii) would be removed and reserved. Further,
proposed Sec. 75.74(c)(3)(ii)(B) would require the third quarter
linearity check to be conducted either by July 30 or within a 168
operating hour period of conditional data validation thereafter.
Finally, proposed Sec. 75.74(c)(3)(ii)(G) would address the case where
a unit operates infrequently and the 168 operating hour conditional
data validation period associated with the April linearity check
extends through the second quarter, into the third quarter. In that
case, if the linearity check is performed and passed in the third
quarter, before the 168 operating hour window expires, then that one
linearity check would satisfy all three of the ozone season linearity
check requirements, i.e., for the pre-season, for the second quarter,
and for the third quarter.
EPA believes that the proposed linearity check schedule for OSO
reporters would ensure that the gas monitors' response is linear
throughout the ozone season and would simplify the regulation by
reducing the number of required linearity checks from three to two (and
in some cases, one) per season.
5. RATA Requirements for Ozone Season Only Reporters
For OSO reporters, Part 75 requires, for quality-assurance
purposes, that at the start of each ozone season each required CEMS
must be within the ``window'' of data validation of a current, non-
expired RATA. Section 75.74(c)(2)(ii) states that this requirement can
be met either by performing a RATA in the pre-season (between October 1
and April 30) or, in some instances, by relying on the results of a
RATA done in the previous ozone season. For example, if a RATA was
performed inside the ozone season, in the 3rd quarter of last year, the
window of data validation for the test would extend through the 3rd
quarter of this year, provided that the RATA results show that the CEMS
qualifies for an ``annual'' RATA frequency. However, if a
``semiannual'' test frequency is obtained, the data validation window
would expire at the end of the first quarter of this year, and the RATA
could not be used to validate data in the current ozone season.
Therefore, a pre-season RATA would be required.
The rule further requires each CEMS to be operated, calibrated and
maintained in the time period extending from the completion of the
RATA, through April 30. This means that if the RATA being used for data
validation in the current ozone season was performed during the last
ozone season, the CEMS would have to be operated, calibrated and
maintained for the entire off-season from October 1 through April 30.
Compliance with this type of requirement is difficult for EPA to
assess, as previously explained in paragraph 4 of this section. Also,
many sources choosing the OSO reporting option find this operation and
maintenance (O&M) requirement to be counter-intuitive, because they
expect to be required to meet Part 75 monitoring obligations only
during the ozone season. If it were discovered during an audit that
this O&M requirement had not been met, a facility could incur
substantial data loss. Further, if a CEMS is not maintained in a manner
consistent with normal operating practices for an extended period of
time following a RATA that was done long before the ozone season, the
results of that RATA may not be a true indicator of the CEMS data
quality at the start of the ozone season.
In view of these considerations, EPA is proposing to restrict the
window of time in which pre-season RATAs may be performed. Proposed
Sec. 75.74(c)(2)(ii) would require the RATAs to be done either in the
first quarter of the year or in the month of April. This restriction
would prohibit RATAs done in the previous year from being used to
validate data in the current ozone season.
Section 75.74(c)(2)(ii)(F) would be revised to address data
validation. The proposed data validation rules for RATAs would be
similar to those proposed for linearity checks, i.e., a period of
conditional data validation (720 operating hours) would be allowed when
the pre-season RATA is not completed by the April 30 deadline.
Consistent with these revisions, today's proposed rule would delete the
data validation and conditional grace period provisions in Sec. Sec.
75.74(c)(2)(ii)(G) and (c)(2)(ii)(H) and would remove and reserve
Sec. Sec. 75.74(c)(3)(vi), (vii), and (viii).
Note that EPA is not modifying the provisions of Sec.
75.74(c)(3)(xii), which allows the results of required quality
assurance tests that are completed early in the fourth quarter, within
a window of conditional data validation, to be submitted with the
electronic data report for the third quarter. This provision provides
sources with a ``last chance'' opportunity to complete the required
quality assurance tests before the final ozone season reports for the
NOX Budget program are due.
[[Page 49267]]
6. Determining Peaking Status for Ozone Season Only Reporters
EPA proposes to revise Sec. 75.74(c)(11) to clarify that when
peaking unit status for ozone season-only reporters is determined,
3,672 hours (i.e., the number of hours in the ozone season) should be
used instead of 8,760 hours in the capacity factor equation. This
clarification is supported by Question 27.1 in the ``Part 75 Emissions
Monitoring Policy Manual''.
7. Calculation of Ozone Season NOX Mass Emissions--LME Units
Today's rule would correct an organizational error in Subpart H of
Part 75. Section 75.72(f), which describes ozone season NOX
mass calculations for units using the low mass emission (LME)
methodology under Sec. 75.19, would be removed, and its basic content
would be relocated to Sec. 75.71(e). The LME provision in Sec. 75.72
appears to have been inadvertently placed in that section. The
monitoring provisions of Sec. 75.72 apply to common and multiple stack
configurations, whereas Sec. 75.71 addresses unit-level monitoring.
LME is a unit-level monitoring methodology.
G. Subpart I (Hg Mass Emissions)
1. Heat Input Provisions for Common and Multiple Stacks
Subpart I of Part 75 provides the basic procedures for monitoring
Hg mass emissions and heat input from affected units under CAMR.
However, due to an apparent oversight, the heat input monitoring
provisions for certain monitoring configurations were inadvertently
omitted from the final rule. In particular, the heat input methodology
for common stacks shared by affected and non-affected units, and the
methodology for multiple stack or duct configurations are missing.
Today's rule would add three new paragraphs, (b)(3), (c)(4) and (d)(3)
to Sec. 75.82 to correct this deficiency.
For the common stack shared by affected and non-affected units,
proposed Sec. 75.82(b)(3) would require the owner or operator to
either measure the total heat input rate at the common stack and
apportion it to the individual units by load, according to Sec.
75.16(e)(3), or to determine the heat input rate at the individual
units by installing a flow monitor and a diluent monitor on the duct
leading from each unit to the common stack. For multiple stack
configurations, proposed Sec. Sec. 75.82(c)(4) and (d)(3) would
require the owner or operator to determine the hourly unit heat input
by measuring the hourly heat input rate (mmBtu/hr) at each stack,
multiplying each stack heat input rate by the stack operating time (hr)
to convert it to heat input (mmBtu), and then summing the hourly stack
heat input values.
2. Low Mass Emission Alternative
Section 75.81(b) of Subpart I provides an alternative
(``excepted'') monitoring methodology for units with low Hg mass
emissions. To qualify to use this methodology, emission testing is
required to demonstrate that the unit has the potential to emit no more
than 29 lb (464 ounces) of Hg per year. Once a unit qualifies, periodic
retesting (semiannual or annual, depending on the emission level) is
required to demonstrate that the unit is actually emitting less than 29
lb/yr of Hg.
Section 75.81(e) allows the low mass emission alternative to be
used for common stacks, provided that the units sharing the stack are
tested individually and each one qualifies as a low-emitter. Though not
explicitly stated in the rule, it is implied that the periodic retests
for common stack configurations would also have to be done at the unit
level. EPA is reconsidering this approach, for two reasons: (1) With
respect to the initial certification testing, it appears to be overly
restrictive for at least one particular configuration; and (2) the
Agency believes that for the retests it may be unnecessarily difficult
and costly to implement.
Therefore, with one exception (discussed below), EPA is proposing
to revise Sec. 75.81(e) to require Hg testing of the individual units
that share the common stack only for the initial demonstration that the
units individually qualify as low emitters. Once this has been
satisfactorily demonstrated, the required semiannual or annual retests
could then be done at the common stack, at a normal load level for the
configuration.
The proposed revisions to Sec. 75.81(e) would also allow the
initial low mass emitter qualification for a group of identical units
sharing a common stack to be based on emission testing of a subset of
those units. To exercise this option, the units would first have to
qualify as identical under Sec. 75.19(c)(1)(iv)(B). Then, the number
of units required to be tested would be determined from Table LM-4 in
Sec. 75.19.
The proposed rule would allow one exception to the requirement to
test the individual units sharing a common stack, in order to
demonstrate that the units qualify for low mass emitter status. In the
case where the gas streams from the individual units are combined
together and routed through emission controls that reduce the Hg
concentration (e.g., a wet scrubber) before entering the common stack,
the only way to measure the controlled Hg concentration from the
individual units would be to operate them one at a time rather than
concurrently. EPA believes that for many such configurations, this
manner of unit operation is abnormal and potentially problematic.
Therefore, the revisions to Sec. 75.81(e) would allow both the initial
and ongoing low mass emission testing to be done at the common stack in
cases where the individual unit effluent gas streams are combined
together upstream of a control device that removes Hg before entering
the common stack. Owners or operators electing to use this option would
be required to perform the testing with all of the units that share the
stack in operation, and the combined load during the testing would be
``normal'', as defined in Section 6.5.2.1 of Appendix A.
Today's proposed rule would also revise Sec. 75.81(c)(1), to
clarify the time frame in which to perform the initial certification
testing for the low mass emission option. The current rule simply
states that this testing must be done ``prior to the compliance date in
Sec. 75.80(b)'', but does not specify how far in advance of that date
the testing may be done and still be considered acceptable. Further,
Sec. 75.81(d)(1) requires the test results to be submitted as a
certification application, no later than 45 days after completing the
testing. And Sec. 75.81(d)(4) requires periodic Hg retesting to
commence within two or four ``QA operating quarters'' after the quarter
of the certification testing.
This approach to implementing the low mass emission alternative
should work reasonably well, provided that the certification test date
is close in time to the compliance date. However if there is too long a
gap between the certification testing and the start of the program, it
becomes problematic. For instance, if the testing is done too early,
the requirement to submit a certification application within 45 days
could result in applications being submitted long before the regulatory
agencies are ready to receive and process them. Also, the periodic
retesting requirements of Sec. 75.81(d)(4), which become active on the
certification test date, could result in several Hg retests being done
before the program begins. This is clearly contrary to the purpose of
the retests, which, like the periodic relative accuracy tests of CEMS,
are intended to commence after the compliance date, when Hg emissions
reporting has begun. It also raises questions about which default
emission rate to use for the initial reporting. In view of these
[[Page 49268]]
considerations, EPA is proposing to revise Sec. 75.81(c)(1), to
require that the Hg testing for initial certification be done no more
than 1 year before the compliance date. Sections 75.81(d)(2) and
75.81(d)(5) would also be revised, to address the case where a retest
may be required before the compliance date (e.g., when Sec.
75.81(d)(4) requires a retest within two QA operating quarters,
following a certification test that was done 9 to 12 months before the
compliance date). In such cases, the default Hg emission rate used at
the beginning of the program would be the value that was obtained in
the retest.
Finally, EPA proposes to amend Sec. 75.81(d)(4) to address the
emission testing requirements when the fuel supply is changed. Revised
Sec. 75.81(d)(4) would require additional Hg retesting within 720 unit
operating hours, following a change in the fuel supply. The results of
this retest would be applied retrospectively, back to the time of the
fuel switch. Section 75.81(c)(1) would also be revised to require that
the fuel combusted during the initial certification testing be from the
same source of supply as the fuel combusted when the program starts.
The Agency believes these rule provisions are necessary to ensure that
the default Hg concentration used for Part 75 reporting is
representative of the fuel being combusted in the unit. However, note
that the proposed revisions only address the emission testing and
reporting requirements for one case, i.e., where the source of supply
for the primary fuel (assumed to be coal) changes. Cases where the coal
supply does not change, but the unit sometimes burns other types of
fuel besides coal or co-fires mixtures of coal and other fuels, are not
addressed. In view of this, EPA also solicits comments and suggestions
on how to apply the Hg low mass emitter option in these situations (i.e.,
what emission testing and reporting requirements might be appropriate).
3. Harmonization of Subpart I With Other Proposed Rule Revisions
Subpart I of Part 75 also contains a recordkeeping and reporting
section (Sec. 75.84). Section 75.84 contains a few stand-alone
provisions, but for the most part, it cross-references the primary
monitoring plan, recordkeeping, notification and reporting sections of
the rule (i.e., Sec. Sec. 75.53, 75.57 through 75.59, 75.61, and
75.64) and other sections of Subpart I.
As discussed in detail in Section E of this preamble, today's rule
would make substantial revisions to the monitoring plan, recordkeeping
and reporting sections of Part 75, in support of EPA's data systems re-
engineering effort. To make Subpart I consistent with these proposed
revisions and with the other proposed changes in today's rule, a number
of minor adjustments would also be made to the text of Sec. Sec.
75.84(c)(3), (e)(1), (e)(2), and (f)(1).
H. Appendix A
1. CO2 Span Values
EPA proposes to revise Section 2.1.3 of Appendix A, to allow the
use of CO2 spans less than 6.0 percent CO2 if a
technical justification is provided in the hardcopy monitoring plan.
This added flexibility in the CO2 span value mirrors a
similar provision in Section 2.1.3 for O2 span values.
2. Protocol Gas Audit Program
EPA is responsible for implementing air quality programs that rely
on accurate calibration gases. Under these programs, calibration gases
are used to calibrate EPA reference methods which, in turn, are used to
perform stack tests or to calibrate installed pollutant continuous
emissions monitoring systems (CEMs) that are used by regulated sources
to report emissions to EPA. If the reference methods are low by 20%,
then emissions may be underreported by 20%. Calibration gases are also
used to ensure that ambient air quality analyzers provide accurate
results. Accurate calibrations gases are critical in helping to ensure
that the Clean Air Act-mandated emission reductions are achieved.
Section 2.1.10 of ``EPA Traceability Protocol for Assay and
Certification of Gaseous Calibration Standards'' (Protocol Procedures),
September 1997 (EPA-600/R-97/121) states that EPA will periodically
assess the accuracy of calibration gases and publish the results.
Between 1978 and 1996, EPA conducted several performance audits of
calibration gases from various manufacturers. These audits had two
goals, to provide a quality check for gas vendors and to connect users
with gas vendors. One notable result in the most recent five
consecutive years of audits is a steady, significant reduction in
failure rate of the calibration gases, from about 27% in 1992 down to
5% in 1996. In 2003, EPA conducted a ``surprise'' audit of 14 national
specialty gas producers and found that the failure rate had risen to 11%.
Today's proposed rule would require that EPA Protocol Gases being
used for 40 CFR Part 75 purposes be obtained from those specialty gas
producers who participate in the audit program. Under the proposed
rule, only audit participants may market these gas standards as ``EPA
Protocol Gases'', although there will be no requirement for
participants' audited standards to meet an accuracy acceptance
criterion. The costs of the audits will be borne by the gas producers
who elect to participate in the audits. Although it may take several
years to revise all of the EPA monitoring regulations in 40 CFR Parts
58 and 60, today's proposed rule would ensure that under Part 75, any
specialty gas producers who do not participate in the program will not
have a price advantage (due to the lack of audit program costs) over
those producers who do participate. An EPA-maintained web site will
list the participants and the audit results, which will provide
calibration gas users with detailed information about the quality of
EPA Protocol Gases.
To clarify the calibration gas requirements in section 5.1 of
appendix A to this part, a definition for ``specialty gas producer''
has been added to section 72.2. EPA believes that most of the gas
standards and reference materials identified in section 5.1 of appendix
A of this part are expensive and not used in practice by Part 75
affected units. Therefore, today's proposed rule also deletes several
calibration gas options and definitions, and consolidates the remaining
calibration gas descriptions under section 5.1 of appendix A to this part.
EPA is also requesting comment on the appropriate accuracy
specification to apply to Hg cylinder gases and other Hg calibration
standards (e.g., gases from NIST-traceable generators). Currently, EPA
requires that accuracy of EPA Protocol gases be within 2 percent of the
certified tag values.
3. Requirements for Air Emission Testing Bodies
Since the inception of the Acid Rain Program, field audits of Part
75-affected facilities have brought to EPA's attention a number of
improperly-performed RATAs and other QA/QC tests. When the proper test
procedures are not followed, this can adversely affect the quality of
the emissions data, and, in some cases, may call into question a unit's
compliance with the requirement to hold allowances covering its
emissions. In view of this, today's proposed rule would revise Section
6.1 of Appendix A to require all individuals who perform the emission
tests and CEMS performance evaluations required by Part 75 to
demonstrate conformance with ASTM D7036-04 ``Standard Practice for
Competence of Air Emission Testing Bodies''. ASTM D7036-04 specifies
the general requirements for demonstrating
[[Page 49269]]
that an air emission testing body (AETB) is competent to perform
emission tests of stationary sources. ASTM D7036-04 covers testing and
calibration performed using standard methods, non-standard methods and
methods developed by the AETB.
Proposed Section 6.1.2 of Appendix A and revisions to Section 2.1
of Appendix E and to Section 1 of Appendix B would make it clear that
this requirement applies only to AETBs that perform RATAs,
NOX emission tests of Appendix E and LME units, or Hg
emission tests of low-emitting units. It would not be applicable to the
daily operation, daily QA/QC (daily calibration error check, daily flow
interference check, etc.), weekly QA/QC (i.e., Hg system integrity
checks), quarterly QA/QC (linearity checks, etc.), and routine
maintenance of the CEMS.
ASTM D7036-04 would be incorporated by reference in Sec.
75.6(a)(45), and a definition of ``Air Emission Testing Body'' would be
added to Sec. 72.2.
4. Linearity Requirements for Dual-Span Applications
Section 6.2 in Appendix A and Section 2.2 in Appendix B require the
owner or operator of affected units with installed gas monitors to
perform periodic linearity checks of the monitors. The basic linearity
check requirements are to perform the test for initial certification
and then, for ongoing quality assurance (QA), to repeat the test
quarterly. In the original Part 75 regulations (published on January
11, 1993), there were no exceptions to these requirements.
However, in May 1999, EPA revised the linearity check provisions of
Part 75 as follows. First, Section 6.2 of Appendix A was revised to
exempt SO2 and NOX span values of 30 ppm or less
from performing linearity checks. Second, revisions to Section 2.2 of
Appendix B reduced the ongoing linearity check requirement from once
per calendar quarter to once every ``QA operating quarter'' (i.e., a
calendar quarter in which the unit operates for at least 168 hours).
Since the May 1999 revisions became effective, the regulated
sources appear to have understood the ``QA operating quarter'' concept
in Section 2.2 of Appendix B, but there has been some confusion about
the meaning of the linearity exemption in Appendix A. Some have
questioned whether the linearity exemption applies only to ongoing QA
or whether it applies also to initial certification. Others have asked
whether the exemption applies only to a particular measurement range or
to all of the linearity check requirements for a monitoring system. The
misunderstanding appears to center around two sentences in Section 6.2.
The first sentence states that ``Notwithstanding these requirements, if
the SO2 or NOX span value for a particular range
is < = 30 ppm, that range is exempted from the linearity test
requirements of this part.'' Since the phrase ``of this part'' refers
to Part 75, this seems to exempt ranges of 30 ppm or less from all Part
75 linearity requirements, including initial certification and ongoing
QA. However, the second sentence states that ``For units using emission
controls and other units using both a high and a low span, perform a
linearity check on both the low- and high-scales for initial
certification.'' Thus, for dual span applications, this statement
appears to require linearity checks of both measurement scales for
initial certification regardless of the span values, which does not
harmonize with the 30 ppm exemption.
EPA believes that the key to understanding and reconciling these
rule texts is the chronological order of the two sentences. The second
sentence is from the original 1993 rule and the first sentence was
added in 1999. Therefore, the 30 ppm linearity check exemption in the
first sentence takes precedence over the low scale linearity check
requirement of the second, and there is no actual contradiction.
However, to eliminate any doubt as to the Agency's intended meaning,
today's rule would revise Section 6.2 of Appendix A to make it clear
that the 30 ppm linearity exemption: (1) Is range-specific; (2) covers
both initial certification and ongoing QA; (3) does not remove the
requirement to perform linearity checks of the high range (if > 30 ppm)
for dual span applications; and (4) does not take away the linearity
check requirements for the diluent monitor component of a
NOX-diluent monitoring system.
5. Dual Span Applications--Data Validation
Today's proposed rule would revise Sections 2.1.1.5 (b)(2) and
2.1.2.5(b)(2) of Appendix A to clarify the relationship between the
quality-assured (QA) status of the low and high ranges of a gas monitor
in a dual-span application. The changes would be consistent with the
proposed revisions to Appendix B (see Section II.I.3, below).
In the current rule, Sections 2.1.1.5(b)(2) and 2.1.2.5(b)(2) of
Appendix A provide instructions for reporting SO2 and
NOX concentration data when the full-scale range of the
monitor is exceeded. For single-range applications, a value of 200
percent of the maximum potential concentration (MPC) must be reported
when a full-scale exceedance occurs. For dual range applications, if
the low range is exceeded, no special reporting is necessary, provided
that the high range is ``available and not out-of-control or out-of-
service for any reason''. However, if the high range is ``not able to
provide quality-assured data'' during the low-range exceedance, then
the MPC must be reported.
EPA believes that for dual range applications, the two phrases used
to describe the QA status of the high range during low-scale
exceedances, i.e., ``available and not out-of-control or out-of-service
for any reason'' and ``not able to provide quality assured data'', are
too general and do not adequately address the possible scenarios
associated with dual range monitoring. Today's rule would revise these
rule texts by defining the QA status of the high range in terms of its
most recent calibration error and linearity checks. Provided that both
of these QA tests are still ``active'', i.e., their windows of data
validation have not expired, the high range would be considered in-
control and able to provide quality-assured data. However if either of
the tests has expired, data recorded on the high range would be
considered invalid until the expired test was repeated and passed. The
MPC would have to be reported until the expired high-range test is
redone or until the data return to the low scale.
These revisions would clarify that when the low range is up-to-date
on its QA tests but the high range is not, the QA statuses of the two
ranges are evaluated separately and may be different. However, as
explained in greater detail in Section II.I.3, below, the QA statuses
of the low and high ranges are not necessarily independent when a
calibration error test or a linearity check on one of the ranges is failed.
6. Cycle Time Test--Stability Criteria
The cycle time test described in Section 6.4 of Appendix A is
required for the initial certification and recertification of gas
monitoring systems, and occasionally as a diagnostic test. The
``upscale'' portion of the test consists of injecting a zero-level
calibration gas, allowing the reading to stabilize, recording it, and
then stopping the calibration gas flow, waiting until a stable reading
of the source emissions is obtained, and recording it. The ``downscale''
portion of the test is performed in like manner, except that a
[[Page 49270]]
high-level calibration gas is used instead of the zero-level gas.
Section 6.4 currently specifies criteria for determining when a
stable reading has been obtained. The reading is considered stable if
it changes by less than 2.0 percent of the span value for 2 minutes or
less than 6.0 percent from the average concentration over 6 minutes.
These criteria are reasonable when the source effluent concentrations
are moderate or high. However, when concentrations are very low, the
criteria are quite stringent and can be very difficult to meet. For
example, if the span value of a NOX analyzer is 10 ppm and
the average measured source emissions are 3 ppm, the source emissions
would have to remain constant within about 0.2 ppm for the specified
amount of time to meet the stability criteria.
In recent years, hundreds of new combustion turbines (CTs) have
been built. The vast majority are subject to Part 75, are equipped with
NOX monitoring systems, and have NOX permit
limits less than 10 ppm. Therefore, the 0.2 ppm cycle time stability
criterion in the example above is realistic and applies to many of
these new CTs. To provide a measure of relief for these low-emitting
sources, today's rule would add alternative stability criteria to
Section 6.4 of Appendix A. By the alternative criteria, an
SO2 or NOX reading would be considered stable if
it changed by no more than 0.5 ppm for 2 minutes or, for a diluent
monitor, if it changed by no more than 0.2% CO2 or
O2 for 2 minutes. EPA believes these alternative stability
criteria are needed to ensure that minor temporal variations in the
concentration of the source effluent do not cause testers to
overestimate the amount of time it takes to achieve stable readings,
resulting in ``false positive'' failures of the cycle time test.
7. System Integrity and Linearity Checks of Hg CEMS
Subpart I of Part 75 includes certification test procedures and
performance specifications for Hg CEMS. The required certification
tests for a Hg CEMS include a 3-level system integrity check, using a
NIST-traceable source of oxidized Hg and a 3-level linearity check,
using elemental Hg standards. The performance specification for the
system integrity check, which is found in paragraph (3)(iii) of
Appendix A, Section 3.2, states that the system measurement error must
not exceed 5.0 percent of the span value at any of the three
calibration gas levels. However no explanation of how to calculate the
measurement error is provided. Today's proposed rule would restructure
paragraph (3) of Section 3.2 (as described in the next paragraph) and
add the necessary mathematical procedure.
EPA is also proposing to make the linearity and system integrity
check specifications for Hg monitors the same. The principal linearity
error specification in Section 3.2(3)(i) is currently 10.0 percent of
the reference gas tag value at each calibration concentration, when
calculated according to Equation A-4. The alternative specification in
Section 3.2(3)(ii) allows an absolute difference of up to 1.0 [mu]g/
m\3\ between the average reference gas and monitor values at each
calibration gas level. Today's proposed rule would replace the
principal linearity error specification with a specification of 5.0
percent of the span value, and would lower the alternative
specification to 0.6 [mu]g/m\3\. Further, the same 0.6 [mu]g/m\3\
alternative specification would be added to the rule for the system
integrity check.
The reason for making these changes is that nearly all Hg monitors
are equipped with a converter and measure the total vapor phase Hg
(i.e., oxidized plus elemental) as elemental Hg. Therefore, the
performance specification for the linearity check, which is done with
elemental Hg, should be at least as stringent as the performance for
the system integrity check, which is done with oxidized Hg. Because the
current linearity specifications are less stringent than the
specification for the system integrity check, EPA proposes to revise
and restructure paragraph (3) in Section 3.2 of Appendix A, to make the
performance specifications the same for linearity checks and system
integrity checks of Part 75 Hg monitors (this includes both the 3-level
and single-level system integrity checks). The alternative performance
specification is deemed necessary for low (10 [mu]g/m\3\ Hg span values,
where the principal specification of 5.0% of span may be overly stringent.
8. Correction of Hg Calibration Gas Concentrations for Moisture
When calibration error tests and linearity checks of
SO2, NOX, and diluent gas monitors are performed,
EPA protocol gases are used. The protocol gases are essentially
moisture-free. However, when mercury monitors are calibrated, moisture
may be added to the calibration gas. This creates a potential source of
error in the calculations, if the Hg monitoring system measures on a
dry basis. In view of this, EPA proposes to revise the calibration
error procedures in section 6.3.1 of Appendix A, to require that when
moisture is added to the Hg calibration gas, the moisture content of
the gas must be accounted for if the Hg monitor measures on a dry
basis. The proposed revisions would also require the calibration gas
concentration to be converted to a dry basis for purposes of the
calibration error calculations.
Parallel language would be added to Section 6.2 of Appendix A, in a
new paragraph ``(h)'', to address this issue for the linearity checks
and system integrity checks of Hg monitors. The Agency believes that
adoption of these proposed revisions will prevent many ``false
positive'' failures of Hg monitor calibration error tests, linearity
checks, and system integrity checks.
9. Correction of Cross-References
Today's proposed rule would correct a number of cross-references in
Appendix A, Sections 6.2(g), 6.5.6(b)(3) and 6.5.6.3. Regarding the
system integrity checks of Hg monitors, Section 6.2(g) of Appendix A
incorrectly only refers to Section 2.6 of Appendix B, which only
describes weekly, single-level system integrity checks. The proposed
revisions would also refer to Sections 2.1.1 and 2.2.1 of Appendix B,
which describe the 3-level system integrity checks. Also, the
references in Sections 6.5.6(b)(3) and 6.5.6.3 of Appendix A to Section
3.2 of 40 CFR Part 60, Appendix B, Performance Specification No. 2
(PS2) are incorrect. The correct section number in PS2 is 8.1.3, not 3.2.
I. Appendix B
1. 3-Load Flow RATA Frequency and RATA Grace Period
On May 26, 1999, EPA revised Appendix B of Part 75, to reduce the
required frequency of 3-load flow RATAs from annually to ``at least
once every 5 consecutive calendar years''. However, as written, the
rule actually allows more than five years (20 calendar quarters) to
elapse between 3-load flow RATAs. For instance, if a 3-load flow RATA
was performed in the1st quarter of 2001 and the next one is done in the
4th quarter of 2006, the rule requirement would be met, but there would
be 23 calendar quarters between the successive tests.
In light of this, EPA is proposing to revise Section 2.3.1.3(c)(4)
of Appendix B, to require 3-load flow RATAs to be done at least once
every 20 calendar quarters. This is consistent with the other 5-year
testing requirements in Part 75, i.e., for Appendix E and LME units. It
is also consistent with the maximum
[[Page 49271]]
allowable interval between successive accuracy tests of Appendix D fuel
flowmeters.
EPA is also proposing to revise the RATA grace period provisions in
Section 2.3.3. In recent years many new combustion turbines have been
built and most of them have NOX-diluent CEMS. A great number
of these turbines have been operated infrequently due to the high price
of natural gas. Because of this, a unit may go for a very long period
of time without performing a RATA of the NOX monitoring
system because the unit seldom, if ever, has a ``QA operating quarter''
(so the extended deadline for the next RATA is often 8 calendar
quarters from the previous test), and then it may be several quarters
or even years before the allowable 720 operating hour grace period expires.
The grace period provisions in Section 2.3.3 were proposed in 1998
and promulgated in May 1999, before the influx of new, infrequently-
operated combustion turbines. Consequently, these rule provisions are
often very difficult to track and apply to such units. Therefore, EPA
proposes to modify the grace period methodology so that it is more
understandable and user-friendly, particularly in cases where a unit
seldom operates.
Today's proposal would move the requirements for determining the
deadline for the next RATA after a grace period test from paragraph (c)
of Section 2.3.3 to a new paragraph (d). Paragraph (c) currently
addresses both RATA deadlines and the data validation requirements for
the case where a RATA is not completed by the end of the 720 operating
hour grace period. Creating a new paragraph (d) would make Section
2.3.3 clearer, by treating the RATA deadline requirement as a distinct
and separate issue.
Proposed paragraph (d) would change the methodology for determining
RATA deadlines without changing the end result. The intent of Section
2.3.3 has always been for the source to return to its original RATA
schedule following a grace period test, in order to prevent the grace
period provisions from being abused. For instance, if the source did
not return to its original RATA schedule, the grace period could be
used to extend the interval between successive annual RATAs from four
QA operating quarters to five.
The current language in Section 2.3.3 works well enough for base
load units that operate most of the time. For these units, the grace
period almost invariably begins and ends within one calendar quarter of
the RATA deadline, making it easy to return to the original RATA
schedule. For instance, suppose that a base load unit is on a 2nd
quarter RATA schedule and a grace period RATA is done in the 3rd
quarter. If annual frequency is obtained, the deadline for the next
RATA is reckoned from the 2nd quarter, when the RATA was due, rather
than the 3rd quarter when the grace period test was actually done.
Therefore, the next RATA would be required in the 2nd quarter of the
following year, i.e., ``back on schedule''. However, for infrequently
operated combustion turbines, the grace period sometimes spans across
many calendar quarters, which effectively eliminates the possibility of
establishing a meaningful relationship between the original RATA due
date and the deadline for the next test.
In view of these considerations, EPA is proposing a simplified
methodology for determining RATA deadlines that will work for both base
load units and combustion turbines that seldom operate. The deadline
for the next RATA following a grace period test would be expressed as a
certain number of QA operating quarters after the quarter of the grace
period RATA, rather than referring back to the quarter in which the
RATA was originally due (which could have been several quarters in the
past).
The deadline for the next RATA would be determined by first
establishing whether the grace period RATA qualifies for the standard
(semiannual) RATA frequency or the reduced (annual) frequency. If the
grace period RATA does not qualify for the annual frequency, the
deadline for the next RATA would be simply set at two QA operating
quarters after the quarter of the grace period test. If the RATA
qualifies for the annual frequency then the deadline for the next RATA
would be set at three QA operating quarters after the quarter of the
grace period test. There would be one exception to these rules.
Regardless of the number of QA operating quarters that have elapsed
following the grace period test, the interval between a grace period
RATA and the deadline for the next required RATA could be no greater
than eight calendar quarters. This provision is consistent with Section
2.3.1.1(a) of Appendix B.
Finally, EPA is proposing to amend paragraph (c) of Section 2.3.3,
to clarify that when a RATA is performed after the expiration of a
grace period, the ``clock'' is reset, and the next RATA would simply be
due in two QA operating quarters (for semiannual frequency) or four QA
operating quarters (for annual frequency), not to exceed eight calendar
quarters.
EPA believes that the proposed revisions to Section 2.3.3 of
Appendix B would greatly simplify implementation of the grace period
provisions and would enhance the Agency's ability to track RATA
deadlines and to provide meaningful feedback to the affected sources.
2. RATA Requirement for Shared Components
Today's proposed rule would amend paragraph (g) in section 2.3.2 of
Appendix B to specify the consequences of a failed RATA, in the case
where a particular NOX pollutant concentration monitor is a
component of both a NOX concentration monitoring system and
a NOX-diluent monitoring system. An example would be a coal-
fired source that is subject to both the Acid Rain and NOX
Budget Programs, for which the owner or operator elects to use a
NOX concentration system to quantify NOX mass
emissions, while using the NOX-diluent system to satisfy the
Acid Rain Program requirement to monitor and report NOX
emission rate in lb/mmBtu. In such cases, if the NOX
concentration system RATA is failed, both the NOX
concentration monitoring system and the associated NOX-
diluent monitoring system would be considered out-of-control.
Successful RATAs of both monitoring systems would be required to get
them back in-control.
3. AETB Requirements
Appendix B would be further revised by adding a new Section, 1.1.4,
to require that an Air Emissions Testing Body (AETB) that performs
emission testing or RATAs for on-going quality-assurance under Part 75
must conform to ASTM D7036-04.
4. Calibration Error Tests and Linearity Checks--Dual Range Applications
Today's rule would revise Sections 2.1.1, 2.1.1.2, 2.1.5.1 and
2.2.3(e) of Appendix B, to clarify the data validation requirements for
daily calibration error tests and linearity checks of gas monitors when
two span values and two measurement ranges are required for a
particular parameter (e.g., SO2 or NOX).
Section 2.1.1 of Appendix B would be revised to require that
sufficient calibration error tests be performed on the low and high
monitor ranges to validate the data recorded on each range. The
provisions of Section 2.1.5 of Appendix B would be used to determine
whether ``sufficient'' calibration error tests have been done. A new
paragraph (3) would also be added to Section 2.1.5.1 of Appendix B to
clarify how the QA status of the low and high ranges is
[[Page 49272]]
determined when: (a) A calibration error test on one of the ranges is
failed; or (b) the most recent calibration error test of one of the
ranges has expired. In the case where separate analyzers are used for
the two ranges, a failed or expired calibration error test on one of
the ranges would not affect the QA status of the other range. For a
dual-range analyzer (i.e., a single analyzer with two scales), a failed
calibration error test on either range would result in an out-of-
control period, and data from the monitor would remain invalid until
corrective actions are taken, followed by successful ``hands-off''
calibrations of both ranges. However, if the most recent calibration
error test on one range of a dual-range analyzer was successful, but
its data validation window has expired, this would have no effect on
the QA status of the other range.
In the current rule, Section 2.2.3(e) in Appendix B states that
when linearity checks are performed on both scales of a dual-range
analyzer, an out-of-control period occurs if either of the two
linearity checks is failed or aborted due to a problem with the
monitor. However, it is not clear whether only one range or both ranges
must be retested to get back in-control. Today's rule would revise
Section 2.2.3(e) to require ``hands-off'' linearity checks of both
ranges of a dual-range analyzer whenever a linearity check on either
range is failed or aborted (unless, of course, a particular range is
exempted from linearity checks under Section 6.2 of Appendix A).
5. Off-Line Calibration Error Tests
Part 75 requires calibration error tests of all CEMS to be done
while the unit is combusting fuel (see Appendix B, Section 2.1.1 and
Appendix A, Sections 6.3.1 and 6.3.2). However, Section 2.1.1.2 of
Appendix B allows the owner or operator to make limited use of off-line
calibration error tests to validate data if an off-line calibration
demonstration test is performed and passed. If the off-line calibration
error demonstration is successful, then off-line calibrations may be
used to validate up to 26 unit operating hours of data before an on-
line calibration error test is required.
The off-line calibration provisions in Appendix B have not been
well-understood by many affected sources. Through the years, EPA has
received numerous requests for a more detailed explanation and/or
examples of how to apply these rule provisions. Today's rule would
revise Sections 2.1.1.2 and 2.1.5.1 of Appendix B to clarify the data
validation rules for off-line calibration error tests.
The Agency believes that main reason why there have been so many
questions about the use of off-line calibration error tests is that
paragraph (2) of Section 2.1.1.2 is not clear. Paragraph (2) states
that ``a successful on-line calibration error test of the monitoring
system must be completed no later than 26 unit operating hours after
each off-line calibration error test used for data validation.'' This
statement can be easily misinterpreted. It could be understood to mean
that a single off-line calibration error test can be used to validate
26 unit operating hours of data, regardless of the number of clock
hours it takes to accumulate the 26 unit operating hours. However, this
is not the intended meaning because it would directly contradict the
statement, in Section 2.1.5 of Appendix B, that the window of data
validation from a passed calibration error test extends for only 26
clock hours.
To clarify EPA's intent regarding the use of off-line calibration
error tests to validate CEM data, today's rule would revise Sections
2.1.1.2 and 2.1.5.1 of Appendix B. First, paragraph (2) in Section
2.1.1.2 would be revised to state that sources may make limited use of
off-line calibrations if the off-line calibration demonstration has
been performed and passed. Revised paragraph (2) of Section 2.1.5.1
would explain what ``limited use'' of off-line calibrations means. Off-
line calibrations could be used to validate up to 26 consecutive unit
operating hours of data before an on-line test is required. Each
individual off-line calibration would be valid only for 26 clock hours,
and if the sequence of consecutive operating hours validated by off-
line calibrations is broken before reaching the 26th consecutive unit
operating hour, data from the monitor would become invalid until an on-
line calibration is performed and passed. The sequence of consecutive
valid hours would be considered broken whenever a unit operating hour
is not contained within the 26 clock hour data validation window of a
passed off-line calibration error test.
6. Weekly System Integrity Check--Data Validation
For a Hg CEMS that is equipped with a converter and that uses
elemental Hg for daily calibrations, Section 2.6 of Part 75, Appendix B
requires a weekly system integrity check, using a NIST-traceable source
of oxidized Hg. This ``weekly'' test is required once every 168 unit
operating hours. However, Section 2.6 does not explain the consequences
of either failing the test or failing to perform the test on schedule.
Today's rule would add data validation rules for the weekly system
integrity check to Section 2.6 of Appendix B. If the test is failed, it
would trigger an out-of-control period until a subsequent system
integrity check is passed. Also, if the test is not performed within
168 unit operating hours of the previous successful system integrity
check, data from the CEMS would become invalid, starting with the 169th
unit operating hour and continuing until a system integrity check is
passed.
Today's rule would also correct a typographical error in Section
2.6 of Appendix B. The performance specification for the weekly system
integrity check is incorrectly referenced in the current rule as
Section 3.2 (c)(3) of Appendix A. The correct citation is Appendix A,
Section 3.2, paragraph (3)(iii).
7. Correction of Hg Units of Measure--Figure 2
Today's rule would correct a minor error in the units of measure
for Hg concentration in Figure 2 of Appendix B. The units of micrograms
per dry standard cubic meter ([mu]g/dscm) would be changed to
micrograms per standard cubic meter ([mu]g/scm). This change is
necessary because not all Hg monitoring systems measure Hg
concentration on a dry basis.
J. Appendix D
1. Update of Incorporation by Reference
As discussed in Section II.B.1of this preamble, EPA proposes to
update the list of test methods, sampling and analysis procedures, and
other items that are incorporated by reference in Part 75. As such,
this proposal also includes the necessary updates to the references in
Appendix D.
EPA is also proposing to add to Section 2.1.5.1 of Appendix D, the
American Petroleum Institute's (API) Manual of Petroleum Measurement
Standards Chapter 22--Testing Protocol: Section 2--Differential
Pressure Flow Measurement Devices (First Edition, August 2005) as a new
standard procedure for verifying flowmeter accuracy.
2. Pipeline Natural Gas--Method of Qualification and Monthly GCV Values
For a unit which combusts a fuel that meets the definition of
``pipeline natural gas'' (PNG) in Sec. 72.2, Section 2.3.1.1 of
Appendix D allows the owner or operator to estimate the unit's
SO2 mass emissions using a default SO2 emission
rate of 0.0006 lb/mmBtu. To qualify to use this SO2 emission
rate, the owner or operator must document in the
[[Page 49273]]
monitoring plan for the unit that the natural gas has a total sulfur
content of 0.5 grains per 100 standard cubic foot or less. Section
2.3.1.4 describes three ways to initially demonstrate that the gas
meets this total sulfur requirement: (1) Based on the gas quality
characteristics specified in a purchase contract, tariff sheet, or
pipeline transportation contract; or (2) based on historical fuel
sampling data from the previous 12 months; or (3) based on at least one
representative sample of the gas, if the requirements of (1) or (2)
cannot be met. When fuel sampling data are used to qualify, each
individual sample result must meet the total sulfur limit. Once a fuel
has qualified as pipeline natural gas, Section 2.3.1.4(e) of Appendix D
requires annual sampling of the total sulfur content to demonstrate
that the fuel still meets the definition of PNG. At least one sample
per year must be taken and if multiple samples are taken, each one must
meet the 0.5 gr/100 scf total sulfur limit.
The criteria for documenting the total sulfur content of PNG were
promulgated on June 12, 2002, and the annual total sulfur requirement
became effective on January 1, 2003. Since then, EPA has learned that
many suppliers of natural gas regularly sample the total sulfur content
of the gas (in many cases, daily) and will provide that data to their
customers upon request. Sources desiring to use this data to meet the
initial or ongoing total sulfur sampling requirements of Appendix D
have approached EPA, asking whether the gas would be disqualified from
using the 0.0006 lb/mmBtu SO2 emission rate if the total
sulfur content of one of these daily samples exceeded 0.5 gr/100 scf.
Thus far, the Agency has addressed these requests on a case-by-case
basis. Generally, in cases where the number of total sulfur samples far
exceeds the requirements of Appendix D, EPA has allowed the sources to
reduce the data to monthly averages. Then, if all of the monthly
averages are below the 0.5 gr/100 scf , the fuel would be allowed to
continue using the 0.0006 lb/mmBtu default SO2 emission rate.
EPA believes that the current rule requirements for documenting the
sulfur content of pipeline natural gas are too restrictive and need to
be revised. For example, a source that takes only one or perhaps a
handful of sulfur samples each year is allowed to use the 0.0006 lb/
mmBtu default emission rate without question if all samples have < = 0.5
gr/100 scf of total sulfur. However, a source with hundreds of total
sulfur sample results could possibly be disqualified from using the
default emission rate if one sample exceeded the 0.5 gr/100 scf limit.
To correct this inequitable situation, today's rule would revise
Sections 2.3.1.4(a)(2) and (e) of Appendix D.
For the initial documentation that the gas meets the 0.5 gr/100 scf
total sulfur limit, proposed Section 2.3.1.4(a)(2) would allow sources
whose fuel suppliers have provided them with at least 100 daily (or
more frequent) total sulfur samples from the previous 12 months to
reduce the data to monthly averages. If all monthly averages meet the
0.5 gr/100 scf limit, the fuel would qualify as pipeline natural gas,
and the source could use the 0.0006 lb/mmBtu default SO2
emission rate. Alternatively, if at least 98 percent of the 100 (or
more) samples have a total sulfur content of 0.5 gr/100 scf or less,
the fuel would qualify as pipeline natural gas.
The revisions to Section 2.3.1.4(e) would allow this same
calculation methodology to be used for the annual total sulfur sampling
requirement. That is, each year, if at least 100 total sulfur samples
from the past 12 months are provided by the fuel supplier, the data
could either be reduced to monthly averages, or the percentage of the
samples that meet the 0.5 gr/100 scf limit could be determined.
EPA is also proposing to clarify the GCV sampling requirements for
pipeline natural gas in Section 2.3.4.1 of Appendix D. The current rule
requires monthly GCV sampling for PNG. However, Section 2.3.4.1 refers
only to the ``monthly sample'' (singular), whereas affected sources may
collect and analyze multiple GCV samples each month, or may receive the
results of multiple GCV samples from the fuel supplier each month. In
view of this, revised Section 2.3.4.1 would require that a monthly
average GCV value be used for Part 75 reporting, for any month in which
multiple samples are taken and analyzed. To implement this provision,
whenever Section 2.3.7(c) of Appendix D requires the results of a
monthly GCV sample to be applied ``starting from the date on which the
sample was taken'', the owner or operator would apply the monthly
average GCV value, starting from the latest date of any of the
individual GCV samples used to calculate the monthly average. EPA
believes that monthly averaging of the available GCV samples will
ensure that representative robust GCV values are used in the Appendix D
heat input calculations.
3. Requirement To Split Oil Samples
For affected units that combust fuel oil and use the Appendix D
``excepted'' methodology to quantify SO2 mass emissions and/
or unit heat input, Section 2.2 of Appendix D requires the owner or
operator to perform periodic sampling of the sulfur content, gross
calorific value and (if necessary) density of the oil. There are four
basic oil sampling options described in Section 2.2: (a) Daily
sampling; (b) flow proportional sampling (composite sample, up to 7
days); (c) sampling from a unit's storage tank after each addition of
oil to the tank; and (d) sampling of each fuel lot (either upon receipt
of the lot or sampling from supplier's storage tank prior to delivery).
Regardless of which sampling option is selected, Section 2.2.5 of
Appendix D requires each oil sample to be split and a portion (at least
200 cc) of it to be maintained for at least 90 days after the end of
the allowance accounting period.
The requirement to split and maintain a portion of each oil sample
has been in Appendix D since it was first promulgated on January 11,
1993. At that time, on-site fuel oil sampling was required on every day
that the unit combusted oil. Later, on May 17, 1995, an option to
sample each shipment upon delivery was added for diesel fuel. Then, on
May 26, 1999, the four basic oil sampling options in the current rule
were put in place. However, the requirement to split and maintain a
portion of each sample has remained unchanged through all of these
rulemakings.
EPA believes that the requirement to split and maintain oil samples
should only apply to samples that are taken at the affected facility.
Today's rule would revise Section 2.2.5 of Appendix D to limit this
requirement to samples that are taken on-site. Therefore, sources using
the fourth sampling option in Section 2.2 of Appendix D, i.e., sampling
from each fuel lot, would no longer be required to split and maintain
oil samples in the case where the samples are taken off-site, from the
fuel supplier's storage container.
K. Appendix E
1. AETB Requirements
EPA proposes to revise Section 2.1 of Appendix E to require that
any Air Emissions Testing Body (AETB) performing emission measurements
to develop an Appendix E correlation curve or to derive a default
emission rate for an LME unit, would have to conform to ASTM D7036-04.
2. Reporting Data When the Correlation Curve Expires
For oil and gas-fired peaking units using the Appendix E
``excepted'' methodology to estimate NOX emissions, the
owner or operator is
[[Page 49274]]
required, for each fuel type, to perform four-load emission testing for
initial certification in order to develop a correlation curve of
NOX emission rate versus heat input rate. Each correlation
curve is programmed into the data acquisition and handling system
(DAHS), and retesting is required every five years (20 calendar
quarters) to develop a new curve.
If the 20 calendar quarter test deadline passes without a retest
having been performed, the previous correlation curve expires and is no
longer valid. Ordinarily, when data from a Part 75 monitoring system
become invalid, missing data substitution procedures are applied.
Section 2.5 of Appendix E contains missing data provisions that address
the following situations: (a) When the monitored QA parameters are
unavailable or invalid; (b) when the measured heat input rate is higher
than the highest heat input rate on the correlation curve; (c) when
NOX emission controls are either not operating or not
documented to be working properly; and (d) when emergency fuel is burned.
Conspicuously absent from Section 2.5 is a missing data procedure
to follow when a correlation curve expires. To address this deficiency,
today's rule would add a new Section, 2.5.2.4, to Appendix E, requiring
the fuel-specific maximum potential NOX emission rate (MER)
to be reported when a baseline correlation curve expires. The MER would
continue to be reported until a new correlation curve is generated.
L. Appendix F
1. NOX Mass Calculations
EPA proposes to revise the manner in which NOX mass data
are collected under the XML-EDR format that will be required in 2009 as
part of EPA's effort to re-engineer the Agency's data collection
systems. Under the current reporting requirements, sources are required
to report hourly NOX mass emissions (lb) and then to sum
these hourly records and divide by 2000 lb/ton to determine the
quarterly NOX mass emissions (tons). This is inconsistent
with the manner in which SO2 and CO2 mass
emissions data are reported and aggregated. For SO2 and
CO2, the hourly values are reported as mass emission rates
(lb/hr). The quarterly cumulative mass emissions are calculated by
multiplying each reported hourly mass emission rate by the
corresponding unit or stack operating time, summing these products, and
then dividing the sum by 2000 lb/ton to get tons of SO2 or
CO2.
Today's proposed rule seeks to harmonize the reporting formats by
requiring the reporting of hourly NOX mass emission rate
(lb/hr) instead of hourly NOX mass emission (lb), when the
source transition from the current EDR reporting format to the XML-EDR
reporting format. As previously discussed, sources may use either the
existing EDR format or the new XML-EDR reporting format in 2008, but
will be required to use the new XML-reporting format, only, in 2009.
Requiring the reporting of hourly NOX mass emission rate
(lb/hr) necessitates the modification of Equations F-24, and F-27 in
Appendix F of Part 75 and the removal of Equation F-26. However, since
the current EDR reporting format will continue to be supported through
2008, EPA must retain these equations in the rule until the transition
to XML-EDR is complete. Therefore, EPA is proposing to revise Section 8
of Appendix F, by adding Equation F-24a for the reporting of hourly
NOX mass emission rate (lb/hr). Equation F-24a is a modified
version of F-24, in which the operating time variable is removed. The
use of Equation F-24a would be mandatory in the new XML-EDR format.
Likewise, Equation F-27a would be added, which is a modified form of
Equation F-27 that includes the operating time variable. In the XML-EDR
format, cumulative NOX mass emissions would be calculated
using Equation F-27a.
Since both EDR reporting formats currently in use (i.e., EDR
versions 2.1 and 2.2) require reporting of hourly NOX mass
emissions (lb), the current versions of Equations F-24 and F-27 would
remain in the rule. However, these equations would no longer be
applicable in 2009, when the use of XML-EDR format is required for all
affected sources.
Today's proposal also would revise Section 8.2 of Appendix F, by
splitting it into two subsections, 8.2.1 and 8.2.2. Section 8.2 of the
current rule describes a procedure for calculating the NOX
mass emission rate in lb/hr, when NOX mass emissions are
determined using a NOX concentration monitoring system and a
flow monitor. Section 8.2 cross-references other parts of the rule,
rather than showing the actual equations used. Today's proposed rule
would add Equation F-26a to proposed subsection 8.2.1 and Equation F-
26b to proposed subsection 8.2.2, clearly showing how the
NOX mass emission rate is calculated on a wet and dry basis.
Equation F-26 in Section 8.3 would be re-numbered as Equation F-26c.
Proposed Equations F-26a and F-26b are currently used by sources to
calculate NOX mass emissions under Subpart H of Part 75.
These equations are represented in the EDR reporting instructions, as
Equations N-1 and N-2 respectively. EPA believes that it is appropriate
to add these equations to the rule at this time.
2. Use of the Diluent Cap
Today's proposed rule would restrict the use of the diluent cap to
NOX emission rate calculations. The original purpose for
implementing the diluent cap was to keep calculated NOX
emission rates from approaching infinity during periods of unit startup
and shutdown, where the diluent gas (CO2 or O2)
concentration is close to the level in the ambient air. However, the
current rule allows the diluent cap to be used for heat input rate
calculations, CO2 mass emission calculations, and
calculation of hourly CO2 concentration from measured
O2 concentrations, in addition to being used for
NOX emission rate. Sources are also allowed to use the cap
value for some of these calculations and not others. This greatly
complicates the data collection process. EPA has also found that using
the diluent cap for other parameters besides NOX emission
rate always leads to over-reporting of these parameters, which is
clearly contrary to the intended purpose of the diluent cap. Therefore,
today's proposed rule would remove all of the references in Sections 4
and 5 of Appendix F which allow the diluent cap to be used for other
parameters besides NOX emission rate
3. Negative Emission Values
EPA proposes to provide special reporting instructions to account
for situations where the equations prescribed by the rule yield
negative values. First, when Equation 19-3 or 19-5 (from EPA Method 19
in 40 CFR Part 60, Appendix A) is used to calculate NOX
emission rate, modified forms of these equations, designated as
Equations 19-3D and 19-5D, would be used whenever the diluent cap is
applied. Second, for any hour where Equation F-14b results in a
negative hourly average CO2 value, EPA proposes to require
0.0% CO2 to be reported as the average CO2 value
for that hour. Third, EPA proposes to require a default heat input rate
value of 1 mmBtu/hr to be reported for any hour in which Equation F-17
results in a negative hourly heat input rate. These changes would be
accomplished by modifying Sections, 3.3.4, 4.4.1, and 5.2.3 of Appendix F.
[[Page 49275]]
4. Calculation of Stack Gas Moisture Content
Today's proposed rule would add Equation F-31 to a new Section 10
of Appendix F. This equation is used to calculate stack gas moisture
values from wet and dry oxygen measurements, as described in Appendix
A, Section 6.5.7(a). The equation is currently represented in the EDR
reporting instructions as Equation M-1.
5. Site-Specific F-Factors (Single Fuel)
For units that use CEMS to measure the NOX emission rate
in lb/mmBtu and/or the unit heat input rate in mmBtu/hr, an equation
from Appendix F of Part 75 or from Method 19 of 40 CFR Part 60 is
required to convert the raw CEMS data into the proper units of measure.
Each of these equations contains an F-factor, which represents either
the total volume of flue gas or the volume of CO2 generated
per million Btu of heat input. The F-factor is fuel-specific.
Sections 3.3.5 and 3.3.6 of Appendix F allow the owner or operator
to use either a default F-factor from Table 1 in Appendix F, or use
Equation F-7a or F-7b in Appendix F to calculate a site-specific F-
factor, based on the composition of the fuel. However, Appendix F
neither specifies how much fuel sampling data is required to develop a
site-specific F-factor, nor how often the F-factor must be updated.
To address this issue, today's rule would revise the introductory
text of Appendix F, Section 3.3.6 to require each site-specific F-
factor to be based on a minimum of 9 samples of the fuel. Fuel samples
taken during the 9 runs of an annual RATA would be acceptable for this
purpose. Further, re-determination of the F-factor would be required at
least annually, and the value from the most recent determination would
be used in the emission calculations.
6. Prorated F-Factors
For affected units that co-fire combinations of fossil fuels or
fossil fuels and wood residue and that use CEMS to monitor the
NOX emission rate or unit heat input rate, Section 3.3.6.4
of Appendix F requires a prorated F-factor to be used in the emission
calculations. The prorated F-factor is calculated using Equation F-8 in
Appendix F. In applying Equation F-8, the F-factor for each type of
fuel is weighted according to the fraction of the total heat input
contributed by the fuel. However, Equation F-8 fails to specify how the
total unit heat input and the fraction of the heat input contributed by
each fuel are determined. Data from the CEMS cannot be used for this
purpose because the prorated F-factor must be known before the unit
heat input rate can be calculated.
Through the years, in response to inquiries about this, EPA has
advised sources to use the best available auxiliary process data, such
as fuel feed rates and measured GCV values, to provide heat input
estimates for calculating the prorated F-factor, but no official Agency
policy guidance has been issued. To correct this situation, today's
rule would revise the definition of ``Xi'' (the fraction of
the total heat input derived from each fuel) in the Equation F-8
nomenclature. The revised definition would require sources to determine
Xi from the best available information on the quantity of
each fuel combusted and its GCV value over a specified time period. The
value of Xi would be updated periodically, either hourly,
daily, weekly, or monthly, and the prorated F-factor used in the
emission calculations would be derived from the Xi values
from the most recent update. The owner or operator would be required to
document in the hard copy portion of the monitoring plan the method
used to determine the Xi values.
7. Default F-Factors
EPA proposes to add default F-factors for petroleum coke and tire
derived fuels to Table 1 in Section 3.3.5 of Appendix F. The proposed
values are 9,832 dscf/mmBtu for Fd and 1,853 scf
CO2/mmBtu for Fc for petroleum coke and 10,261
dscf/mmBtu for Fd and 1,803 scf CO2/mmBtu for
Fc for tire derived fuels. These F-factors are needed
because petroleum coke and tires are being used as a fuel by a number
of units. EPA is also proposing 9,819 dscf/mmBtu for Fd and
1,840 scf CO2/mmBtu for Fc as F-factors for sub-
bituminous coal. These F-factors were calculated using Part 75,
Appendix F, Equations F-7a and F-7b and representative composition and
gross calorific value (GCV) data for each fuel.
8. Revisions to Equation F-23
Consistent with the proposed changes to Sec. 75.11(e), expanding
the applicability of Equation F-23 (which are discussed in detail in
Section II.B.4 of this preamble), modifications would be made to
Section 7 of Appendix F (introductory text), and to the Equation F-23
nomenclature.
M. Appendix G
Consistent with the changes to other parts of the rule, EPA
proposes to update the current ASTM standards listed in Sections 2.1.2,
2.2.1, and 2.2.2, of Appendix G, citing the newer versions.
N. Appendix K
Today's proposed rule addresses several issues regarding the use of
sorbent trap monitoring systems for the measurement and reporting of Hg
mass emissions. When this monitoring option is selected, the current
rule requires the use of paired sorbent traps to measure the effluent
Hg concentration. If the two Hg concentrations measured by the paired
traps meet the required relative deviation (RD) specification in
Appendix K of Part 75, and if each trap individually meets certain
other QA requirements of Appendix K, then the two Hg concentrations are
averaged arithmetically and the average value is used to determine the
Hg mass emissions in each hour of the data collection period. However,
in cases where either or both of the traps fails to meet the acceptance
criteria, Sec. 75.15(h) and Table K-1 of Appendix K specify
consequences of varying severity. As discussed in the following
paragraphs, EPA has reconsidered these rule provisions and has
concluded that some of the consequences are too lenient while others
are unnecessarily harsh. The Agency is therefore proposing to revise
them to make them more consistent and equitable.
Section 75.15(h) currently provides a measure of relief to the
affected sources whenever one of the paired traps is accidentally lost,
damaged, or broken and cannot be analyzed. In such cases, the owner or
operator is allowed to use the remaining trap to determine the Hg
concentration for the data collection period, provided that the
remaining trap meets all of the QA requirements of Appendix K. But the
rule does not require any adjustment of the data to compensate for the
loss of one of the samples. In view of this, EPA is proposing to revise
Sec. 75.15(h) to require that the Hg concentration measured by the
remaining valid trap be multiplied by a ``single trap adjustment
factor'' (STAF) of 1.222. The STAF represents the maximum amount by
which the Hg concentration from the lost, damaged or broken trap could
have exceeded the concentration measured by the valid trap and still
met the 10% RD specification.
The Agency is also proposing to revise Table K-1 in Appendix K, to
extend the use of the STAF to cases where one of the paired sorbent
traps either: (a) Fails a post-test leak check; (b) has excessive
breakthrough in the second section; or (c) is unable to meet the
required percent recovery of the third section elemental Hg spike. In all
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three of these cases, provided that the other trap meets all Appendix K
requirements, rather than invalidating the sorbent trap system data for
the entire collection period, the Hg concentration measured by the
valid trap, multiplied by the STAF, could be used for Part 75 reporting.
Section 7.2.3 of Appendix K requires that for each hour of the data
collection period, the ratio of the stack gas flow rate to the sample
flow rate through each sorbent trap must be maintained within 25
percent of the initial ratio established in the first hour of the data
collection period. However, the current rule does not say what to do if
this criterion is not met. Rather, Table K-1 indicates that the
appropriate consequences are to be determined on a ``case-by-case''
basis. EPA has reconsidered this approach and is proposing to revise
it, because it opens the door to inconsistent application of the
sorbent trap monitoring methodology. Therefore, Table K-1 would be
revised to specify that a sample is invalidated if either: (a) More
than 5 percent of the hourly ratios; or (b) more than 5 hourly ratios
in the data collection period (whichever is less restrictive) fail to
meet the ±25 percent acceptance criterion. Further, if only
one of the paired traps is able to meet the specification, provided
that it also meets the rest of the Appendix K QA criteria, the valid
trap could be used for Part 75 reporting, if the single trap adjustment
factor of 1.222 is applied to the measured Hg concentration.
Appendix K currently requires that the data from a sorbent trap
monitoring system be invalidated whenever the relative deviation
between the Hg concentrations measured by the paired traps is greater
than 10 percent. EPA proposes to revise this requirement, to allow
sources to report the higher of the two Hg concentrations measured by a
pair of sorbent traps whenever the RD specification is not met, rather
than invalidating the sorbent trap system data for the entire
collection period. EPA is also proposing, for consistency with the
proposed changes Sec. 75.22(a) (which are discussed in Section II.C.3
of this preamble), to revise Table K-1 to include an alternative
relative deviation specification of 20 percent for paired sorbent
traps, where low effluent concentrations of Hg (< = 1 [mu]g/
m3) are encountered.
Today's proposed rule would add two new paragraphs, (k) and (l), to
Sec. 75.15. Proposed Sec. 75.15(k) would require that whenever the
RATA of a sorbent trap system is performed, the sorbent traps used to
collect the RATA run data must be the same size as the traps used for
daily operation of the monitoring system. Likewise, the sorbent
material must be the same type that is used for daily operation.
Proposed Sec. 75.15(l) would require a diagnostic RATA of the sorbent
trap system whenever the size of the sorbent traps or the type of
sorbent material is changed. Data from the modified sorbent trap system
would not be acceptable for Part 75 reporting until the RATA is passed,
with one exception, i.e., data collected during a successful diagnostic
RATA test period could be reported as quality-assured. EPA is proposing
to add these requirements because the relative accuracy and bias of a
sorbent trap monitoring system are dependent upon both the trap design
and the type of sorbent material used.
Finally, today's proposed rule would revise section 7.2.3 of
Appendix K to require that the sample flow rate through a sorbent trap
monitoring system must be zero when the unit is not operating. This
clarification is needed to prevent the system from sampling ambient air
during periods when the combustion unit is off-line. Sampling ambient
air when the unit is not in operation would artificially lower the Hg
concentrations measured by the sorbent traps, resulting in under-
reporting of Hg mass emissions.
II. Administrative Requirements
A. Executive Order 12866--Regulatory Planning and Review
This action is not a ``significant regulatory action'' under the
terms of Executive Order (EO) 12866 (58 FR 51735, October 4, 1993) and
is therefore not subject to review under the EO.
B. Paperwork Reduction Act
The information collection requirements in the proposed rule have
been submitted for approval to OMB under the Paperwork Reduction Act,
44 U.S.C. 3501 et seq. The Information Collection Request (ICR)
document prepared by EPA has been assigned EPA ICR number 2203.01. The
information requirements are based on the proposed revisions to the
monitoring, recordkeeping, and reporting requirements in 40 CFR Part
75, which are mandatory for all sources subject to the Acid Rain
Program under Title IV of the Clean Air Act and certain other emissions
trading programs administered by EPA. All information submitted to EPA
pursuant to the recordkeeping and reporting requirements for which a
claim of confidentiality is made is safeguarded according to Agency
policies set forth in 40 CFR Part 2, subpart B. The existing Part 75
rule requirements are covered by existing ICRs for the Acid Rain
Program (EPA ICR number 1633.13; OMB control number 2060-0258), the
NOX SIP Call (EPA ICR number 1857.03; OMB number 2060-0445),
and the Clean Air Interstate Rule (EPA ICR number 2152.01). The
separate ICR for the proposed rule revisions addresses the one time
costs necessary for sources to review the rule revisions and adapt
their recordkeeping and reporting systems to the revised requirements.
The EPA believes that the long term implications of the proposed rule
revisions will be to reduce the ongoing burdens and costs associated
with Part 75 compliance, but those impacts will be addressed as EPA
renews the individual program ICRs. The annual monitoring, reporting,
and recordkeeping burden for this collection (averaged over the first 3
years after the effective date of the final rule) is estimated to be
124,976 labor hours per year at a total annual cost of $8,581,420. This
estimate includes burdens for rule review, recordkeeping and reporting
software upgrades, and software debugging activities, as well as the
capital costs of upgrading recordkeeping and reporting software.
Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a Federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of information;
and transmit or otherwise disclose the information. An Agency may not
conduct or sponsor, and a person is not required to respond to a
collection of information unless it displays a currently valid OMB
control number. The OMB control numbers for EPA's regulations in 40 CFR
are listed in 40 CFR Part 9.
To comment on the Agency's need for this information, the accuracy
of the provided burden estimates, and any suggested methods for
minimizing respondent burden, including the use of automated collection
techniques, EPA has established a public docket for this rule, which
includes this ICR, under Docket ID number OAR-2005-0132. Submit any
comments related to the ICR for this proposed rule to EPA and OMB.
[[Page 49277]]
See Addresses section at the beginning of this notice for where to
submit comments to EPA. Send comments to OMB at the Office of
Information and Regulatory Affairs, Office of Management and Budget,
725 17th Street, NW., Washington, DC 20503, Attention: Desk Office for
EPA. Since OMB is required to make a decision concerning the ICR
between 30 and 60 days after August 22, 2006, a comment to OMB is best
assured of having its full effect if OMB receives it by September 21,
2006. The final rule will respond to any OMB or public comments on the
information collection requirements contained in this proposal.
C. Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
For purposes of assessing the impacts of today's proposed rule on
small entities, small entity is defined as: (1) A small business as
defined by the Small Business Administration's (SBA) regulations at 13
CFR 121.201; (2) a small governmental jurisdiction that is a government
of a city, county, town, school district or special district with a
population of less than 50,000; or (3) a small organization that is any
not-for-profit enterprise which is independently owned and operated and
is not dominant in its field.
After considering the economic impacts of today's proposed rule on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. In
determining whether a rule has a significant economic impact on small
entities, the impact of concern is any significant adverse economic
impact on small entities, since the primary purpose of the regulatory
flexibility analysis is to identify and address regulatory alternatives
``which minimize any significant economic impact of the rule on small
entities.'' 5 U.S.C. 603 and 604. Thus, an agency may certify that a
rule will not have a significant economic impact on a substantial
number of small entities if the rule relieves regulatory burden or
otherwise has a positive economic effect on all of the small entities
subject to the rule. The proposed rule revisions represent minor
changes to existing monitoring requirements used in EPA emission
trading programs. Although there will be some small level of up front
costs to reprogram existing electronic data reporting software used
under this program, the long term effects of these proposed revisions
is to allow continued efficient electronic data submittals that should
act to relieve some of the long term reporting burdens for affected
sources, which include some small entities.
We continue to be interested in the potential impacts of the
proposed rule on small entities and welcome comments on issues related
to such impacts.
D. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under Section 202 of the UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures to State, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million or more in any
one year. Before promulgating an EPA rule for which a written statement
is needed, Section 205 of the UMRA generally requires EPA to identify
and consider a reasonable number of regulatory alternatives and adopt
the least costly, most cost-effective, or least burdensome alternative
that achieves the objectives of the rule. The provisions of Section 205
do not apply when they are inconsistent with applicable law. Moreover,
Section 205 allows EPA to adopt an alternative other than the least
costly, most cost-effective, or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted. Before EPA establishes any regulatory
requirements that may significantly or uniquely affect small
governments, including tribal governments, it must have developed under
Section 203 of the UMRA a small government agency plan. The plan must
provide for notifying potentially affected small governments, enabling
officials of affected small governments to have meaningful and timely
input in the development of EPA regulatory proposals with significant
Federal intergovernmental mandates, and informing, educating, and
advising small governments on compliance with the regulatory requirements.
EPA has determined that this proposed rule does not contain a
Federal mandate that may result in expenditures of $100 million or more
for State, local, and tribal governments, in the aggregate, or in the
private sector in any one year. Thus, today's proposed rule is not
subject to the requirements of Sections 202 and 205 of the UMRA.
EPA has determined that this rule contains no regulatory
requirements that might significantly or uniquely affect small
governments. The revisions primarily would make certain changes EPA has
determined are necessary as part of upgrading the data systems used to
manage data submitted under the program and to streamline the methods
for sources to report their information. The revisions also would
clarify certain issues that have been raised during ongoing
implementation of the existing rule and would update the information on
various voluntary consensus standards incorporated by reference in the
rule. Some States do have programs that rely on the monitoring
provisions in 40 CFR Part 75, and States may incur some costs
associated with reviewing the proposed modifications to Part 75, but
the rule revisions and the impact on the States would not be significant.
E. Executive Order 13132--Federalism
Executive Order 13132, entitled ``Federalism'' (64 FR 43255, August
10, 1999), requires EPA to develop an accountable process to ensure
``meaningful and timely input by State and local officials in the
development of regulatory policies that have federalism implications.''
``Policies that have federalism implications'' is defined in the
Executive Order to include regulations that have ``substantial direct
effects on the States, on the relationship between the national
government and the States, or on the distribution of power and
responsibilities among the various levels of government.''
This proposed rule does not have federalism implications. This
proposed rule will not have substantial direct effects on the States,
on the relationship between the national government and the States, or
on the distribution of power and responsibilities among the various
levels of government, as specified in Executive Order 13132. These
proposed rule revisions represent minor adjustments to existing
regulations. The revisions primarily would make certain changes EPA has
determined are necessary as part of upgrading the data systems used to
manage data submitted under the program and to streamline the methods
for sources to report their information. The revisions also would
clarify certain
[[Page 49278]]
issues that have been raised during ongoing implementation of the
existing rule and would update the information on various voluntary
consensus standards incorporated by reference in the rule. Some States
do have programs that rely on the monitoring provisions in 40 CFR Part
75, and States may incur some costs associated with reviewing the
proposed modifications to Part 75, but the rule revisions and the
impact on the States would not be significant. Thus, Executive Order
13132 does not apply to this proposed rule. In the spirit of Executive
Order 13132, and consistent with EPA policy to promote communications
between EPA and State and local governments, EPA specifically solicits
comment on this proposed rule from State and local officials.
F. Executive Order 13175--Consultation and Coordination With Indian
Tribal Governments
Executive Order 13175, entitled ``Consultation and Coordination
with Indian Tribal Governments'' (59 FR 22951, November 9, 2000),
requires EPA to develop an accountable process to ensure ``meaningful
and timely input by tribal officials in the development of regulatory
policies that have tribal implications.'' This proposed rule does not
have tribal implications, as specified in Executive Order 13175. The
proposed action makes minor revisions to existing rule requirements.
Thus, Executive Order 13175 does not apply to this proposed rule. The
EPA specifically solicits additional comment on the proposed rule from
tribal officials.
G. Executive Order 13045--Protection of Children From Environmental
Health and Safety Risks
Executive Order 13045, ``Protection of Children from Environmental
Health Risks and Safety Risks'' (62 FR 19885, April 23, 1997), applies
to any rule that: (1) Is ``economically significant'' as defined under
Executive Order 12866; and (2) concerns an environmental health or
safety risk that EPA has reason to believe may have a disproportionate
effect on children. If the regulatory action meets both criteria, the
Agency must evaluate the environmental health or safety effects of the
planned rule on children and explain why the planned regulation is
preferable to other potentially effective and reasonably feasible
alternatives considered by the Agency.
This proposed rule is not subject to the Executive Order because it
is not economically significant as defined in Executive Order 12866,
and because the Agency does not have reason to believe the proposed
revisions to certain monitoring and reporting requirements implicate
any environmental health or safety risks, including any specific risks
that present a disproportionate risk to children. The public is invited
to submit or identify peer-reviewed studies and data, of which the
agency may not be aware, that are relevant to the environmental health
or safety risks to children that could be implicated by this proposed
action.
H. Executive Order 13211--Actions That Significantly Affect Energy
Supply, Distribution, or Use
This proposed rule is not a ``significant energy action'' as
defined in Executive Order 13211, ``Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use'' (66 FR 28355,
May 22, 2001), because it is not likely to have a significant
adverse effect on the supply, distribution, or use of energy.
I. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (``NTTAA''), Public Law 104-113, 12(d) (15 U.S.C. 272
note), directs EPA to use voluntary consensus standards in its
regulatory activities unless to do so would be inconsistent with
applicable law or otherwise impractical.
Voluntary consensus standards are technical standards (e.g.,
materials specifications, test methods, sampling procedures, and
business practices) that are developed or adopted by voluntary
consensus standards bodies. The NTTAA directs EPA to provide Congress,
through OMB, explanations when the Agency decides not to use available
and applicable voluntary consensus standards. This proposed rule
includes updated information on a number of voluntary consensus
standards previously included in 40 CFR Part 75, as well as the
proposed addition of certain other voluntary consensus standards. The
EPA welcomes comments on this aspect of the proposed rulemaking and
specifically invites the public to identify other potentially
applicable voluntary consensus standards and to explain why such
standards should be used in this regulation.
List of Subjects in 40 CFR Parts 72 and 75
Environmental protection, Acid rain, Administrative practice and
procedure, Air pollution control, Carbon dioxide, Electric utilities,
Nitrogen oxides, Reporting and recordkeeping requirements, Sulfur oxides.
Dated: August 4, 2006.
Stephen L. Johnson,
Administrator.
For the reasons set forth in the preamble, EPA proposes to amend
chapter I of title 40 of the Code of Federal Regulations as follows:
PART 72--PERMITS REGULATION
1. The authority citation for Part 72 continues to read as follows:
Authority: 42 U.S.C. 7601 and 7651, et seq.
Subpart A--Acid Rain Program General Provisions
2. Section 72.2 is amended as follows:
a. In the definition of ``Capacity factor'', by adding the words
``(or maximum observed hourly gross load (in MWe/hr) if greater than
the nameplate capacity)'' after the word ``capacity'' in paragraph (1),
by removing the word ``design'' and adding in its place the words
``rated hourly'' in paragraph (2), and by adding the word ``rate''
after the new phrase ``rated hourly heat input'' in paragraph (2);
b. In the definition of ``Diluent cap'', by removing the words ``,
CO2 mass emission rate, or heat input rate,'' after the
words ``NOX emission rate'';
c. In the definition of ``EPA protocol gas'', by adding a new
sentence to the end of the definition;
d. Revising the definition of ``Excepted monitoring system'';
e. Adding the new definitions in alphabetical order for ``Air
Emission Testing Body (AETB)'', ``EPA Protocol Gas Verification
Program'', ``Long-term cold storage'', ``Qualified Individual'', and
``Specialty gas producer''; and
f. Removing the definitions for ``Calibration gas'', ``Gas
manufacturer's intermediate standard (GMIS)'', ``NIST/EPA-approved
certified reference material or NIST/EPA-approved CRM'', ``NIST
traceable reference material (NTRM)'', ``Research gas material (RGM)'',
``Research gas mixture (RGM)'', ``Standard reference material or SRM'',
``Standard reference material-equivalent compressed gas primary
reference material (SRM-equivalent PRM)'', and ``Zero air material''.
The revisions and additions read as follows:
Sec. 72.2 Definitions.
* * * * *
Air Emission Testing Body (AETB) means a company or other entity
that conducts Air Emissions Testing as described in ASTM D7036-04.
* * * * *
EPA protocol gas * * * Vendors advertising certification with the EPA
[[Page 49279]]
Traceability Protocol or distributing gases as ``EPA Protocol Gas''
must participate in the EPA Protocol Gas Verification Program. Non-
participating vendors may not use ``EPA'' in any form of advertising
for these products, unless approved by the Administrator.
* * * * *
EPA Protocol Gas Verification Program means the EPA Protocol Gas
audit program described in Section 2.1.10 of the ``EPA Traceability
Protocol for Assay and Certification of Gaseous Calibration
Standards,'' September 1997, EPA-600/R-97/121 (EPA Protocol Procedure)
or such revised procedure as approved by the Administrator.
* * * * *
Excepted monitoring system means a monitoring system that follows
the procedures and requirements of Sec. 75.15 of this chapter, Sec.
75.19 of this chapter, Sec. 75.81(b) of this chapter or of appendix D,
or E to part 75 for approved exceptions to the use of continuous
emission monitoring systems.
* * * * *
Long-term cold storage means the complete shut down of a unit
intended to last for an extended period of time (at least two calendar
years) where notice for long-term cold storage is provided under Sec.
75.61(a)(7).
* * * * *
Qualified Individual means an individual who meets the requirements
as described in ASTM D7036-04.
* * * * *
Specialty gas producer means an organization that prepares and
analyzes compressed gas mixtures for use as calibration gases and that
offers the mixtures for sale to end users or to third-party vendors for
resale to end users.
* * * * *
PART 75--CONTINUOUS EMISSION MONITORING
3. The authority citation for Part 75 continues to read as follows:
Authority: 42 U.S.C. 7601, 7651k, and 7651k note.
Subpart A--General
4. Section 75.4 is amended by revising paragraph (d) to read as follows:
Sec. 75.4 Compliance dates.
* * * * *
(d) This paragraph, (d), applies to affected units under the Acid
Rain Program and to units subject to a State or Federal pollutant mass
emissions reduction program that adopts the emission monitoring and
reporting provisions of this part. In accordance with Sec. 75.20, for
an affected unit which, on the applicable compliance date, is either in
long-term cold storage (as defined in Sec. 72.2 of this chapter) or is
shutdown as the result of a planned outage or a forced outage, thereby
preventing the required continuous monitoring system certification
tests from being completed by the compliance date, the owner or
operator shall provide notice of such unit storage or outage in
accordance with Sec. 75.61(a)(3) or Sec. 75.61(a)(7), as applicable.
For the planned and unplanned unit outages described in this paragraph,
the owner or operator shall ensure that all of the continuous
monitoring systems for SO2, NOX, CO2,
Hg, opacity, and volumetric flow rate required under this part (or
under the applicable State or Federal mass emissions reduction program)
are installed and that all required certification tests are completed
no later than 90 unit operating days or 180 calendar days (whichever
occurs first) after the date that the unit recommences commercial
operation, notice of which date shall be provided under Sec.
75.61(a)(3) or Sec. 75.61(a)(7), as applicable. The owner or operator
shall determine and report SO2 concentration, NOX
emission rate, CO2 concentration, Hg concentration, and flow
rate data (as applicable) for all unit operating hours after the
applicable compliance date until all of the required certification
tests are successfully completed, using either:
(1) The maximum potential concentration of SO2 (as
defined in section 2.1.1.1 of appendix A to this part), the maximum
potential NOX emission rate, as defined in Sec. 72.2 of
this chapter, the maximum potential flow rate, as defined in section
2.1.4.1 of appendix A to this part, the maximum potential Hg
concentration, as defined in section 2.1.7.1 of appendix A to this
part, or the maximum potential CO2 concentration, as defined
in section 2.1.3.1 of appendix A to this part; or
(2) The conditional data validation provisions of Sec.
75.20(b)(3); or
(3) Reference methods under Sec. 75.22(b); or
(4) Another procedure approved by the Administrator pursuant to a
petition under Sec. 75.66.
* * * * *
5. Section 75.6 is amended by:
a. Removing ``D129-91'' and adding in its place ``D129-00'', in
paragraph (a)(1);
b. Removing ``D240-87'' and adding in its place ``D240-00'', in
paragraph (a)(2);
c. Removing ``D287-82 (Reapproved 1987)'' and adding in its place
``D287-92 (2000)e1'', in paragraph (a)(3);
d. Removing ``D388-92'' and adding in its place ``D388-99e1'', in
paragraph (a)(4);
e. Removing and reserving paragraph (a)(5);
f. Adding the phrase ``(1999)'' at the end of ``D1072-90'', in
paragraph (a)(6);
g. Removing ``D1217-91'' and adding in its place ``D1217-93
(1998)'', in paragraph (a)(7);
h. Adding the phrase ``(1997)e1'' at the end of D1250-80, and by
removing the phrase ``(Reapproved 1990)'', in paragraph (a)(8);
i. Removing the phrase ``D1298-85 (Reapproved 1990)'' and adding in
its place ``D1298-99'', in paragraph (a)(9);
j. Removing ``D1480-91'' and adding in its place ``D1480-93
(1997)'', in paragraph (a)(10);
k. Removing ``D1481-91'' and adding in its place ``D1481-93
(1997)'', in paragraph (a)(11);
l. Removing ``D1552-90'' and adding in its place ``D1552-01'', in
paragraph (a)(12);
m. Removing ``D1826-88'' and adding in its place ``D1826-94
(1998)'', in paragraph (a)(13);
n. Removing ``D1945-91'' and adding in its place ``D1945-96
(2001)'', in paragraph (a)(14);
o. Adding the phrase ``(2000)'' after ``D1946-90'', in paragraph
(a)(15);
p. Removing and reserving paragraph (a)(16);
q. Removing ``D2013-86'' and adding in its place ``D2013-01'', in
paragraph (a)(17);
r. Removing and reserving paragraph (a)(18);
s. Removing ``D2234-89'' and adding in its place ``D2234-00e1'', in
paragraph (a)(19);
t. Removing and reserving paragraph (a)(20);
u. Removing ``D2502-87'' and adding in its place ``D2502-92
(1996)'', in paragraph (a)(21);
v. Removing ``D2503-82 (Reapproved 1987)'' and adding in its place
``D2503-92 (1997)'', in paragraph (a)(22);
w. Removing ``D2622-92'' and adding in its place ``D2622-98'', in
paragraph (a)(23);
x. Removing ``D3174-89'' and adding in its place ``D3174-00'', in
paragraph (a)(24);
y. Adding the phrase ``(1997)e1'' after ``D3176-89'', in paragraph
(a)(25);
z. Adding the phrase ``(1997)'' after ``D3177-89'', in paragraph
(a)(26);
aa. Adding the phrase ``(1997)'' after ``D3178-89'', in paragraph
(a)(27);
bb. Removing ``D3238-90'' and adding in its place ``D3238-95
(2000)e1'', in paragraph (a)(28);
[[Page 49280]]
cc. Removing ``D3246-81 (Reapproved 1987)'' and adding in its place
``D3246-96'', in paragraph (a)(29);
dd. Removing and reserving paragraph (a)(30);
ee. Removing ``D3588-91'' and adding in its place ``D3588-98'', in
paragraph (a)(31);
ff. Removing ``D4052-91'' and adding in its place ``D4052-96
(2002)e1'', in paragraph (a)(32);
gg. Removing ``D4057-88'' and adding in its place ``D4057-95
(2000)'', in paragraph (a)(33);
hh. Removing ``D4177-82 (Reapproved 1990)'' and adding in its place
``D4177-95 (2000)'', in paragraph (a)(34)
ii. Removing ``D4239-85'' and adding in its place ``D4239-02'', in
paragraph (a)(35);
jj. Removing ``D4294-90'' and adding in its place ``D4294-98'', in
paragraph (a)(36);
kk. Removing the phrase ``(Reapproved 1989)'' and adding in its
place the phrase ``(2000)'', in paragraph (a)(37);
ll. Adding the phrase ``(2001)'' after ``D4891-89'', in paragraph
(a)(39);
mm. Removing ``D5291-92'' and adding in its place ``D5291-01'', in
paragraph (a)(40);
nn. Adding the phrase ``(1997)'' after ``D5373-93'', in paragraph
(a)(41);
oo. Removing ``D5504-94'' and adding in its place ``D5504-01'', in
paragraph (a)(42);
pp. Adding new paragraphs (a)(45), (a)(46), (a)(47), and (a)(48);
qq. Removing the phrase ``with September 1990 Errata'' and adding
in its place the phrase ``(Reaffirmed 1995)'', in paragraph (b)(1);
rr. Removing the date ``1990'' and adding in its place the date
``1997'' in the parenthetical, in paragraph (b)(2);
ss. Adding the phrase ``(Reaffirmed 2001)'' after ``ASME-MFC-5M-
1985'', in paragraph (b)(3);
tt. Removing the phrase ``1987 with June 1987 Errata'' and adding
in its placethe number ``1998'' at the end of ``MFC-6M-'', in paragraph
(b)(4);
uu. Removing the date ``1992'' and adding in its place the date
``2001'' in the parenthetical, in paragraph (b)(5);
vv. Removing the phrase ``with December 1989 Errata'' and adding in
its place the phrase ``(Reaffirmed 2001)'', in paragraph (b)(6);
ww. Removing the number ``86'' and adding in its place the number
``1996'' at the end of ``GPA Standard 2172-'', in paragraph (d)(1);
xx. Removing the number ``90'' and adding in its place the number
``1999'' at the end of ``GPA Standard 2261-'', in paragraph (d)(2);
yy. Adding the phrase ``(1st edition)'' after the date ``December
1994'', removing the phrase ``April 1992 (reaffirmed January 1997)''
and adding in its place the phrase ``June 2001'', adding the phrase
``(Reaffirmed September 2000)'' after the date ``September 1995'',
adding the phrase ``(1st Edition)'' after the date ``June 1996'',
adding the phrase ``(1st Edition)'' after the date ``April 1995'', and
adding the phrase ``(1st Edition)'' after the date ``March 1997'', in
paragraph (f)(1);
zz. Adding the phrase ``Manual of Measurement Standards, Chapter
4:'' after the phrase ``(API)'', adding the phrase ``(Provers
Accumulating at Least 10,000 Pulses), Measurement Coordination (Second
Edition, March 2001)'', after the words ``Conventional Pipe Provers'',
adding the phrase ``(First Edition)'' after the words ``Small Volume
Provers'', adding the phrase ``Measurement Coordination (Second
Edition, May 2000)'' after the phrase ``Master-Meter Provers,'' and
removing the phrase ``from Chapter 4 of the Manual of Petroleum
Measurement Standards, October 1988 (Reaffirmed 1993)'', in paragraph
(f)(3); and
aaa. Adding new paragraph (f)(4).
The revisions and additions read as follows:
Sec. 75.6 Incorporation by reference.
(a) * * *
(45) ASTM D6667-04, Standard Test Method for Determination of Total
Volatile Sulfur in Gaseous Hydrocarbons and Liquified Petroleum Gases
by Ultraviolet Fluorescence, for appendix D of this part.
(46) ASTM D4809-00, ``Standard Test Method for Heat of Combustion
of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), for
appendices D and F of this part.
(47) ASTM D5865-01ae1, ``Standard Test Method for Gross Calorific
Value of Coal and Coke'', for appendices A, D, and F of this part.
(48) ASTM D7036-04, ``Standard Practice for Competence of Air
Emission Testing Bodies'', for appendices A, B, and E of this part.
* * * * *
(f) * * *
(4) American Petroleum Institute (API) Manual of Petroleum
Measurement Standards, Chapter 22--Testing Procedures: Section 2--
Differential Pressure Flow Measurement Devices (First Edition, August
2005) for Appendix D to this part.
6. Section 75.11 is amended by:
a. Revising the heading of the section;
b. Adding the phrase ``and 14.0% for natural gas (boilers, only)''
after the word ``wood'', in paragraph (b)(1);
c. Revising paragraph (d)(3);
d. Revising paragraph (e) introductory text, (e)(1) and (e)(3)
introductory text;
e. Removing and reserving paragraph (e)(2); and
f. Revising paragraph (f).
The revisions and additions read as follows:
Sec. 75.11 Specific provisions for monitoring SO2 emissions.
* * * * *
(d) * * *
(3) By using the low mass emissions excepted methodology in Sec.
75.19(c) for estimating hourly SO2 mass emissions if the
affected unit qualifies as a low mass emissions unit under Sec.
75.19(a) and (b). If this option is selected for SO2, the
LME methodology must also be used for NOX and CO2
when these parameters are required to be monitored by applicable program(s).
(e) Special considerations during the combustion of gaseous fuels.
The owner or operator of an affected unit that uses a certified flow
monitor and a certified diluent gas (O2 or CO2)
monitor to measure the unit heat input rate shall, during any hours in
which the unit combusts only gaseous fuel, determine SO2
emissions in accordance with paragraph (e)(1) or (e)(3) of this
section, as applicable.
(1) If the gaseous fuel qualifies for a default SO2
emission rate under Section 2.3.1.1, 2.3.2.1.1, or 2.3.6(b) of appendix
D to this part, the owner or operator may determine SO2
emissions by using Equation F-23 in appendix F to this part. Substitute
into Equation F-23 the hourly heat input, calculated using the
certified flow monitoring system and the certified diluent monitor
(according to the applicable equation in section 5.2 of appendix F to
this part), in conjunction with the appropriate default SO2
emission rate from section 2.3.1.1, 2.3.2.1.1, or 2.3.6(b) of appendix
D to this part. When this option is chosen, the owner or operator shall
perform the necessary data acquisition and handling system tests under
Sec. 75.20(c), and shall meet all quality control and quality
assurance requirements in appendix B to this part for the flow monitor
and the diluent monitor; or
(2) [Reserved]
(3) The owner or operator may determine SO2 mass
emissions by using a certified SO2 continuous monitoring
system, in conjunction with the certified flow rate monitoring system.
However, if the gaseous fuel is very low sulfur fuel (as defined in
Sec. 72.2 of this chapter), the SO2 monitoring system shall
meet the following quality assurance provisions
[[Page 49281]]
when the very low sulfur fuel is combusted:
* * * * *
(4) The provisions in paragraph (e)(1) of this section, may also be
used for the combustion of a solid or liquid fuel that meets the
definition of very low sulfur fuel in Sec. 72.2 of this chapter,
mixtures of such fuels, or combinations of such fuels with gaseous
fuel, if the owner or operator submits a petition under Sec. 75.66 for
a default SO2 emission rate for each fuel, mixture or
combination, and if the Administrator approves the petition.
(f) Other units. The owner or operator of an affected unit that
combusts wood, refuse, or other material in addition to oil or gas
shall comply with the monitoring provisions for coal-fired units
specified in paragraph (a) of this section, except where the owner or
operator has an approved petition to use the provisions of paragraph
(e)(1) of this section.
7. Section 75.12 is amended by:
a. Revising the section heading;
b. Removing the word ``and'' before the number ``15.0%'', and by
adding the phrase ``; and 18.0% for natural gas (boilers, only)'' after
the word ``wood'', in paragraph (b); and
c. Revising paragraph (e)(3).
The revisions read as follows:
Sec. 75.12 Specific provisions for monitoring NOX emission rate.
* * * * *
(e) * * *
(3) Use the low mass emissions excepted methodology in Sec.
75.19(c) for estimating hourly NOX emission rate and hourly
NOX mass emissions, if applicable under Sec. 75.19(a) and
(b). If this option is selected for NOX, the LME methodology
must also be used for SO2 and CO2 when these
parameters are required to be monitored by applicable program(s).
* * * * *
8. Section 75.13 is amended by revising paragraph (d)(3) to read as
follows:
Sec. 75.13 Specific provisions for monitoring CO2 emissions.
* * * * *
(d) * * *
(3) Use the low mass emissions excepted methodology in Sec.
75.19(c) for estimating hourly CO2 mass emissions, if
applicable under Sec. 75.19(a) and (b). If this option is selected for
CO2, the LME methodology must also be used for
NOX and SO2 when these parameters are required to
be monitored by applicable program(s).
9. Section 75.15 is amended by:
a. Removing the reference ``(j)'' and adding the reference ``(l)''
in its place, in the introductory paragraph;
b. Revising paragraph (h); and
c. Adding paragraphs (k) and (l).
The revisions and additions read as follows:
Sec. 75.15 Special provisions for measuring Hg mass emissions using
the excepted sorbent trap monitoring methodology.
* * * * *
(h) The hourly Hg mass emissions for each collection period are
determined using the results of the analyses in conjunction with
contemporaneous hourly data recorded by a certified stack flow monitor,
corrected for the stack gas moisture content. For each pair of sorbent
traps analyzed, the average of the two Hg concentrations shall be used
for reporting purposes under Sec. 75.84(f). Notwithstanding this
requirement, if, due to circumstances beyond the control of the owner
or operator, one of the paired traps is accidentally lost, damaged, or
broken and cannot be analyzed, the results of the analysis of the other
trap may be used for reporting purposes, provided that:
(1) The other trap has met all of the applicable quality-assurance
requirements of this part; and
(2) The Hg concentration measured by the other trap is multiplied
by a factor of 1.222.
* * * * *
(k) When a sorbent trap monitoring system is tested for relative
accuracy, both the size of the sorbent traps and the type of sorbent
material used by the traps shall be the same as for daily operation of
the system.
(l) Whenever the size of the sorbent traps or the type of sorbent
material used by the traps is changed, the owner or operator shall
conduct a diagnostic RATA of the sorbent trap monitoring system. The
modified system shall not be used to report Hg emissions under this
part until the RATA has been performed and passed. Notwithstanding this
requirement, Hg concentrations measured by the modified system during a
successful RATA may be reported as quality-assured data under this part.
10. Section 75.16 is amended by:
a. Revising paragraph (b)(1)(ii);
b. Adding the word ``rate'' after the phrase ``report heat input''
in the last sentence, in paragraph (e)(1); and
c. Replacing both occurrences of the phrase ``steam flow'' with the
phrase ``steam load'' and adding the phrase ``or mmBtu/hr thermal
output'' inside the parentheses, after the phrase ``in 1000 lb/hr'', in
paragraph (e)(3).
The revisions read as follows:
Sec. 75.16 Special provisions for monitoring emissions from common,
bypass, and multiple stacks for SO2 emissions and heat input determinations.
* * * * *
(b) * * *
(1) * * *
(ii) Install, certify, operate, and maintain an SO2
continuous emission monitoring system and flow monitoring system in the
common stack and combine emissions for the affected units for
recordkeeping and compliance purposes.
* * * * *
11. Section 75.17 is amended by revising paragraph (d)(2) to read
as follows:
Sec. 75.17 Special provisions for monitoring emissions from common,
bypass, and multiple stacks for NOX emission rate.
* * * * *
(d) * * *
(2) Install, certify, operate, and maintain a NOX-
diluent CEMS only on the main stack. If this option is chosen, it is
not necessary to designate the exhaust configuration as a multiple
stack configuration in the monitoring plan required under Sec. 75.53,
with respect to NOX or any other parameter that is monitored
only at the main stack. For each unit operating hour in which the
bypass stack is used and the emissions are either uncontrolled (or the
add-on controls are not documented to be operating properly), report
the maximum potential NOX emission rate (as defined in Sec.
72.2 of this chapter). The maximum potential NOX emission
rate may be specific to the type of fuel combusted in the unit during
the bypass (see Sec. 75.33(c)(8)). Alternatively, for a unit with
NOX add-on emission controls, for each unit operating hour
in which the bypass stack is used and the emissions are controlled, the
owner or operator may report the maximum controlled NOX
emission rate (MCR) instead of the maximum potential NOX
emission rate provided that the add-on controls are documented to be
operating properly, as described in the quality assurance/quality
control program for the unit, required by section 1 in appendix B of
this part. To provide the necessary documentation, the owner or
operator shall record parametric data to verify the proper operation of
the NOX add-on emission controls as described in Sec.
75.34(d). Furthermore, the owner or operator shall calculate the MCR
using the procedure described in section 2.1.2.1(b) of Appendix A to
this part by replacing the words ``maximum potential NOX
emission rate (MER)'' with the words ``maximum controlled
NOX emission rate (MCR)'' in and by
[[Page 49282]]
using the NOX MEC instead of the NOX MPC.
12. Section 75.19 is amended by:
a. Revising paragraph (a)(1);
b. Revising paragraph (c)(1)(i);
c. Adding the phrase, ``that meets the quality assurance
requirements of either: this part, or appendix F to part 60 of this
chapter, or a comparable State CEM program,'' after the abbreviation
``CEMS'', in paragraph (c)(1)(iv)(G);
d. Adding the word ``add-on'' before the first instance of the
phrase ``NOX controls'', in paragraph (c)(1)(iv)(H)(3);
e. Adding the phrase ``(1st Edition)'' after the date ``December
1994'', replacing the phrase ``April 1992 (reaffirmed January 1997)''
with the date ``June 2001'' after the phrase ``Stationary Tanks by
Automatic Tank Gauging,'', adding the phrase ``(Reaffirmed September
2000)'' after the date ``September 1995'', adding the phrase ``(1st
Edition)'' after the date ``June 1996'', adding the phrase ``(1st
Edition)'' after the date ``April 1995'', and adding the phrase ``(1st
Edition)'' after the date ``March 1997'', in paragraph (c)(3)(ii)(B)(2);
f. Removing the words ``from Table LM-1 of this section'' from the
first sentence of paragraph (c)(4)(i)(A);
g. Revising the heading to paragraph (c)(4)(ii); and
h. Adding paragraph (c)(4)(ii)(D).
The revisions and additions read as follows:
Sec. 75.19 Optional SO2, NOX, and
CO2 emissions calculation for low mass emissions units.
* * * * *
(a) * * *
(1) For units that meet the requirements of this paragraph (a)(1)
and paragraphs (a)(2) and (b) of this section, the low mass emissions
(LME) excepted methodology in paragraph (c) of this section may be used
in lieu of continuous emission monitoring systems or, if applicable, in
lieu of methods under appendices D, E, and G to this part, for the
purpose of determining unit heat input, NOX, SO2,
and CO2 mass emissions, and NOX emission rate
under this part. If the owner or operator of a qualifying unit elects
to use the LME methodology, it must be used for all parameters that are
required to be monitored by the applicable program(s). For example, for
an Acid Rain Program LME unit, the methodology must be used to estimate
SO2, NOX, and CO2 mass emissions,
NOX emission rate, and unit heat input.
* * * * *
(c) * * *
(1) * * *
(i) If the unit combusts only natural gas and/or fuel oil, use
Table LM-1 of this section to determine the appropriate SO2
emission rate for use in calculating hourly SO2 mass
emissions under this section. Alternatively, for fuel oil combustion, a
lower, fuel-specific SO2 emission factor may be used in lieu
of the applicable emission factor from Table LM-1, if a federally
enforceable permit condition is in place that limits the sulfur content
of the oil. If this alternative is chosen, the fuel-specific
SO2 emission rate in lb/mmBtu shall be calculated by
multiplying the fuel sulfur content limit (weight percent sulfur) by
1.01. In addition, the owner or operator shall periodically determine
the sulfur content of the oil combusted in the unit, using one of the
oil sampling and analysis options described in section 2.2 of Appendix
D to this part, and shall keep records of these fuel sampling results
in a format suitable for inspection and auditing. If the unit combusts
gaseous fuel(s) other than natural gas, the owner or operator shall use
the procedures in section 2.3.6 of appendix D to this part to document
the total sulfur content of each such fuel and to determine the
appropriate default SO2 emission rate for each such fuel.
* * * * *
(4) * * *
(ii) NOX mass emissions and NOX emission
rate. * * *
(D) The quarterly and cumulative NOX emission rate in
lb/mmBtu (if required by the applicable program(s)) shall be determined
as follows. Calculate the quarterly NOX emission rate by
taking the arithmetic average of all of the hourly EFNOx
values. Calculate the cumulative (year-to-date) NOX emission
rate by taking the arithmetic average of the quarterly NOX
emission rates.
* * * * *
13. Section 75.20 is amended by:
a. Adding a new sentence after the third sentence of paragraph (b)
introductory text;
b. Revising paragraph (c)(1)(v); and
c. Removing paragraphs (f)(1) and (f)(2).
The revisions and additions read as follows:
Sec. 75.20 Initial certification and recertification procedures.
* * * * *
(b) * * * The owner or operator shall also recertify the continuous
emission monitoring systems for a unit that has recommenced commercial
operation following a period of long-term cold storage as defined in
Sec. 72.2 of this chapter. * * *
* * * * *
(c) * * *
(1) * * *
(v) A cycle time test, (where, for the NOX-diluent
continuous emission monitoring system, the test is performed separately
on the NOX pollutant concentration monitor and the diluent
gas monitor); and
* * * * *
14. Section 75.21 is amended by removing the words ``or (e)(2)'' at
the end of the first sentence of paragraph (a)(4).
15. Section 75.22 is amended by revising paragraphs (a)(5) and
(a)(7) to read as follows:
Sec. 75.22 Reference test methods.
(a) * * *
(5) Methods 6, 6A, 6B or 6C, and 7, 7A, 7C, 7D or 7E, as
applicable, are the reference methods for determining SO2
and NOX pollutant concentrations. Alternatively, Method 20
may be used as the reference method for relative accuracy test audits
of NOX CEMS installed on combustion turbines. (Methods 6A
and 6B may also be used to determine SO2 emission rate in
lb/mmBtu.) Methods 7, 7A, 7C, 7D, or 7E must be used to measure total
NOX emissions, both NO and NO2, for purposes of
this part. The owner or operator shall not use the following exceptions
or options of method 7E:
(i) Section 7.1 of the method allowing for use of prepared
calibration gas mixtures that are produced in accordance with method
205 in Appendix M of 40 CFR Part 51;
(ii) Paragraph (3) in section 8.4 of the method allowing for the
use of a multi-hole probe to satisfy the multipoint traverse
requirement of the method;
(iii) Section 8.6 of the method allowing for the use of ``Dynamic
Spiking'' as an alternative to the interference and system bias checks
of the method. Dynamic spiking may be conducted (optionally) as an
additional quality assurance check.
* * * * *
(7) ASTM D6784-02, ``Standard Test Method for Elemental, Oxidized,
Particle-Bound, and Total Mercury in Flue Gas Generated from Coal-Fired
Stationary Sources'' (also known as the Ontario Hydro
Method)(incorporated by reference, see Sec. 75.6) is the reference
method for determining Hg concentration. Alternatively, Method 29 in
appendix A-8 to part 60 of this chapter may be used, with these
caveats: the procedures for preparation of Hg standards and sample
analysis in sections 13.4.1.1 through 13.4.1.3 ASTM D6784-02 shall be
followed instead of the procedures in sections 7.5.33 and 11.1.3 of
Method 29, and the QA/QC
[[Page 49283]]
procedures in section 13.4.2 of ASTM D6784-02 shall be performed
instead of the procedures in section 9.2.3 of Method 29. The tester may
also opt to use the sample recovery and preparation procedures in ASTM
D6784-02 instead of the Method 29 procedures, as follows: sections
8.2.8 and 8.2.9.1 of Method 29 may be replaced with sections 13.2.9.1
through 13.2.9.3 of ASTM D6784-02 ; sections 8.2.9.2 and 8.2.9.3 of
Method 29 may be replaced with sections 13.2.10.1 through 13.2.10.4 of
ASTM D6784-02; section 8.3.4 of Method 29 may be replaced with section
13.3.4 or 13.3.6 of ASTM D6784-02 (as appropriate); and section 8.3.5
of Method 29 may be replaced with section 13.3.5 or 13.3.6 of ASTM
D6784-02 (as appropriate). Whenever ASTM D6784-02 or Method 29 is used,
paired sampling trains are required. To validate a RATA run, the
relative deviation (RD), calculated according to section 11.7 of
appendix K to this part, must not exceed 10 percent, when the average
concentration is greater than 1.0 [mu]g/m\3\. If the average
concentration is < = 1.0 [mu]g/m\3\, the RD must not exceed 20 percent.
If the RD criterion is met, use the average Hg concentration measured
by the two trains (vapor phase, only) in the relative accuracy
calculations. As a second alternative, an instrumental reference method
or other suitable reference method capable of measuring total vapor
phase Hg may be used, subject to the approval of the Administrator.
* * * * *
16. Section 75.32 is amended by replacing the phrase ``need not be
calculated during the'' with the phrase ``shall be calculated for each
hour during each'', by replacing the word ``last'' with the word
``each'', and by removing the phrase ``as the monitor availability
used'' after the words ``data period'', in paragraph (b).
17. Section 75.33 is amended by:
a. Replacing the word ``Whenever'' with the word ``If'', and by
replacing the words ``each hour of each'' with the words ``that hour of
the'', in paragraph (b)(1) introductory text;
b. Replacing the word ``Whenever'' with the word ``If'', and by
replacing the words ``each hour of each'' with the words ``that hour of
the'', in paragraph (b)(2) introductory text;
c. Replacing the word ``Whenever'' with the word ``If'', and by
replacing the word ``each'' with the words ``that hour of the'', in
paragraphs (b)(3) and (b)(4);
d. Replacing the word ``Whenever'' with the word ``If'', and by
replacing the words ``each hour of each'' with the words ``that hour of
the'', in paragraphs (c)(1) introductory text, (c)(2) introductory
text, (c)(3), and (c)(4);
e. Revising Tables 1 and 2 in paragraph (c)(8)(iv);
f. Revising Table 3 in paragraph (e)(3); and
h. Replacing the word ``Whenever'' with the word ``If'', and by
replacing the words ``each hour of each'' with the words ``that hour of
the'', in paragraphs (d)(1), (d)(2), (d)(3), and (d)(4).
The revisions and additions read as follows:
Sec. 75.33 Standard missing data procedures for SO2,
NOX, Hg, and flow rate.
* * * * *
(c) * * *
(8) * * *
(iv) * * *
Table 1.--Missing Data Procedure for SO2 CEMS, CO2 CEMS, Moisture CEMS, Hg CEMS, and Diluent (CO2 or O2)
Monitors for Heat Input Determination
----------------------------------------------------------------------------------------------------------------
Trigger conditions Calculation routines
----------------------------------------------------------------------------------------------------------------
Monitor data availability Duration (N) of CEMS
(percent) outage (hours) \2\ Method Lookback period
----------------------------------------------------------------------------------------------------------------
95 or more (90 or more for Hg).... N < = 24.............. Average.............. HB/HA
N > 24............... For SO2, CO2, Hg, and
H2O **, the greater
of:
Average.............. HB/HA
90th percentile...... 720 hours *
For O2 and H2Ox, the
lesser of:
10th percentile...... HB/HA 720 hours *
90 or more, but below 95 (> 80 but N <= 8............... Average.............. HB/HA
< 90 for Hg).
N > 8................ For SO2, CO2, Hg, and
H2O **, the greater
of:
Average.............. HB/HA
95th percentile...... 720 hours *
For O2 and H2Ox, the
lesser of:
Average.............. HB/HA
5th Percentile....... 720 hours *
80 or more, but below 90 (> 70 but N > 0................ For SO2, CO2, Hg, and
< 80 for Hg). H2O **,
Maximum value1....... 720 hours *
For O2 and H2Ox:.....
Minimum value1....... 720 hours *
Below 80 (Below 70 for Hg)........ N > 0................ Maximum potential
concentration 3 or %
(for SO2, CO2, Hg,
and H2O **) or.
Minimum potential None
concentration or %
(for O2 and H2Ox).
----------------------------------------------------------------------------------------------------------------
HB/HA = hour before and hour after the CEMS outage.
* Quality-assured, monitor operating hours, during unit operation. May be either fuel-specific or non-fuel-
specific. For units that report data only for the ozone season, include only quality assured monitor operating
hours within the ozone season in the lookback period. Use data from no earlier than 3 years prior to the
missing data period.
\1\ Where a unit with add-on SO2 or Hg emission controls can demonstrate that the controls are operating
properly, as provided in Sec. 75.34, the unit may, upon approval, use the maximum controlled emission rate
from the previous 720 quality-assured monitor operating hours.
\2\ During unit operating hours.
[[Page 49284]]
\3\ Alternatively, where a unit with add-on SO2 or Hg emission controls can demonstrate that the controls are
operating properly, as provided in Sec. 75.34, the unit may report the greater of: (a) The maximum expected
SO2 or Hg concentration or (b) 1.25 times the maximum controlled value from the previous 720 quality-assured
monitor operating hours.
x Use this algorithm for moisture except when Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60
of this chapter is used for NOX emission rate.
** Use this algorithm for moisture only when Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60
of this chapter is used for NOX emission rate.
Table 2.--Load-Based Missing Data Procedure for NOX-Diluent CEMS, NOX Concentration CEMS and Flow Rate CEMS
----------------------------------------------------------------------------------------------------------------
Trigger conditions Calculation routines
----------------------------------------------------------------------------------------------------------------
Duration (N) of
Monitor data availability CEMS outage (hours) Method Lookback period Load ranges
(percent) \2\
----------------------------------------------------------------------------------------------------------------
95 or more....................... N < = 24............ Average............ 2160 hours *....... Yes
N > 24............. The greater of:
Average............ HB/HA.............. No
90th percentile.... 2160 hours *....... Yes
90 or more, but below 95......... N < = 8............. Average............ 2160 hours *....... Yes
N > 8.............. The greater of:
Average............ HB/HA.............. No
95th percentile.... 2160 hours *....... Yes
80 or more, but below 90......... N > 0.............. Maximum value \1\.. 2160 hours *....... Yes
Below 80......................... N > 0.............. Maximum potential None............... No
NOX emission
rate3; or maximum
potential NOX
concentration3; or
maximum potential
flow rate..
----------------------------------------------------------------------------------------------------------------
HB/HA = hour before and hour after the CEMS outage.
* Quality-assured, monitor operating hours, using data at the corresponding load range (``load bin'') for each
hour of the missing data period. May be either fuel-specific or non-fuel-specific. For units that report data
only for the ozone season, include only quality assured monitor operating hours within the ozone season in the
lookback period. Use data from no earlier than three years prior to the missing data period.
\1\ Where a unit with add-on NOX emission controls can demonstrate that the controls are operating properly, as
provided in Sec. 75.34, the unit may, upon approval, use the maximum controlled emission rate from the
previous 2160 quality-assured monitor operating hours. Alternatively, units with add-on controls that report
NOX mass emissions on a year-round basis under subpart H of this part may use separate ozone season and non-
ozone season databases to provide substitute data values, as described in Sec. 75.34 (a)(2).
\2\ During unit operating hours.
\3\ Alternatively, where a unit with add-on NOX emission controls can demonstrate that the controls are
operating properly, as provided in Sec. 75.34, the unit may report the greater of: (a) The maximum expected
NOX concentration (or maximum controlled NOX emission rate, as applicable); or (b) 1.25 times the maximum
controlled value at the corresponding load bin, from the previous 2160 quality-assured monitor operating
hours.
* * * * *
(e) * * *
(3) * * *
Table 3.--Non-load-based Missing Data Procedure for NOX-Diluent CEMS and NOX Concentration CEMS
----------------------------------------------------------------------------------------------------------------
Trigger conditions Calculation routines
----------------------------------------------------------------------------------------------------------------
Duration (N) of CEMS
Monitor data availability (percent) outage (hours) \1\ Method Lookback period
----------------------------------------------------------------------------------------------------------------
95 or more.......................... N < = 24................ Average............... 2160 hours *
N > 24................. 90th percentile....... 2160 hours *
90 or more, but below 95............ N < = 8................. Average............... 2160 hours *
N > 8.................. 95th percentile....... 2160 hours *
80 or more, but below 90............ N > 0.................. Maximum value......... 2160 hours *
Below 80, or operational bin N > 0.................. Maximum potential NOX None
indeterminable. emission rate \2\ or
maximum potential NOX
concentration \2\.
----------------------------------------------------------------------------------------------------------------
* If operational bins are used, the lookback period is 2,160 quality-assured, monitor operating hours, and data
at the corresponding operational bin are used to provide substitute data values. If operational bins are not
used, the lookback period is the previous 2,160 quality-assured monitor operating hours. For units that report
data only for the ozone season, include only quality-assured monitor operating hours within the ozone season
in the lookback period. Use data from no earlier than three years prior to the missing data period.
\1\ During unit operation.
\2\ Alternatively, where a unit with add-on NOX emission controls can demonstrate that the controls are
operating properly, as provided in Sec. 75.34, the unit may report the greater of: (a) the maximum expected
NOX concentration, (or maximum controlled NOX emission rate, as applicable); or (b) 1.25 times the maximum
controlled value at the corresponding operational bin (if applicable), from the previous 2160 quality-assured
monitor operating hours.
[[Page 49285]]
* * * * *
18. Section 75.34 is amended by:
a. Revising paragraph (a) introductory text;
b. Amending paragraph (a)(2)(ii) by replacing the words ``and
(c)(3)'' with ``, (c)(3) and (c)(5), and Sec. 75.38(c),'';
c. Revising paragraph (a)(3);
d. Adding paragraph (a)(5); and
e. Revising paragraph (d) by replacing the words ``paragraphs
(a)(1) and (a)(3)'' with ``paragraphs (a)(1), (a)(3) and (a)(5)''.
The revisions and additions read as follows:
Sec. 75.34 Units with add-on emission controls.
(a) The owner or operator of an affected unit equipped with add-on
SO2 and/or NOX emission controls shall provide
substitute data in accordance with paragraphs (a)(1), through (a)(5) of
this section for each hour in which quality-assured data from the
outlet SO2 and/or NOX monitoring system(s) are
not obtained.
* * * * *
(3) For each missing data hour in which the percent monitor data
availability for SO2 or NOX, calculated in
accordance with Sec. 75.32, is less than 90.0 percent and is greater
than or equal to 80.0 percent; and parametric data establishes that the
add-on emission controls were operating properly (i.e. within the range
of operating parameters provided in the quality assurance/quality
control program) during the hour, the owner or operator may:
(i) Replace the maximum SO2 concentration recorded in
the 720 quality-assured monitor operating hours immediately preceding
the missing data period, with the maximum controlled SO2
concentration recorded in the previous 720 quality-assured monitor
operating hours; or
(ii) Replace the maximum NOX concentration(s) or
NOX emission rate(s) from the appropriate load bin(s) (based
on a lookback through the 2,160 quality-assured monitor operating hours
immediately preceding the missing data period), with the maximum
controlled NOX concentration(s) or emission rate(s) from the
appropriate load bin(s) in the same 2,160 quality-assured monitor
operating hour lookback period.
* * * * *
(5) For each missing data hour in which the percent monitor data
availability for SO2 or NOX, calculated in
accordance with Sec. 75.32, is below 80.0 percent and parametric data
establish that the add-on emission controls were operating properly
(i.e. within the range of operating parameters provided in the quality
assurance/quality control program), in lieu of reporting the maximum
potential value, the owner or operator may substitute, as applicable,
the greater of:
(i) The maximum expected SO2 concentration or 1.25 times
the maximum hourly controlled SO2 concentration recorded in
the previous 720 quality-assured monitor operating hours;
(ii) The maximum expected NOX concentration or 1.25
times the maximum hourly controlled NOX concentration
recorded in the previous 2,160 quality-assured monitor operating hours
at the corresponding unit load range or operational bin;
(iii) The maximum hourly controlled NOX emission rate
(MCR) or 1.25 times the maximum hourly controlled NOX
emission rate recorded in the previous 2,160 quality-assured monitor
operating hours at the corresponding unit load range or operational bin;
(iv) For the purposes of implementing the missing data options in
paragraphs (a)(5)(i) through (a)(5)(iii) of this section, the maximum
expected SO2 and NOX concentrations shall be
determined, respectively, according to sections 2.1.1.2 and 2.1.2.2 of
appendix A to this part. The MCR shall be calculated according to the
basic procedure described in section 2.1.2.1(b) of appendix A to this
part, except that the words ``maximum potential NOX emission
rate (MER)'' shall be replaced with the words ``maximum controlled
NOX emission rate (MCR)'' and the NOX MEC shall
be used instead of the NOX MPC.
* * * * *
19. Section 75.38 is amended by revising paragraphs (a) and (c) to
read as follows.
Sec. 75.38 Standard missing data procedures for Hg CEMS.
(a) Once 720 quality assured monitor operating hours of Hg
concentration data have been obtained following initial certification,
the owner or operator shall provide substitute data for Hg
concentration in accordance with the procedures in Sec. 75.33(b)(1)
through (b)(4), except that the term ``Hg concentration'' shall apply
rather than ``SO2 concentration,'' the term ``Hg
concentration monitoring system'' shall apply rather than
``SO2 pollutant concentration monitor,'' the term ``maximum
potential Hg concentration, as defined in section 2.1.7 of appendix A
to this part'' shall apply, rather than ``maximum potential
SO2 concentration'', and the percent monitor data
availability trigger conditions prescribed for Hg in Table 1 of Sec.
75.33 shall apply rather than the trigger conditions prescribed for
SO2.
* * * * *
(c) For units with FGD systems or add-on Hg emission controls, when
the percent monitor data availability is less than 80.0 percent and is
greater than or equal to 70.0 percent, and a missing data period
occurs, consistent with Sec. 75.34(a)(3), for each missing data hour
in which the FGD or Hg emission controls are documented to be operating
properly, the owner or operator may report the maximum controlled Hg
concentration recorded in the previous 720 quality-assured monitor
operating hours. In addition, when the percent monitor data
availability is less than 70.0 percent and a missing data period
occurs, consistent with Sec. 75.34(a)(5), for each missing data hour
in which the FGD or Hg emission controls are documented to be operating
properly, the owner or operator may report the greater of the maximum
expected Hg concentration (MEC) or 1.25 times the maximum controlled Hg
concentration recorded in the previous 720 quality-assured monitor
operating hours. The MEC shall be determined in accordance with section
2.1.7.1 of appendix A to this part.
20. Section 75.39 is amended by:
a. Revising paragraph (a);
b. Revising paragraph (b);
c. Revising paragraph (c);
d. Revising paragraph (d); and
e. Adding paragraph (f).
The revisions and additions read as follows:
Sec. 75.39 Missing data procedures for sorbent trap monitoring systems.
(a) If a primary sorbent trap monitoring system has not been
certified by the applicable compliance date specified under a State or
Federal Hg mass emission reduction program that adopts the requirements
of subpart I of this part, and if quality-assured Hg concentration data
from a certified backup Hg monitoring system, reference method, or
approved alternative monitoring system are unavailable, the owner or
operator shall report the maximum potential Hg concentration, as
defined in section 2.1.7 of appendix A to this part, until the primary
system is certified.
(b) For a certified sorbent trap system, a missing data period will
occur in the following circumstances, unless quality-assured Hg
concentration data from a certified backup Hg CEMS, sorbent trap system,
reference method, or approved alternative monitoring system are available:
(1) A gas sample is not extracted from the stack during unit
operation (e.g.
[[Page 49286]]
during a monitoring system malfunction or when the system undergoes
maintenance); or
(2) The results of the Hg analysis for the paired sorbent traps are
missing or invalid (as determined using the quality assurance
procedures in appendix K to this part). The missing data period begins
with the hour in which the paired sorbent traps for which the Hg
analysis is missing or invalid were put into service. The missing data
period ends at the first hour in which valid Hg concentration data are
obtained with another pair of sorbent traps (i.e., the hour at which
this pair of traps was placed in service), or with a certified backup
Hg CEMS, reference method, or approved alternative monitoring system.
(c) Initial missing data procedures. Use the missing data
procedures in Sec. 75.31(b) until 720 hours of quality-assured Hg
concentration data have been collected with the sorbent trap monitoring
system(s), following initial certification.
(d) Standard missing data procedures. Once 720 quality-assured
hours of data have been obtained with the sorbent trap system(s), begin
reporting the percent monitor data availability in accordance with
Sec. 75.32 and switch from the initial missing data procedures in
paragraph (c) of this section to the standard missing data procedures
in Sec. 75.38.
* * * * *
(f) In cases where the owner or operator elects to use a primary Hg
CEMS and a redundant backup sorbent trap monitoring system (or vice-
versa), when both monitoring systems are out-of-service and quality-
assured Hg concentration data from a reference method or approved
alternative monitoring system are unavailable, the previous 720
quality-assured monitor operating hours reported in the electronic
quarterly report under Sec. 75.64 shall be used for the required
missing data lookback, irrespective of whether these data were recorded
by the Hg CEMS, the sorbent trap system, a reference method, or an
approved alternative monitoring system.
21. Section 75.53 is amended by:
a. Revising paragraph (a)(1);
b. Replacing the phrase ``(d) or (f)'' with the phrase ``(f) or
(h)'' in the second sentence of paragraph (a)(2);
c. Adding paragraph (e)(1)(xiv); and
d. Adding paragraphs (g) and (h).
The revisions and additions read as follows:
Sec. 75.53 Monitoring plan.
(a) * * *
(1) The provisions of paragraphs (e) and (f) of this section shall
remain in effect through December 31, 2008. The owner or operator shall
meet the requirements of paragraphs (a), (b), (e), and (f) of this
section through December 31, 2008, except as otherwise provided in
paragraph (g) of this section. On and after January 1, 2009, the owner
or operator shall meet the requirements of paragraphs (a), (b), (g),
and (h) of this section only. In addition, the provisions in paragraphs
(g) and (h) of this section that support a regulatory option provided
in another section of this part must be followed if the regulatory
option is used prior to January 1, 2009.
* * * * *
(e) * * *
(1) * * *
(xiv) For each unit with a flow monitor installed on a rectangular
stack or duct, if a wall effects adjustment factor (WAF) is determined
and applied to the hourly flow rate data:
(A) Stack or duct width at the test location, ft;
(B) Stack or duct depth at the test location, ft;
(C) Wall effects adjustment factor (WAF), to the nearest 0.0001;
(D) Method of determining the WAF;
(E) WAF Effective date and hour;
(F) WAF no longer effective date and hour (if applicable;
(G) WAF determination date;
(H) Number of WAF test runs;
(I) Number of Method 1 traverse points in the WAF test;
(J) Number of test ports in the WAF test; and
(K) Number of Method 1 traverse points in the reference flow RATA.
* * * * *
(g) Contents of the monitoring plan. The requirements of paragraphs
(g) and (h) of this section shall be met on and after January 1, 2009.
Notwithstanding this requirement, the provisions of paragraphs (g) and
(h) of this section may be implemented prior to January 1, 2009, as
follows. In 2008, the owner or operator may opt to record and report
the monitoring plan information in paragraphs (g) and (h) of this
section, in lieu of recording and reporting the information in
paragraphs (e) and (f) of this section. Each monitoring plan shall
contain the information in paragraph (g)(1) of this section in
electronic format and the information in paragraph (g)(2) of this
section in hardcopy format. Electronic storage of all monitoring plan
information, including the hardcopy portions, is permissible provided
that a paper copy of the information can be furnished upon request for
audit purposes.
(1) Electronic.
(i) The facility ORISPL number developed by the Department of
Energy and used in the National Allowance Data Base (or equivalent
facility ID number assigned by EPA, if the facility does not have an
ORISPL number). Also provide the following information for each unit
and (as applicable) for each common stack and/or pipe, and each
multiple stack and/or pipe involved in the monitoring plan:
(A) A representation of the exhaust configuration for the units in
the monitoring plan. Provide the ID number of each unit and assign a
unique ID number to each common stack, common pipe multiple stack and/
or multiple pipe associated with the unit(s) represented in the
monitoring plan. For common and multiple stacks and/or pipes, provide
the activation date and deactivation date (if applicable) of each stack
and/or pipe;
(B) Identification of the monitoring system location(s) (e.g., at
the unit-level, on the common stack, at each multiple stack, etc.).
Provide an indicator (``flag'') if the monitoring location is at a
bypass stack or in the ductwork (breeching);
(C) The stack exit height (ft) above ground level and ground level
elevation above sea level, and the inside cross-sectional area
(ft2) at the flue exit and at the flow monitoring location
(for units with flow monitors, only). Also use appropriate codes to
indicate the material(s) of construction and the shape(s) of the stack
or duct cross-section(s) at the flue exit and (if applicable) at the
flow monitor location;
(D) The type(s) of fuel(s) fired by each unit. Indicate the start
and (if applicable) end date of combustion for each type of fuel, and
whether the fuel is the primary, secondary, emergency, or startup fuel;
(E) The type(s) of emission controls that are used to reduce
SO2, NOX, Hg, and particulate emissions from each
unit. Also provide the installation date, optimization date, and
retirement date (if applicable) of the emission controls, and indicate
whether the controls are an original installation;
(F) Maximum hourly heat input capacity of each unit; and
(G) A non-load based unit indicator (if applicable) for units that
do not produce electrical or thermal output.
(ii) For each monitored parameter (e.g., SO2,
NOX, flow, etc.) at each monitoring location, specify the
monitoring methodology and the missing data approach for the parameter.
If the unmonitored bypass stack approach is used for a particular
parameter, indicate this by means of an appropriate code. Provide the
activation date/hour, and deactivation date/hour (if applicable) for
each monitoring
[[Page 49287]]
methodology and each missing data approach.
(iii) For each required continuous emission monitoring system, each
fuel flowmeter system, each continuous opacity monitoring system, and
each sorbent trap monitoring system (as defined in Sec. 72.2 of this
chapter), identify and describe the major monitoring components in the
monitoring system (e.g., gas analyzer, flow monitor, opacity monitor,
moisture sensor, fuel flowmeter, DAHS software, etc.). Other important
components in the system (e.g., sample probe, PLC, data logger, etc.)
may also be represented in the monitoring plan, if necessary. Provide
the following specific information about each component and monitoring
system:
(A) For each required monitoring system:
(1) Assign a unique, 3-character alphanumeric identification code
to the system;
(2) Indicate the parameter monitored by the system;
(3) Designate the system as a primary, redundant backup, non-
redundant backup, data backup, or reference method backup system, as
provided in Sec. 75.10(e); and
(4) Indicate the system activation date/hour and deactivation date/
hour (as applicable).
(B) For each component of each monitoring system represented in the
monitoring plan:
(1) Assign a unique, 3-character alphanumeric identification code
to the component;
(2) Indicate the manufacturer, model and serial number;
(3) Designate the component type;
(4) For dual-span applications, indicate whether the analyzer
component ID represents a high measurement scale, a low scale, or a
dual range;
(5) For gas analyzers, indicate the moisture basis of measurement;
(6) Indicate the method of sample acquisition or operation, (e.g.,
extractive pollutant concentration monitor or thermal flow monitor);
and
(7) Indicate the component activation date/hour and deactivation
date/hour (as applicable).
(iv) Explicit formulas, using the component and system
identification codes for the primary monitoring system, and containing
all constants and factors required to derive the required mass
emissions, emission rates, heat input rates, etc. from the hourly data
recorded by the monitoring systems. Formulas using the system and
component ID codes for backup monitoring systems are required only if
different formulas for the same parameter are used for the primary and
backup monitoring systems (e.g., if the primary system measures
pollutant concentration on a different moisture basis from the backup
system). Provide the equation number or other appropriate code for each
emissions formula (e.g., use code F-1 if Equation F-1 in appendix F to
this part is used to calculate SO2 mass emissions). Also
identify each emissions formula with a unique three character
alphanumeric code. The formula effective start date/hour and
inactivation date/hour (as applicable) shall be included for each
formula. The owner or operator of a unit for which the optional low
mass emissions excepted methodology in Sec. 75.19 is being used is not
required to report such formulas.
(v) For each parameter monitored with CEMS, provide the following
information:
(A) Measurement scale (high or low);
(B) Maximum potential value (and method of calculation). If
NOX emission rate in lb/mmBtu is monitored, calculate and
provide the maximum potential NOX emission rate in addition
to the maximum potential NOX concentration;
(C) Maximum expected value (if applicable) and method of calculation;
(D) Span value(s) and full-scale measurement range(s);
(E) Daily calibration units of measure;
(F) Effective date/hour, and (if applicable) inactivation date/hour
of each span value;
(G) An indication of whether dual spans are required; and
(H) The default high range value (if applicable) and the maximum
allowable low-range value for this option;
(vi) If the monitoring system or excepted methodology provides for
the use of a constant, assumed, or default value for a parameter under
specific circumstances, then include the following information for each
such value for each parameter:
(A) Identification of the parameter;
(B) Default, maximum, minimum, or constant value, and units of
measure for the value;
(C) Purpose of the value;
(D) Indicator of use, i.e., during controlled hours, uncontrolled
hours, or all operating hours;
(E) Type of fuel;
(F) Source of the value;
(G) Value effective date and hour;
(H) Date and hour value is no longer effective (if applicable); and
(I) For units using the excepted methodology under Sec. 75.19, the
applicable SO2 emission factor.
(vii) Unless otherwise specified in section 6.5.2.1 of appendix A
to this part, for each unit or common stack on which hardware CEMS are
installed:
(A) Maximum hourly gross load (in MW, rounded to the nearest MW, or
steam load in 1000 lb/hr (i.e., klb/hr), rounded to the nearest klb/hr,
or thermal output in mmBtu/hr, rounded to the nearest mmBtu/hr), for
units that produce electrical or thermal output;
(B) The upper and lower boundaries of the range of operation (as
defined in section 6.5.2.1 of appendix A to this part), expressed in
megawatts, thousands of lb/hr of steam, mmBtu/hr of thermal output, or
ft/sec (as applicable);
(C) Except for peaking units, identify the most frequently and
second most frequently used load (or operating) levels (i.e., low, mid,
or high) in accordance with section 6.5.2.1 of appendix A to this part,
expressed in megawatts, thousands of lb/hr of steam, mmBtu/hr of
thermal output, or ft/sec (as applicable);
(D) Except for peaking units, an indicator of whether the second
most frequently used load (or operating) level is designated as normal
in section 6.5.2.1 of appendix A to this part;
(E) The date of the data analysis used to determine the normal load
(or operating) level(s) and the two most frequently-used load (or
operating) levels (as applicable); and
(F) Activation and deactivation dates and hours, when the maximum
hourly gross load, boundaries of the range of operation, normal load
(or operating) level(s) or two most frequently-used load (or operating)
levels change and are updated.
(viii) For each unit for which CEMS are not installed:
(A) Maximum hourly gross load (in MW, rounded to the nearest MW, or
steam load in klb/hr, rounded to the nearest klb/hr, or steam load in
mmBtu/hr, rounded to the nearest mmBtu/hr);
(B) The upper and lower boundaries of the range of operation (as
defined in section 6.5.2.1 of appendix A to this part), expressed in
megawatts, mmBtu/hr of thermal output, or thousands of lb/hr of steam;
(C) Except for peaking units and units using the low mass emissions
excepted methodology under Sec. 75.19, identify the load level
designated as normal, pursuant to section 6.5.2.1 of appendix A to this
part, expressed in megawatts, mmBtu/hr of thermal output, or thousands
of lb/hr of steam;
(D) The date of the load analysis used to determine the normal load
level (as applicable); and
(E) Activation and deactivation dates and hours, when the maximum
hourly gross load, boundaries of the range of
[[Page 49288]]
operation, or normal load level change and are updated.
(ix) For each unit with a flow monitor installed on a rectangular
stack or duct, if a wall effects adjustment factor (WAF) is determined
and applied to the hourly flow rate data:
(A) Stack or duct width at the test location, ft;
(B) Stack or duct depth at the test location, ft;
(C) Wall effects adjustment factor (WAF), to the nearest 0.0001;
(D) Method of determining the WAF;
(E) WAF Effective date and hour;
(F) WAF no longer effective date and hour (if applicable);
(G) WAF determination date;
(H) Number of WAF test runs;
(I) Number of Method 1 traverse points in the WAF test;
(J) Number of test ports in the WAF test; and
(K) Number of Method 1 traverse points in the reference flow RATA.
(2) Hardcopy.
(i) Information, including (as applicable): identification of the
test strategy; protocol for the relative accuracy test audit; other
relevant test information; calibration gas levels (percent of span) for
the calibration error test and linearity check; calculations for
determining maximum potential concentration, maximum expected
concentration (if applicable), maximum potential flow rate, maximum
potential NOX emission rate, and span; and apportionment
strategies under Sec. Sec. 75.10 through 75.18.
(ii) Description of site locations for each monitoring component in
the continuous emission or opacity monitoring systems, including
schematic diagrams and engineering drawings specified in paragraphs
(e)(2)(iv) and (e)(2)(v) of this section and any other documentation
that demonstrates each monitor location meets the appropriate siting
criteria.
(iii) A data flow diagram denoting the complete information
handling path from output signals of CEMS components to final reports.
(iv) For units monitored by a continuous emission or opacity
monitoring system, a schematic diagram identifying entire gas handling
system from boiler to stack for all affected units, using
identification numbers for units, monitoring systems and components,
and stacks corresponding to the identification numbers provided in
paragraphs (g)(1)(i) and (g)(1)(iii) of this section. The schematic
diagram must depict stack height and the height of any monitor
locations. Comprehensive and/or separate schematic diagrams shall be
used to describe groups of units using a common stack.
(v) For units monitored by a continuous emission or opacity
monitoring system, stack and duct engineering diagrams showing the
dimensions and location of fans, turning vanes, air preheaters, monitor
components, probes, reference method sampling ports, and other
equipment that affects the monitoring system location, performance, or
quality control checks.
(h) Contents of monitoring plan for specific situations. The
following additional information shall be included in the monitoring
plan for the specific situations described:
(1) For each gas-fired unit or oil-fired unit for which the owner
or operator uses the optional protocol in appendix D to this part for
estimating heat input and/or SO2 mass emissions, or for each
gas-fired or oil-fired peaking unit for which the owner/operator uses
the optional protocol in appendix E to this part for estimating
NOX emission rate (using a fuel flowmeter), the designated
representative shall include the following additional information for
each fuel flowmeter system in the monitoring plan:
(i) Electronic.
(A) Parameter monitored;
(B) Type of fuel measured, maximum fuel flow rate, units of
measure, and basis of maximum fuel flow rate (i.e., upper range value
or unit maximum) for each fuel flowmeter;
(C) Test method used to check the accuracy of each fuel flowmeter;
(D) Monitoring system identification code;
(E) The method used to demonstrate that the unit qualifies for
monthly GCV sampling or for daily or annual fuel sampling for sulfur
content, as applicable; and
(F) Activation date/hour and (if applicable) inactivation date/hour
for the fuel flowmeter system;
(ii) Hardcopy.
(A) A schematic diagram identifying the relationship between the
unit, all fuel supply lines, the fuel flowmeter(s), and the stack(s).
The schematic diagram must depict the installation location of each
fuel flowmeter and the fuel sampling location(s). Comprehensive and/or
separate schematic diagrams shall be used to describe groups of units
using a common pipe;
(B) For units using the optional default SO2 emission
rate for ``pipeline natural gas'' or ``natural gas'' in appendix D to
this part, the information on the sulfur content of the gaseous fuel
used to demonstrate compliance with either section 2.3.1.4 or 2.3.2.4
of appendix D to this part;
(C) For units using the 720 hour test under 2.3.6 of Appendix D of
this part to determine the required sulfur sampling requirements,
report the procedures and results of the test; and
(D) For units using the 720 hour test under 2.3.5 of Appendix D of
this part to determine the appropriate fuel GCV sampling frequency,
report the procedures used and the results of the test.
(2) For each gas-fired peaking unit and oil-fired peaking unit for
which the owner or operator uses the optional procedures in appendix E
to this part for estimating NOX emission rate, the
designated representative shall include in the monitoring plan:
(i) Electronic. Unit operating and capacity factor information
demonstrating that the unit qualifies as a peaking unit, as defined in
Sec. 72.2 of this chapter for the current calendar year or ozone
season, including: capacity factor data for three calendar years (or
ozone seasons) as specified in the definition of peaking unit in Sec.
72.2 of this chapter; the method of qualification used; and an
indication of whether the data are actual or projected data.
(ii) Hardcopy.
(A) A protocol containing methods used to perform the baseline or
periodic NOX emission test; and
(B) Unit operating parameters related to NOX formation
by the unit.
(3) For each gas-fired unit and diesel-fired unit or unit with a
wet flue gas pollution control system for which the designated
representative claims an opacity monitoring exemption under Sec.
75.14, the designated representative shall include in the hardcopy
monitoring plan the information specified under Sec. 75.14(b), (c), or
(d), demonstrating that the unit qualifies for the exemption.
(4) For each unit using the low mass emissions excepted methodology
under Sec. 75.19 the designated representative shall include the
following additional information in the monitoring plan that
accompanies the initial certification application:
(i) Electronic. For each low mass emissions unit, report the
results of the analysis performed to qualify as a low mass emissions
unit under Sec. 75.19(c). This report will include either the previous
three years actual or projected emissions. The following items should
be included:
(A) Current calendar year of application;
(B) Type of qualification;
(C) Years one, two, and three;
(D) Annual and/or ozone season measured, estimated or projected NOX
[[Page 49289]]
mass emissions for years one, two, and three;
(E) Annual measured, estimated or projected SO2 mass
emissions (if applicable) for years one, two, and three; and
(F) Annual or ozone season operating hours for years one, two, and
three.
(ii) Hardcopy.
(A) A schematic diagram identifying the relationship between the
unit, all fuel supply lines and tanks, any fuel flowmeter(s), and the
stack(s). Comprehensive and/or separate schematic diagrams shall be
used to describe groups of units using a common pipe;
(B) For units which use the long term fuel flow methodology under
Sec. 75.19(c)(3), the designated representative must provide a diagram
of the fuel flow to each affected unit or group of units and describe
in detail the procedures used to determine the long term fuel flow for
a unit or group of units for each fuel combusted by the unit or group
of units;
(C) A statement that the unit burns only gaseous fuel(s) and/or
fuel oil and a list of the fuels that are burned or a statement that
the unit is projected to burn only gaseous fuel(s) and/or fuel oil and
a list of the fuels that are projected to be burned;
(D) A statement that the unit meets the applicability requirements
in Sec. Sec. 75.19(a) and (b); and
(E) Any unit historical actual, estimated and projected emissions
data and calculated emissions data demonstrating that the affected unit
qualifies as a low mass emissions unit under Sec. Sec. 75.19(a) and
75.19(b).
(5) For qualification as a gas-fired unit, as defined in Sec. 72.2
of this part, the designated representative shall include in the
monitoring plan, in electronic format, the following: current calendar
year, fuel usage data for three calendar years (or ozone seasons) as
specified in the definition of gas-fired in Sec. 72.2 of this part,
the method of qualification used, and an indication of whether the data
are actual or projected data.
(6) For each monitoring location with a stack flow monitor that is
exempt from performing 3-load flow RATAs (peaking units, bypass stacks,
or by petition) the designated representative shall include in the
monitoring plan an indicator of exemption from 3-load flow RATA using
the appropriate exemption code.
22. Section 75.57 is amended by:
a. Adding the phrase ``, or mmBtu/hr of thermal output, rounded to
the nearest mmBtu/hr'' after the phrase ``rounded to the nearest 1000
lb/hr'', in paragraph (b)(3); and
b. Revising Table 4a in paragraph (c)(4)(iv).
The revisions and additions read as follows:
Sec. 75.57 General recordkeeping provisions.
* * * * *
(c) * * *
(4) * * *
(iv) * * *
Table 4a.--Codes for Method of Emissions and Flow Determination
------------------------------------------------------------------------
Hourly emissions/flow measurement or
Code estimation method
------------------------------------------------------------------------
1............................ Certified primary emission/flow
monitoring system.
2............................ Certified backup emission/flow monitoring
system.
3............................ Approved alternative monitoring system.
4............................ Reference method:
SO2: Method 6C.
Flow: Method 2 or its allowable
alternatives under appendix A to part 60
of this chapter.
NOX: Method 7E.
CO2 or O2: Method 3A.
5............................ For units with add-on SO2 and/or NOX
emission controls: SO2 concentration or
NOX emission rate estimate from Agency
preapproved parametric monitoring
method.
6............................ Average of the hourly SO2 concentrations,
CO2 concentrations, O2 concentrations,
NOX concentrations, flow rates, moisture
percentages or NOX emission rates for
the hour before and the hour following a
missing data period.
7............................ Initial missing data procedures used.
Either: (a) The average of the hourly
SO2 concentration, CO2 concentration, O2
concentration, or moisture percentage
for the hour before and the hour
following a missing data period; or (b)
the arithmetic average of all NOX
concentration, NOX emission rate, or
flow rate values at the corresponding
load range (or a higher load range), or
at the corresponding operational bin
(non-load-based units, only); or (c) the
arithmetic average of all previous NOX
concentration, NOX emission rate, or
flow rate values (non-load-based units,
only).
8............................ 90th percentile hourly SO2 concentration,
CO2 concentration, NOX concentration,
flow rate, moisture percentage, or NOX
emission rate or 10th percentile hourly
O2 concentration or moisture percentage
in the applicable lookback period
(moisture missing data algorithm depends
on which equations are used for
emissions and heat input).
9............................ 95th percentile hourly SO2 concentration,
CO2 concentration, NOX concentration,
flow rate, moisture percentage, or NOX
emission rate or 5th percentile hourly
O2 concentration or moisture percentage
in the applicable lookback period
(moisture missing data algorithm depends
on which equations are used for
emissions and heat input).
10........................... Maximum hourly SO2 concentration, CO2
concentration, NOX concentration, flow
rate, moisture percentage, or NOX
emission rate or minimum hourly O2
concentration or moisture percentage in
the applicable lookback period (moisture
missing data algorithm depends on which
equations are used for emissions and
heat input).
11........................... Average of hourly flow rates, NOX
concentrations or NOX emission rates in
corresponding load range, for the
applicable lookback period. For non-load-
based units, report either the average
flow rate, NOX concentration or NOX
emission rate in the applicable lookback
period, or the average flow rate or NOX
value at the corresponding operational
bin (if operational bins are used).
12........................... Maximum potential concentration of SO2,
maximum potential concentration of CO2,
maximum potential concentration of NOX
maximum potential flow rate, maximum
potential NOX emission rate, maximum
potential moisture percentage, minimum
potential O2 concentration or minimum
potential moisture percentage, as
determined using Sec. 72.2 of this
chapter and section 2.1 of appendix A to
this part (moisture missing data
algorithm depends on which equations are
used for emissions and heat input).
13........................... Maximum expected concentration of SO2,
maximum expected concentration of NOX,
maximum expected Hg concentration, or
maximum controlled NOX emission rate.
(See Sec. 75.34(a)(5)).
14........................... Diluent cap value (if the cap is
replacing a CO2 measurement, use 5.0
percent for boilers and 1.0 percent for
turbines; if it is replacing an O2
measurement, use 14.0 percent for
boilers and 19.0 percent for turbines).
[[Page 49290]]
15........................... 1.25 times the maximum hourly controlled
SO2 concentration, Hg concentration, NOX
concentration at the corresponding load
or operational bin, or NOX emission rate
at the corresponding load or operational
bin, in the applicable lookback period
(See Sec. 75.34(a)(5)).
16........................... SO2 concentration value of 2.0 ppm during
hours when only ``very low sulfur
fuel'', as defined in Sec. 72.2 of
this chapter, is combusted.
17........................... Like-kind replacement non-redundant
backup analyzer.
19........................... 200 percent of the MPC; default high
range value.
20........................... 200 percent of the full-scale range
setting (full-scale exceedance of high
range).
21........................... Negative hourly SO2 concentration, NOX
concentration, percent moisture, or NOX
emission rate replaced with zero.
22........................... Hourly average SO2 or NOX concentration,
measured by a certified monitor at the
control device inlet (units with add-on
emission controls only).
23........................... Maximum potential SO2 concentration, NOX
concentration, CO2 concentration, NOX
emission rate or flow rate, or minimum
potential O2 concentration or moisture
percentage, for an hour in which flue
gases are discharged through an
unmonitored bypass stack.
24........................... Maximum expected NOX concentration, or
maximum controlled NOX emission rate for
an hour in which flue gases are
discharged downstream of the NOX
emission controls through an unmonitored
bypass stack, and the add-on NOX
emission controls are confirmed to be
operating properly.
25........................... Maximum potential NOX emission rate
(MER). (Use only when a NOX
concentration full-scale exceedance
occurs and the diluent monitor is
unavailable.)
26........................... 1.0 mmBtu/hr substituted for Heat Input
Rate for an operating hour in which the
calculated Heat Input Rate is zero or
negative.
32........................... Hourly Hg concentration determined from
analysis of a single trap multiplied by
a factor of 1.222 when one of the paired
traps is invalidated or damaged (See
Appendix K Sec. 8).
33........................... Hourly Hg concentration determined from
the trap resulting in the higher Hg
concentration when the relative
deviation between the paired traps is
greater than 10 percent (See Appendix K
Sec. 8).
54........................... Other quality assured methodologies
approved through petition. These hours
are included in missing data lookback
and are treated as unavailable hours for
percent monitor availability
calculations.
55........................... Other substitute data approved through
petition. These hours are not included
in missing data lookback and are treated
as unavailable hours for percent monitor
availability calculations.
------------------------------------------------------------------------
* * * * *
23. Section 75.58 is amended by:
a. Revising paragraph (b)(3) introductory text;
b. Removing paragraphs (b)(3)(iii) and (b)(3)(iv);
c. Removing the word ``and'' from paragraph (c)(1)(xii);
d. Replacing the period with a semicolon and adding the word
``and'' to the end of the paragraph, in paragraph (c)(1)(xiii);
e. Adding paragraph (c)(1)(xiv);
f. Replacing the period with a semicolon and adding the word
``and'' to the end of the paragraph, in paragraph (c)(4)(x);
g. Adding paragraph (c)(4)(xi);
h. Replacing the period with a semicolon and adding the word
``and'' to the end of the paragraph, in paragraph (d)(1)(x);
i. Adding paragraph (d)(1)(xi);
j. Replacing the period with a semicolon and adding the word
``and'' to the end of the paragraph, in paragraph (d)(2)(x);
k. Adding paragraph (d)(2)(xi);
l. Revising paragraph (f)(1)(iii);
m. Removing the word ``and'' at the end of paragraph (f)(1)(xi);
n. Replacing the period with a semicolon at the end of paragraph
(f)(1)(xii);
o. Adding paragraphs (f)(1)(xiii) and (f)(1)(xiv); and
p. Replacing the word ``Component'' with the word ``Monitoring'',
in paragraph (f)(2)(x).
The revisions and additions read as follows:
Sec. 75.58 General recordkeeping provisions for specific situations.
* * * * *
(b) * * *
(3) Except as otherwise provided in Sec. 75.34(d), for units with
add-on SO2 or NOX emission controls following the
provisions of Sec. 75.34(a)(1), (a)(2), (a)(3) or (a)(5), and for
units with add-on Hg emission controls, the owner or operator shall record:
* * * * *
(c) * * *
(1) * * *
(xiv) Heat input formula ID and SO2 Formula ID (required
beginning January 1, 2009).
* * * * *
(4) * * *
(xi) Heat input formula ID and SO2 Formula ID (required
beginning January 1, 2009).
* * * * *
(d) * * *
(1) * * *
(xi) Heat input rate formula ID (required beginning January 1, 2009).
(2) * * *
(xi) Heat input rate formula ID (required beginning January 1, 2009).
* * * * *
(f) * * *
(1) * * *
(iii) Fuel type (pipeline natural gas, natural gas, other gaseous
fuel, residual oil, or diesel fuel). If more than one type of fuel is
combusted in the hour, either:
(A) Indicate the fuel type which results in the highest emission
factors for NOX (this option is in effect through December
31, 2008); or
(B) Indicate the fuel type resulting in the highest emission factor
for each parameter (SO2, NOX emission rate, and
CO2) separately (this option is required on and after
January 1, 2009);
* * * * *
(xiii) Base or peak load indicator (as applicable); and
(xiv) Multiple fuel flag.
* * * * *
24. Section 75.59 is amended by:
a. Adding the phrase ``(on and after January 1, 2009, only the
component identification code is required)'' after the word ``code'',
in paragraph (a)(1)(i);
b. Revising paragraph (a)(1)(viii);
c. Replacing the phrase ``For the qualifying test for off-line
calibration, the owner or operator shall indicate'' with the phrase
``Indication of'', in paragraph (a)(1)(xi);
d. Adding the phrase ``(after January 1, 2009, only the component
[[Page 49291]]
identification code is required)'' after the word ``code'', in
paragraph (a)(2)(i);
e. Adding the phrase ``(on and after January 1, 2009, only the
component identification code is required)'' after the word ``code'',
in paragraph (a)(3)(i);
f. Adding the phrase ``(only span scale is required on and after
January 1, 2009)'' after the word ``scale'', in paragraph (a)(3)(ii);
g. Adding the phrase ``(on and after January 1, 2009, only the
system identification code is required)'' after the word ``code'', in
paragraph (a)(4)(i);
h. Removing the word ``and'' after the semicolon at the end of
paragraph (a)(4)(vi)(L);
i. Replacing the period with a semicolon and adding the word
``and'' at the end of paragraph (a)(4)(vi)(M);
j. Adding paragraph (a)(4)(vi)(N);
k. Removing the word ``and'' after the semicolon, at the end of
paragraph (a)(4)(vii)(K);
l. Replacing the period with a semicolon and adding the word
``and'' at the end of paragraph (a)(4)(vii)(L);
m. Adding paragraph (a)(4)(vii)(M);
n. Revising paragraph (a)(6) introductory text;
o. Adding the phrase ``(on and after January 1, 2009, only the
component identification code is required)'' after the word ``code'',
in paragraph (a)(6)(i);
p. Replace the phrase ``Cycle time result for the entire system''
with the phrase ``Total cycle time'', in paragraph (a)(6)(ix);
q. Adding paragraphs (a)(7)(ix) and (a)(7)(x);
r. Revising paragraph (a)(8);
s. Removing and reserving paragraph (a)(12)(iii);
t. Removing the number ``(2)'' from the paragraph identifier
``Sec. 75.64(a)(2)'' in the second sentence of paragraph (a)(13);
u. Adding the phrase ``(on and after January 1, 2009, only the
component identification code is required)'' after the word ``tested'',
in paragraphs (b)(1)(ii) and (b)(2)(i);
v. Adding the phrase ``(on and after January 1, 2009, only the
monitoring system identification code is required)'' after the word
``code'', in paragraph (b)(4)(i)(A);
w. Removing the word ``and'' after the semicolon at the end of
paragraph (b)(4)(i)(H);
x. Replacing the period with a semicolon and adding the word
``and'' at the end of paragraph (b)(4)(i)(I);
y. Adding paragraph (b)(4)(i)(J);
z. Revising paragraphs (b)(4)(ii)(A), (b)(4)(ii)(B), and
(b)(4)(ii)(F);
aa. Removing the word ``and'' after the semicolon at the end of
paragraph (b)(4)(ii)(L);
bb. Replacing the period with a semicolon and adding the word
``and'' at the end of paragraph (b)(4)(ii)(M);
cc. Adding paragraph (b)(4)(ii)(N);
dd. Adding the phrase ``(on and after January 1, 2009, component
identification codes shall be reported in addition to the monitoring
system identification code)'' after the second occurrence of the word
``system'' in paragraphs (b)(5)(i)(B), (b)(5)(ii)(B), and
(b)(5)(iii)(B);
ee. Adding the phrase ``This requirement remains in effect through
December 31, 2008'' after the word ``run'', in paragraph (b)(5)(i)(H);
ff. Adding the phrase ``(as applicable). This requirement remains
in effect through December 31, 2008'' after the word ``level'', in
paragraph (b)(5)(iv)(A);
gg. Removing the word ``and'' after the semicolon at the end of
paragraph (b)(5)(iv)(G);
hh. Replacing the period with a semicolon and adding the word
``and'' at the end of paragraph (b)(5)(iv)(H);
ii. Adding paragraph (b)(5)(iv)(I);
jj. Removing the word ``and'' after the semicolon at the end of
paragraph (d)(1)(xi);
kk. Replacing the period with a semicolon and adding the word
``and'' at the end of paragraph (d)(1)(xii);
ll. Adding paragraph (d)(1)(xiii);
mm. Removing the phrase ``, multiplied by 1.15, if appropriate''
from paragraph (d)(2)(iii);
nn. Removing the word ``and'' after the semicolon at the end of
paragraph (d)(2)(iv);
oo. Replacing the period with a semicolon at the end of paragraph
(d)(2)(v); and
pp. Adding paragraphs (d)(2)(vi), (d)(2)(vii), (e) and (f).
The revisions and additions read as follows:
Sec. 75.59 Certification, quality, assurance, and quality control
record provisions.
* * * * *
(a) * * *
(1) * * *
(viii) For 7-day calibration error tests, a test number and reason
for test;
* * * * *
(4) * * *
(vi) * * *
(N) Test number.
(vii) * * *
(M) An indicator (``flag'') if separate reference ratios are
calculated for each multiple stack.
* * * * *
(6) For each SO2, NOX, Hg, or CO2
pollutant concentration monitor, each component of a NOX-
diluent continuous emission monitoring system, and each CO2
or O2 monitor used to determine heat input, the owner or
operator shall record the following information for the cycle time test:
* * * * *
(7) * * *
(ix) For a unit with a flow monitor installed on a rectangular
stack or duct, if a site-specific default or measured wall effects
adjustment factor (WAF) is used to correct the stack gas volumetric
flow rate data to account for velocity decay near the stack or duct
wall, the owner or operator shall keep records of the following for
each flow RATA performed with EPA Method 2, subsequent to the WAF
determination:
(A) Monitoring system ID;
(B) Test number;
(C) Operating level;
(D) RATA end date and time;
(E) Number of Method 1 traverse points; and
(F) Wall effects adjustment factor (WAF), to the nearest 0.0001.
(x) For each RATA run using Method 29 to determine Hg concentration:
(A) Percent CO2 and O2 in the stack gas, dry
basis;
(B) Moisture content of the stack gas (percent H2O);
(C) Average stack gas temperature ([deg]F);
(D) Dry gas volume metered (dscm);
(E) Percent isokinetic;
(F) Particulate Hg collected in the front half of the sampling
train, corrected for the front-half blank value ([mu]g); and
(G) Total vapor phase Hg collected in the back half of the sampling
train, corrected for the back-half blank value ([mu]g).
(8) For each certified continuous emission monitoring system,
continuous opacity monitoring system, excepted monitoring system, or
alternative monitoring system, the date and description of each event
which requires certification, recertification, or certain diagnostic
testing of the system and the date and type of each test performed. If
the conditional data validation procedures of Sec. 75.20(b)(3) are to
be used to validate and report data prior to the completion of the
required certification, recertification, or diagnostic testing, the
date and hour of the probationary calibration error test shall be
reported to mark the beginning of conditional data validation.
* * * * *
(b) * * *
(4) * * *
(i) * * *
(J) Test number.
(ii) * * *
(A) Completion date and hour of most recent primary element
inspection or
[[Page 49292]]
test number of the most recent primary element inspection (as
applicable); (on and after January 1, 2009, the test number of the most
recent primary element inspection is required in lieu of the completion
date and hour for the most recent primary element inspection);
(B) Completion date and hour of most recent flow meter of
transmitter accuracy test or test number of the most recent flowmeter
or transmitter accuracy test (as applicable); (on and after January 1,
2009, the test number of the most recent flowmeter or transmitter
accuracy test is required in lieu of the completion date and hour for
the most recent flowmeter or transmitter accuracy test);
* * * * *
(F) Average load, in megawatts, 1000 lb/hr of steam, or mmBtu/hr
thermal output;
* * * * *
(N) Monitoring system identification code. * * *
* * * * *
(5) * * *
(iv) * * *
(I) Component identification code (required on and after January 1,
2009).
* * * * *
(d) * * *
(1) * * *
(xiii) An indicator (``flag'') if the run is used to calculate the
highest 3-run average NOX emission rate at any load level.
(2) * * *
(vi) Indicator of whether the testing was done at base load, peak
load or both (if appropriate); and
(vii) The default NOX emission rate for peak load hours
(if applicable).
* * * * *
(e) Excepted monitoring for Hg low mass emission units under Sec.
75.81(b). For qualifying coal-fired units using the alternative low
mass emission methodology under Sec. 75.81(b), the owner or operator
shall record the data elements described in Sec. 75.59(a)(7)(vii),
Sec. 75.59(a)(7)(viii), or Sec. 75.59(a)(7)(x), as applicable, for
each run of each Hg emission test and re-test required under Sec.
75.81(c)(1) or Sec. 75.81(d)(4)(iii).
(f) DAHS Verification. For each DAHS (missing data and formula)
verification that is required for initial certification,
recertification, or for certain diagnostic testing of a monitoring
system, record the date and hour that the DAHS verification is
successfully completed. (This requirement only applies to units that
report monitoring plan data in accordance with Sec. 75.53(g) and (h).)
* * * * *
25. Section 75.60 is amended by adding paragraph (b)(8) to read as
follows:
Sec. 75.60 General provisions.
* * * * *
(b) * * *
(8) Routine retest reports for Hg low mass emissions units. If
requested in writing (or by electronic mail) by the applicable EPA
Regional Office, appropriate State, and/or appropriate local air
pollution control agency, the designated representative shall submit a
hardcopy report for a semiannual or annual retest required under Sec.
75.81(d)(4)(iii) for a Hg low mass emissions unit, within 45 days after
completing the test or within 15 days of receiving the request,
whichever is later. The designated representative shall report, at a
minimum, the following hardcopy information to the applicable EPA
Regional Office, appropriate State, and/or appropriate local air
pollution control agency that requested the hardcopy report: A summary
of the test results; the raw reference method data for each test run;
the raw data and results of all pretest, post-test, and post-run
quality-assurance checks of the reference method; the raw data and
results of moisture measurements made during the test runs (if
applicable); diagrams illustrating the test and sample point locations;
a copy of the test protocol used; calibration certificates for the gas
standards or standard solutions used in the testing; laboratory
calibrations of the source sampling equipment; and the names of the key
personnel involved in the test program, including test team members,
plant contact persons, agency representatives and test observers.
* * * * *
26. Section 75.61 is amended by:
a. Revising the first sentence of paragraph (a)(1) introductory text;
b. Revising paragraph (a)(3);
c. Revising the first sentence of paragraph (a)(5) introductory
text; and
d. Adding paragraphs (a)(7) and (a)(8)
The revisions and additions read as follows:
Sec. 75.61 Notifications.
(a) * * *
(1) Initial certification and recertification test notifications.
The owner or operator or designated representative for an affected unit
shall submit written notification of initial certification tests and
revised test dates as specified in Sec. 75.20 for continuous emission
monitoring systems, for the excepted Hg monitoring methodology under
Sec. 75.81(b), for alternative monitoring systems under subpart E of
this part, or for excepted monitoring systems under appendix E to this
part, except as provided in paragraphs (a)(1)(iii), (a)(1)(iv) and
(a)(4) of this section.* * *
* * * * *
(3) Unit shutdown and recommencement of commercial operation. For
an affected unit that will be shutdown on the relevant compliance date
specified in Sec. 75.4 or in a State or Federal pollutant mass
emissions reduction program that adopts the monitoring and reporting
requirements of this part, if the owner or operator is relying on the
provisions in Sec. 75.4(d) to postpone certification testing, the
designated representative for the unit shall submit notification of
unit shutdown and recommencement of commercial operation as follows:
(i) For planned unit shutdowns (e.g., extended maintenance
outages), written notification of the planned shutdown date shall be
provided at least 21 days prior to the applicable compliance date, and
written notification of the planned date of recommencement of
commercial operation shall be provided at least 21 days in advance of
unit restart. If the actual shutdown date or the actual date of
recommencement of commercial operation differs from the planned date,
written notice of the actual date shall be submitted no later than 7
days following the actual date of shutdown or of recommencement of
commercial operation, as applicable;
(ii) For unplanned unit shutdowns (e.g., forced outages), written
notification of the actual shutdown date shall be provided no more than
7 days after the shutdown, and written notification of the planned date
of recommencement of commercial operation shall be provided at least 21
days in advance of unit restart. If the actual date of recommencement
of commercial operation differs from the expected date, written notice
of the actual date shall be submitted no later than 7 days following
the actual date of recommencement of commercial operation.
* * * * *
(5) Periodic relative accuracy test audits, appendix E retests, and
low mass emissions unit retests. The owner or operator or designated
representative of an affected unit shall submit written notice of the
date of periodic relative accuracy testing performed under section
2.3.1 of appendix B to this part, of periodic retesting performed under
section 2.2 of appendix E to this part, of periodic retesting of low
mass emissions units performed under Sec. 75.19(c)(1)(iv)(D), and of
periodic
[[Page 49293]]
retesting of Hg low mass emissions units performed under Sec.
75.81(d)(4)(iii), no later than 21 days prior to the first scheduled
day of testing. * * *
* * * * *
(7) Long-term cold storage and recommencement of commercial
operation. The designated representative for an affected unit that is
placed into long-term cold storage that is relying on the provisions in
Sec. 75.4(d) or Sec. 75.64(a), either to postpone certification
testing or to discontinue the submittal of quarterly reports during the
period of long-term cold storage, shall provide written notification of
long-term cold storage status and recommencement of commercial
operation as follows:
(i) Whenever an affected unit has been placed into long-term cold
storage, written notification of the date and hour that the unit was
shutdown and a statement from the designated representative stating
that the shutdown is expected to last for at least two years from that
date, in accordance with the definition for long-term cold storage of a
unit as provided in Sec. 72.2.
(ii) Whenever an affected unit that has been placed into long-term
cold storage is expected to resume operation, written notification
shall be submitted 45 calendar days prior to the planned date of
recommencement of commercial operation. If the actual date of
recommencement of commercial operation differs from the expected date,
written notice of the actual date shall be submitted no later than 7
days following the actual date of recommencement of commercial operation.
(8) Certification deadline date for new or newly affected units.
The designated representative of a new or newly affected unit shall
provide notification of the date on which the relevant deadline for
initial certification is reached, either as provided in Sec. 75.4(b)
or Sec. 75.4(c), or as specified in a State or Federal SO2,
NOX, or Hg mass emission reduction program that incorporates
by reference, or otherwise adopts, the monitoring, recordkeeping, and
reporting requirements of subpart F, G, H, or I of this part. The
notification shall be submitted no later than 7 calendar days after the
applicable certification deadline is reached.
* * * * *
27. Section 75.62 is amended by:
a. Revising paragraph (a)(1); and
b. Replacing the number ``45'' with the number ``21'' before the
phrase ``days prior'', in paragraph (a)(2).
The revisions and additions read as follows:
Sec. 75.62 Monitoring plan submittals.
(a) * * *
(1) Electronic. Using the format specified in paragraph (c) of this
section, the designated representative for an affected unit shall
submit a complete, electronic, up-to-date monitoring plan file (except
for hardcopy portions identified in paragraph (a)(2) of this section)
to the Administrator as follows: no later than 21 days prior to the
initial certification tests; at the time of each certification or
recertification application submission; and (prior to or concurrent
with) the submittal of the electronic quarterly report for a reporting
quarter where an update of the electronic monitoring plan information
is required, either under Sec. 75.53(b) or elsewhere in this part.
* * * * *
28. Section 75.63 is amended by:
a. Removing the phrase ``and a hardcopy certification application
form (EPA form 7610-14)'' from paragraph (a)(1)(i)(A);
b. Revising paragraph (a)(1)(ii)(A);
c. Adding the phrase ``or Sec. 75.53(h)(4)(ii) (as applicable)''
after the identifier ``Sec. 75.53(f)(5)(ii)'', in paragraph (a)(1)(ii)(B);
d. Removing the phrase ``and a hardcopy certification application
form (EPA form 7610-14)'' after the word ``section'', in paragraph
(a)(2)(i);
e. Revising paragraph (a)(2)(iii);
f. Removing and reserving paragraph (b)(2)(iii);
g. Revising paragraph (b)(2)(iv) by adding the words ``certifying
the accuracy of the submission'' after the word ``signature''.
The revisions read as follows:
Sec. 75.63 Initial Certification or Recertification Application.
(a) * * *
(1) * * *
(ii) * * *
(A) To the Administrator, the electronic low mass emission
qualification information required by Sec. 75.53(f)(5)(i) or Sec.
75.53(h)(4)(i) (as applicable) and paragraph (b)(1)(i) of this section;
and
* * * * *
(2) * * *
(iii) Notwithstanding the requirements of paragraphs (a)(2)(i) and
(a)(2)(ii) of this section, for an event for which the Administrator
determines that only diagnostic tests (see Sec. 75.20(b)) are required
rather than recertification testing, no hardcopy submittal is required;
however, the results of all diagnostic test(s) shall be submitted prior
to or concurrent with the electronic quarterly report required under
Sec. 75.64. Notwithstanding the requirement of Sec. 75.59(e), for
DAHS (missing data and formula) verifications, no hardcopy submittal is
required; the owner or operator shall keep these test results on-site
in a format suitable for inspection.
* * * * *
29. Section 75.64 is amended by:
a. Revising paragraph (a) introductory text;
b. Revising paragraph (a)(2)(xiv);
c. Removing paragraph (a)(8);
d. Redesignating paragraphs (a)(3) through (a)(7) as paragraphs
(a)(8) through (a)(12), and redesignating paragraphs (a)(9) through
(a)(11) as paragraphs (a)(13) through (a)(15);
e. Adding new paragraphs (a)(3) through (a)(7); and
f. Replacing the citation ``Sec. 75.59'', with ``Sec.
75.58(f)(2)'' at the end of newly designated paragraph (a)(14).
The revisions and additions read as follows:
Sec. 75.64 Quarterly reports.
(a) Electronic submission. The designated representative for an
affected unit shall electronically report the data and information in
paragraphs (a), (b), and (c) of this section to the Administrator
quarterly, beginning with the data from the earlier of the calendar
quarter corresponding to the date of provisional certification or the
calendar quarter corresponding to the relevant deadline for initial
certification in Sec. 75.4(a), (b), or (c). The initial quarterly
report shall contain hourly data beginning with the hour of provisional
certification or the hour corresponding to the relevant certification
deadline, whichever is earlier. For an affected unit subject to Sec.
75.4(d) that is shutdown on the relevant compliance date in Sec.
75.4(a) or has been placed in long-term cold storage (as defined in
Sec. 72.2 of this chapter), quarterly reports are not required. In
such cases, the owner or operator shall submit quarterly reports for
the unit beginning with the data from the quarter in which the unit
recommences commercial operation (where the initial quarterly report
contains hourly data beginning with the first hour of recommenced
commercial operation of the unit). For units placed into long-term cold
storage during a reporting quarter, the exemption from submitting
quarterly reports begins with the calendar quarter following the date
that the unit is placed into long-term cold storage. For any
provisionally-certified monitoring system, Sec. 75.20(a)(3) shall
apply for initial certifications, and Sec. 75.20(b)(5) shall apply for
recertifications. Each electronic report must be submitted to
[[Page 49294]]
the Administrator within 30 days following the end of each calendar
quarter. Prior to January 1, 2008, each electronic report shall include
for each affected unit (or group of units using a common stack), the
information provided in paragraphs (a)(1), (a)(2), and (a)(8) through
(a)(15) of this section. During the time period of January 1, 2008 to
January 1, 2009, each electronic report shall include either the
information provided in paragraphs (a)(1), (a)(2), and (a)(8) through
(a)(15) of this section or the information provided in paragraphs
(a)(3) through (a)(15). On and after January 1, 2009, the owner or
operator shall meet the requirements of paragraphs (a)(3) through
(a)(15) of this section only. Each electronic report shall also include
the date of report generation.
* * * * *
(2) * * *
(xiii) Supplementary RATA information required under Sec.
75.59(a)(7), except that:
(A) The applicable data elements under Sec. 75.59(a)(7)(ii)(A)
through (T) and under Sec. 75.59(a)(7)(iii)(A) through (M) shall be
reported for flow RATAs at circular or rectangular stacks (or ducts) in
which angular compensation for yaw and/or pitch angles is used (i.e.,
Method 2F or 2G), with or without wall effects adjustments;
(B) The applicable data elements under Sec. 75.59(a)(7)(ii)(A)
through (T) and under Sec. 75.59(a)(7)(iii)(A) through (M) shall be
reported for any flow RATA run at a circular stack in which Method 2 is
used and a wall effects adjustment factor is determined by direct
measurement;
(C) The data under Sec. 75.59(a)(7)(ii)(T) shall be reported for
all flow RATAs at circular stacks in which Method 2 is used and a
default wall effects adjustment factor is applied; and
(D) The data under Sec. 75.59(a)(7)(ix)(A) through (F) shall be
reported for all flow RATAs at rectangular stacks or ducts in which
Method 2 is used and a wall effects adjustment factor is applied.
(3) Facility identification information, including:
(i) Facility/ORISPL number;
(ii) Calendar quarter and year for the data contained in the report; and
(iii) Version of the electronic data reporting format used for the
report.
(4) In accordance with Sec. 75.62(a)(1), if any monitoring plan
information required in Sec. 75.53 requires an update, either under
Sec. 75.53(b) or elsewhere in this part, submission of the electronic
monitoring plan update shall be completed prior to or concurrent with
the submittal of the quarterly electronic data report for the
appropriate quarter in which the update is required.
(5) Except for the daily calibration error test data, daily
interference check, and off-line calibration demonstration information
required in Sec. 75.59(a)(1) and (2), which must always be submitted
with the quarterly report, the certification, quality assurance, and
quality control information required in Sec. 75.59 shall either be
submitted prior to or concurrent with the submittal of the relevant
quarterly electronic data report.
(6) The information and hourly data required in Sec. Sec. 75.57
through 75.59, and daily calibration error test data, daily
interference check, and off-line calibration demonstration information
required in Sec. 75.59(a)(1) and (2).
(7) Notwithstanding the requirements of paragraphs (a)(4) through
(a)(6) of this section, the following information is excluded from
electronic reporting:
(i) Descriptions of adjustments, corrective action, and maintenance;
(ii) Information which is incompatible with electronic reporting
(e.g., field data sheets, lab analyses, quality control plan);
(iii) Opacity data listed in Sec. 75.57(f), and in Sec.
75.59(a)(8);
(iv) For units with SO2 or NOX add-on
emission controls that do not elect to use the approved site-specific
parametric monitoring procedures for calculation of substitute data,
the information in Sec. 75.58(b)(3);
(v) Information required by Sec. 75.57(h) concerning the causes of
any missing data periods and the actions taken to cure such causes;
(vi) Hardcopy monitoring plan information required by Sec. 75.53
and hardcopy test data and results required by Sec. 75.59;
(vii) Records of flow monitor and moisture monitoring system
polynomial equations, coefficients, or ``K'' factors required by Sec.
75.59(a)(5)(vi) or Sec. 75.59(a)(5)(vii);
(viii) Daily fuel sampling information required by Sec.
75.58(c)(3)(i) for units using assumed values under appendix D;
(ix) Information required by Sec. Sec. 75.59(b)(1)(vi), (vii),
(viii), (ix), and (xiii), and (b)(2)(iii) and (iv) concerning fuel
flowmeter accuracy tests and transmitter/transducer accuracy tests;
(x) Stratification test results required as part of the RATA
supplementary records under Sec. 75.59(a)(7);
(xi) Data and results of RATAs that are aborted or invalidated due
to problems with the reference method or operational problems with the
unit and data and results of linearity checks that are aborted or
invalidated due to problems unrelated to monitor performance; and
(xii) Supplementary RATA information required under Sec.
75.59(a)(7)(i) through Sec. 75.59(a)(7)(v), except that:
(A) The applicable data elements under Sec. 75.59(a)(7)(ii)(A)
through (T) and under Sec. 75.59(a)(7)(iii)(A) through (M) shall be
reported for flow RATAs at circular or rectangular stacks (or ducts) in
which angular compensation for yaw and/or pitch angles is used (i.e.,
Method 2F or 2G), with or without wall effects adjustments;
(B) The applicable data elements under Sec. 75.59(a)(7)(ii)(A)
through (T) and under Sec. 75.59(a)(7)(iii)(A) through (M) shall be
reported for any flow RATA run at a circular stack in which Method 2 is
used and a wall effects adjustment factor is determined by direct
measurement;
(C) The data under Sec. 75.59(a)(7)(ii)(T) shall be reported for
all flow RATAs at circular stacks in which Method 2 is used and a
default wall effects adjustment factor is applied; and
(D) The data under Sec. 75.59(a)(7)(vii)(A) through (F) shall be
reported for all flow RATAs at rectangular stacks or ducts in which
Method 2 is used and a wall effects adjustment factor is applied.
* * * * *
Sec. 75.66 [Amended]
30. Section 75.66 is amended by removing and reserving paragraph (f).
31. Section 75.71 is amended by:
a. In paragraph (a)(1), by replacing the second occurrence of the
phrase ``CO2 diluent gas monitor'' with the phrase
``CO2 diluent gas monitoring system'';
b. Replacing the phrase ``O2 or CO2 diluent
gas monitor'' with the phrase ``O2 or CO2
monitoring system'', in paragraph (a)(2); and
c. Revising paragraph (e).
The revision reads as follows:
Sec. 75.71 Specific provisions for monitoring NOX and heat
input for the purpose of calculating NOX mass emissions.
* * * * *
(e) Low mass emissions units. Notwithstanding the requirements of
paragraphs (c) and (d) of this section, for an affected unit using the
low mass emissions (LME) unit under Sec. 75.19 to estimate hourly
NOX emission rate, heat input and NOX mass
emissions, the owner or operator shall calculate the ozone season
NOX mass emissions by summing all of the estimated hourly
NOX mass emissions in the ozone season, as determined under
[[Page 49295]]
Sec. 75.19(c)(4)(ii)(A), and dividing this sum by 2000 lb/ton.
* * * * *
32. Section 75.72 is amended by:
a. Revising the section heading and the introductory text; and
b. Removing and reserving paragraph (f).
The revisions read as follows:
Sec. 75.72 Determination of NOX mass emissions for common
stack and multiple stack configurations.
The owner or operator of an affected unit shall either: calculate
hourly NOX mass emissions (in lbs) by multiplying the hourly
NOX emission rate (in lbs/mmBtu) by the hourly heat input
rate (in mmBtu/hr) and the unit or stack operating time (as defined in
Sec. 72.2); or, as provided in paragraph (e) of this section,
calculate hourly NOX mass emissions from the hourly
NOX concentration (in ppm) and the hourly stack flow rate
(in scfh). Only one methodology for determining NOX mass
emissions shall be identified in the monitoring plan for each
monitoring location at any given time. The owner or operator shall also
calculate quarterly and cumulative year-to-date NOX mass
emissions and cumulative NOX mass emissions for the ozone
season (in tons) by summing the hourly NOX mass emissions
according to the procedures in section 8 of appendix F to this part.
* * * * *
(f) [Reserved]
* * * * *
33. Section 75.73 is amended by:
a. Revising paragraph (c)(3);
b. Replacing the number ``45'' with the number ``21'' in paragraphs
(e)(1) and (e)(2);
c. Revising paragraph (f)(1) introductory text;
d. Replacing the phrase ``paragraph (a)'' with the phrase
``paragraphs (a) and (b)'' in paragraph (f)(1)(ii) introductory text;
and
e. Revising paragraph (f)(1)(ii)(K).
The revisions read as follows:
Sec. 75.73 Recordkeeping and reporting.
* * * * *
(c) * * *
(3) Contents of the monitoring plan for units not subject to an
Acid Rain emissions limitation. Prior to January 1, 2009, each
monitoring plan shall contain the information in Sec. 75.53(e)(1) or
Sec. 75.53(g)(1) in electronic format and the information in Sec.
75.53(e)(2) or Sec. 75.53(g)(2) in hardcopy format. On and after
January 1, 2009, each monitoring plan shall contain the information in
Sec. 75.53(g)(1) in electronic format and the information in Sec.
75.53(g)(2) in hardcopy format, only. In addition, to the extent
applicable, prior to January 1, 2009, each monitoring plan shall
contain the information in Sec. 75.53(f)(1)(i), (f)(2)(i), and (f)(4)
or Sec. 75.53(h)(1)(i), and (h)(2)(i) in electronic format and the
information in Sec. 75.53(f)(1)(ii) and (f)(2)(ii) or Sec.
75.53(h)(1)(ii) and (h)(2)(ii) in hardcopy format. On and after January
1, 2009, each monitoring plan shall contain the information in Sec.
75.53(h)(1)(i), and (h)(2)(i) in electronic format and the information
in Sec. 75.53(h)(1)(ii) and (h)(2)(ii) in hardcopy format, only. For
units using the low mass emissions excepted methodology under Sec.
75.19, prior to January 1, 2009, the monitoring plan shall include the
additional information in Sec. 75.53(f)(5)(i) and (f)(5)(ii) or Sec.
75.53(h)(4)(i) and (h)(4)(ii). On and after January 1, 2009, for units
using the low mass emissions excepted methodology under Sec. 75.19 the
monitoring plan shall include the additional information in Sec.
75.53(h)(4)(i) and (h)(4)(ii), only. Prior to January 1, 2008, the
monitoring plan shall also identify, in electronic format, the
reporting schedule for the affected unit (ozone season or quarterly),
and the beginning and end dates for the reporting schedule. The
monitoring plan also shall include a seasonal controls indicator, and
an ozone season fuel-switching flag.
* * * * *
(f) * * *
(1) Electronic submission. The designated representative for an
affected unit shall electronically report the data and information in
this paragraph (f)(1) and in paragraphs (f)(2) and (3) of this section
to the Administrator quarterly, unless the unit has been placed in
long-term cold storage (as defined in Sec. 72.2 of this chapter). For
units placed into long-term cold storage during a reporting quarter,
the exemption from submitting quarterly reports begins with the
calendar quarter following the date that the unit is placed into long-
term cold storage. In such cases, the owner or operator shall submit
quarterly reports for the unit beginning with the data from the quarter
in which the unit recommences operation (where the initial quarterly
report contains hourly data beginning with the first hour of
recommenced operation of the unit). Each electronic report must be
submitted to the Administrator within 30 days following the end of each
calendar quarter. Except as otherwise provided in Sec. Sec.
75.64(a)(4) and (a)(5), each electronic report shall include the
information provided in paragraphs (f)(1)(i) through (1)(vi) of this
section, and shall also include the date of report generation. Prior to
January 1, 2009, each report shall include the facility information
provided in paragraphs (f)(1)(i)(A) and (B), for each affected unit or
group of units monitored at a common stack. On and after January 1,
2009, only the facility identification information provided in
paragraph (f)(1)(i)(A) is required.
* * * * *
(ii) * * *
(K) Supplementary RATA information required under Sec.
75.59(a)(7), except that:
(1) The applicable data elements under Sec. 75.59(a)(7)(ii)(A)
through (T) and under Sec. 75.59(a)(7)(iii)(A) through (M) shall be
reported for flow RATAs at circular or rectangular stacks (or ducts) in
which angular compensation for yaw and/or pitch angles is used (i.e.,
Method 2F or 2G), with or without wall effects adjustments;
(2) The applicable data elements under Sec. 75.59(a)(7)(ii)(A)
through (T) and under Sec. 75.59(a)(7)(iii)(A) through (M) shall be
reported for any flow RATA run at a circular stack in which Method 2 is
used and a wall effects adjustment factor is determined by direct
measurement;
(3) The data under Sec. 75.59(a)(7)(ii)(T) shall be reported for
all flow RATAs at circular stacks in which Method 2 is used and a
default wall effects adjustment factor is applied; and
(4) The data under Sec. 75.59(a)(7)(ix)(A) through (F) shall be
reported for all flow RATAs at rectangular stacks or ducts in which
Method 2 is used and a wall effects adjustment factor is applied.
* * * * *
34. Section 75.74 is amended by:
a. Replacing the phrase ``In the time period to the start of the
current ozone season (i.e., in the period extending from October 1 of
the previous calendar year through April 30 of the current calendar
year), the'', with the word ``The'', in paragraph (c)(2) introductory text;
b. Adding the words ``in the second calendar quarter no later than
April 30'' to the end of paragraph (c)(2)(i) introductory text;
c. Removing the phrase ``of the current calendar year'' from the
first sentence, and removing the last sentence of paragraph
(c)(2)(i)(C);
d. Revising paragraph (c)(2)(i)(D);
e. Adding the words ``in the first or second calendar quarter, but
no later than April 30'' to the end of the first sentence, and by
removing the second sentence of paragraph (c)(2)(ii) introductory text;
f. Removing the words ``of the current calendar year'' from
paragraph (c)(2)(ii)(E);
[[Page 49296]]
g. Revising paragraph (c)(2)(ii)(F);
h. Removing paragraphs (c)(2)(ii)(G) and (c)(2)(ii)(H);
i. Revising paragraph (c)(3)(ii);
j. Removing and reserving paragraphs (c)(3)(vi) through (viii);
k. Replacing all occurrences of the words ``Sec. 75.31, Sec.
75.33, or Sec. 75.37'' with the words ``Sec. Sec. 75.31 through
75.37'' in paragraphs (c)(3)(xi), (c)(3)(xii)(A), and (c)(3)(xii)(B);
l. Revising paragraph (c)(6)(iii);
m. Replacing the words ``October 1 of the previous calendar year''
with ``January 1'' in paragraph (c)(6)(v); and
n. Revising paragraph (c)(11).
The revisions and additions read as follows:
Sec. 75.74 Annual and ozone season monitoring and reporting requirements.
* * * * *
(c) * * *
(2) * * *
(i) * * *
(D) If the linearity check is not completed by April 30, data
validation shall be determined in accordance with paragraph
(c)(3)(ii)(E) of this section.
(ii) * * *
(F) Data Validation. For each RATA that is performed by April 30,
data validation shall be done according to sections 2.3.2(a)-(j) of
appendix B to this part. However, if a required RATA is not completed
by April 30, data from the monitoring system shall be invalid,
beginning with the first unit operating hour on or after May 1. The
owner or operator shall continue to invalidate all data from the CEMS
until either:
(1) The required RATA of the CEMS has been performed and passed; or
(2) A probationary calibration error test of the CEMS is passed in
accordance with Sec. 75.20(b)(3)(ii). Once the probationary
calibration error test has been passed, the owner or operator shall
perform the required RATA in accordance with the conditional data
validation provisions and within the 720 unit or stack operating hour
time frame specified in Sec. 75.20(b)(3) (subject to the restrictions
in paragraph (c)(3)(xii) of this section), and the term ``quality
assurance'' shall apply instead of the term ``recertification.''
However, in lieu of the provisions in Sec. 75.20(b)(3)(ix), the owner
or operator shall follow the applicable provisions in paragraphs
(c)(3)(xi) and (c)(3)(xii) of this section.
(3) * * *
(ii) For each gas monitor required by this subpart, linearity
checks shall be performed in the second and third calendar quarters, as
follows:
(A) For the second calendar quarter, the pre-ozone season linearity
check required under paragraph (c)(2)(i) of this section shall be
performed by April 30.
(B) For the third calendar quarter, a linearity check shall be
performed and passed no later than July 30.
(C) Conduct each linearity check in accordance with the general
procedures in section 6.2 of appendix A to this part, except that the
data validation procedures in sections 6.2(a) through (f) of appendix A
do not apply.
(D) Each linearity check shall be done ``hands-off,'' as described
in section 2.2.3(c) of appendix B to this part.
(E) Data Validation. For second and third quarter linearity checks
performed by the applicable deadline (i.e., April 30 or July 30), data
validation shall be done in accordance with sections 2.2.3(a), (b),
(c), (e), and (h) of Appendix B to this part. However, if a required
linearity check for the second calendar quarter is not completed by
April 30, or if a required linearity check for the third calendar
quarter is not completed by July 30, data from the monitoring system
(or range) shall be invalid, beginning with the first unit operating
hour on or after May 1 or July 31, respectively. The owner or operator
shall continue to invalidate all data from the CEMS until either:
(1) The required linearity check of the CEMS has been performed and
passed; or
(2) A probationary calibration error test of the CEMS is passed in
accordance with Sec. 75.20(b)(3)(ii). Once the probationary
calibration error test has been passed, the owner or operator shall
perform the required linearity check in accordance with the conditional
data validation provisions and within the 168 unit or stack operating
hour time frame specified in Sec. 75.20(b)(3) (subject to the
restrictions in paragraph (c)(3)(xii) of this section), and the term
``quality assurance'' shall apply instead of the term
``recertification.'' However, in lieu of the provisions in Sec.
75.20(b)(3)(ix), the owner or operator shall follow the applicable
provisions in paragraphs (c)(3)(xi) and (c)(3)(xii) of this section.
(F) A pre-season linearity check performed and passed in April
satisfies the linearity check requirement for the second quarter.
(G) The third quarter linearity check requirement in paragraph
(c)(3)(ii)(B) of this section is waived if:
(1) Due to infrequent unit operation, the 168 operating hour
conditional data validation period associated with a pre-season
linearity check extends into the third quarter; and
(2) A linearity check is performed and passed within that
conditional data validation period.
* * * * *
(6) * * *
(iii) For the time periods described in paragraphs (c)(2)(i)(C) and
(c)(2)(ii)(E) of this section, hourly emission data and the results of
all daily calibration error tests and flow monitor interference checks
shall be recorded. The results of all daily calibration error tests and
flow monitor interference checks performed in the time period from
April 1 through April 30 shall be reported. The owner or operator shall
also report unit operating data recorded in the time period from April
1 through April 30 beginning with the day of the first required daily
calibration error test or flow monitor interference check performed
whenever the XML reporting format is used. The owner or operator may
also report the hourly emission data in the time period from April 1
through April 30. However, only the emission data recorded in the time
period from May 1 through September 30 shall be used for NOX
mass compliance determination;
* * * * *
(11) Units may qualify to use the optional NOX mass
emissions estimation protocol for gas-fired and oil-fired peaking units
in appendix E to this part on an ozone season basis. In order to be
allowed to use this methodology, the unit must meet the definition of
``peaking unit'' in Sec. 72.2 of this chapter, except that the words
``year'', ``calendar year'' and ``calendar years'' in that definition
shall be replaced by the words ``ozone season'', ``ozone season'', and
``ozone seasons'', respectively. In addition, in the definition of the
term ``capacity factor'' in Sec. 72.2 of this chapter, the word
``annual'' shall be replaced by the words ``ozone season'' and the
number ``8,760'' shall be replaced by the number ``3,672''.
35. Section 75.81 is amended by:
a. Revising paragraph (a)(4);
b. Revising paragraph (c)(1);
c. Revising paragraph (c)(2);
c. Removing Eq. 1 from paragraph (d)(1);
d. Revising paragraph (d)(2);
e. Adding paragraph (d)(4)(iv); and
f. Revising paragraphs (d)(5) and (e)(1).
The revisions and additions read as follows:
Sec. 75.81 Monitoring of Hg mass emissions and heat input at the unit
level.
* * * * *
(a) * * *
(4) If heat input is required to be reported under the applicable
State or Federal Hg mass emission reduction
[[Page 49297]]
program that adopts the requirements of this subpart, the owner or
operator must meet the general operating requirements for a flow
monitoring system and an O2 or CO2 monitoring
system to measure heat input rate.
* * * * *
(c) * * *
(1) The owner or operator must perform Hg emission testing one year
or less before the compliance date in Sec. 75.80(b), to determine the
Hg concentration (i.e., total vapor phase Hg) in the effluent. The
testing shall be performed using one of the Hg reference methods listed
in Sec. 75.22(a)(7), and shall consist of a minimum of 3 runs at the
normal unit operating load, while combusting coal. The coal combusted
during the testing must be from the same source of supply as the coal
combusted at the start of the Hg mass emissions reduction program. The
minimum time per run shall be 1 hour if an instrumental reference
method is used. If Method 29 or the Ontario Hydro method is used,
paired sampling trains are required for each test run and the run must
be long enough to ensure that sufficient Hg is collected to analyze.
When Method 29 or the Ontario Hydro method is used, the test results
shall be based on the vapor phase Hg collected in the back-half of the
sampling trains (i.e., the non-filterable impinger catches). For each
Method 29 or Ontario Hydro method test run, the paired trains must meet
the percent relative deviation (RD) requirement in Sec. 75.22(a)(7).
If the RD specification is met, the results of the two trains shall be
averaged arithmetically. If the unit is equipped with flue gas
desulfurization or add-on Hg emission controls, the controls must be
operating normally during the testing, and, for the purpose of
establishing proper operation of the controls, the owner or operator
shall record parametric data or SO2 concentration data in
accordance with Sec. 75.58(b)(3)(i).
(2) Based on the results of the emission testing, Equation 1 of
this section shall be used to provide a conservative estimate of the
annual Hg mass emissions from the unit:
[GRAPHIC]
[TIFF OMITTED]
TP22AU06.050
Where:
E = Estimated annual Hg mass emissions from the affected unit, (ounces/year)
K = Units conversion constant, 9.978 x 10-10 oz-scm/[mu]g-scf
8760 = Number of hours in a year
CHg = The highest Hg concentration ([mu]g/scm) from any of
the test runs or 0.50 [mu]g/scm, whichever is greater
Qmax = Maximum potential flow rate, determined according to section
2.1.4.1 of appendix A to this part, (scfh)
Equation 1 of this section assumes that the unit operates year-
round at its maximum potential flow rate. Also, note that if the highest
Hg concentration measured in any test run is less than 0.50 [mu]g/scm, a
default value of 0.50 [mu]g/scm must be used in the calculations.
* * * * *
(d) * * *
(2) Following initial certification, the same default Hg
concentration value that was used to estimate the unit's annual Hg mass
emissions under paragraph (c) of this section shall be reported for
each unit operating hour, except as otherwise provided in paragraph
(d)(4)(iv) or (d)(6) of this section. The default Hg concentration
value shall be updated as appropriate, according to paragraph (d)(5) of
this section.
* * * * *
(4) * * *
(iv) An additional retest is required when there is a change in the
fuel supply. The retest shall be performed within 720 unit operating
hours of the change.
(5) The default Hg concentration used for reporting under Sec.
75.84 shall be updated after each required retest. This includes
retests that are required prior to the compliance date in Sec.
75.80(b). The updated value shall either be the highest Hg
concentration measured in any of the test runs or 0.50 [mu]g/scm,
whichever is greater. The updated value shall be applied beginning with
the first unit operating hour in which Hg emissions data are required
to be reported after completion of the retest, except as provided in
paragraph (d)(4)(iv) of this section, where the need to retest is
triggered by a change in the fuel supply. In that case, apply the
updated default Hg concentration beginning with the first unit
operating hour in which Hg emissions are required to be reported after
the date and hour of the fuel switch.
* * * * *
(e) * * *
(1) The methodology may not be used for reporting Hg mass emissions
at a common stack unless all of the units using the common stack are
affected units and each individual unit is tested to demonstrate that
its potential to emit does not exceed 464 ounces of Hg per year, in
accordance with paragraphs (c) and (d) of this section. If the units
sharing the common stack qualify as a group of identical units in
accordance with Sec. 75.19(c)(1)(iv)(B), the owner or operator may
test a subset of the units in lieu of testing each unit individually.
If this option is selected, the number of units required to be tested
shall be determined from Table LM-4 in Sec. 75.19. If the test results
demonstrate that the units sharing the common stack qualify as low mass
emitters, the default Hg concentration used for reporting Hg mass
emissions at the common stack shall either be the highest value
obtained in any test run for any of the tested units serving the common
stack or 0.50 [mu]g/scm, whichever is greater. Notwithstanding these
requirements, the emission testing required under paragraphs (c) and/or
(d)(3) of this section may be performed at the common stack in the
following circumstances:
(i) The initial certification testing required under paragraph (c)
of this section may be performed at the common stack if all of the
units using the stack are affected units and if, prior to entering the
common stack, the effluent gas streams from the individual units are
combined together upstream of an emission control device that reduces
the Hg concentration. If this testing option is chosen:
(A) The testing must be done at a combined load corresponding to
the designated normal load level (low, mid, or high) for the units
sharing the common stack, in accordance with section 6.5.2.1 of
appendix A to this part;
(B) All of the units that share the stack must be operating in a
normal, stable manner and at typical load levels during the emission
testing;
(C) When calculating E, the estimated maximum potential annual Hg
mass emissions from the stack, the maximum potential flow rate through
the common stack (as defined in the monitoring plan) and the highest
concentration from any test run (or 0.50 [mu]g/scm, if greater) shall
be substituted into Equation 1;
(D) The calculated value of E shall be divided by the number of
units sharing the stack. If the result, when rounded to the nearest
ounce, does not exceed 464 ounces, the units qualify to use the low
mass emission methodology; and
(E) If the units qualify to use the methodology, the default Hg
concentration used for reporting at the common stack shall be the
highest value obtained in any test run or 0.50 [mu]g/scm, whichever is
greater; or
(ii) For all common stack configurations, the retests required
under paragraph (d)(3) of this section may be done at the common stack.
If this testing option is chosen, the testing shall be done at a
combined load corresponding to the designated normal
[[Page 49298]]
load level (low, mid, or high) for the units sharing the common stack,
in accordance with section 6.5.2.1 of appendix A to this part. The due
date for the next retest shall be determined as follows:
(A) To calculate E, the maximum potential flow rate for the common
stack (as defined in the monitoring plan) and the highest Hg
concentration from any test run (or 0.50 [mu]g/scm, if greater) shall
be substituted into Equation 1;
(B) If the value of E obtained from Equation 1, rounded to the
nearest ounce, is greater than 144 times the number of units sharing
the common stack, but less than or equal to 464 times the number of units
sharing the stack, the next retest is due in two QA operating quarters;
(C) If the value of E obtained from Equation 1, rounded to the
nearest ounce, is less than or equal to 144 times the number of units
sharing the common stack, the next retest is due in four QA operating
quarters.
* * * * *
36. Section 75.82 is amended by adding paragraphs (b)(3), (c)(4),
and (d)(3) to read as follows:
Sec. 75.82 Monitoring of Hg mass emissions and heat input at common
and multiple stacks.
* * * * *
(b) * * *
(3) If the monitoring option in paragraph (b)(2) of this section is
selected, and if heat input is required to be reported under the
applicable State or Federal Hg mass emission reduction program that
adopts the requirements of this subpart, the owner or operator shall either:
(i) Apportion the common stack heat input rate to the individual
units according to the procedures in Sec. 75.16(e)(3); or
(ii) Install a flow monitoring system and a diluent gas
(O2 or CO2) monitoring system in the duct leading
from each affected unit to the common stack, and measure the heat input
rate in each duct, according to section 5.2 of appendix F to this part.
(c) * * *
(4) If the monitoring option in paragraph (c)(1) or (c)(2) of this
section is selected, and if heat input is required to be reported under
the applicable State or Federal Hg mass emission reduction program that
adopts the requirements of this subpart, the owner or operator shall:
(i) Use the installed flow and diluent monitors to determine the
hourly heat input rate at each stack (mmBtu/hr), according to section
5.2 of appendix F to this part; and
(ii) Calculate the hourly heat input at each stack (in mmBtu) by
multiplying the measured stack heat input rate by the corresponding
stack operating time; and
(iii) Determine the hourly unit heat input by summing the hourly
stack heat input values.
(d) * * *
(3) If the monitoring option in paragraph (d)(1) or (d)(2) of this
section is selected, and if heat input is required to be reported under
the applicable State or Federal Hg mass emission reduction program that
adopts the requirements of this subpart, the owner or operator shall:
(i) Use the installed flow and diluent monitors to determine the
hourly heat input rate at each stack or duct (mmBtu/hr), according to
section 5.2 of appendix F to this part; and
(ii) Calculate the hourly heat input at each stack or duct (in
mmBtu) by multiplying the measured stack (or duct) heat input rate by
the corresponding stack (or duct) operating time; and
(iii) Determine the hourly unit heat input by summing the hourly
stack (or duct) heat input values.
37. Section 75.84 is amended by:
a. Removing ``Sec. 75.53(e)(1)'' and ``Sec. 75.53(e)(2)'' and
adding in their place ``Sec. 75.53(g)(1)'' and ``Sec. 75.53(g)(2)'',
respectively, in paragraph (c)(3);
b. Removing the number ``45'' and adding in its place the number
``21'' in paragraphs (e)(1) and (e)(2);
c. Revising paragraph (f)(1) introductory text;
d. Removing ``Sec. 75.64(a)(1)'' and adding in its place ``Sec.
75.64(a)(3)'' in paragraph (f)(1)(i);
e. Replacing the phrase ``paragraph (a)'' with the phrase
``paragraphs (a) and (b)'' in paragraph (f)(1)(ii) introductory text;
f. Revising paragraph (f)(1)(ii)(I).
The revisions read as follows:
Sec. 75.84 Recordkeeping and reporting.
* * * * *
(f) * * *
(1) Electronic submission. Electronic quarterly reports shall be
submitted, beginning with the calendar quarter containing the
compliance date in Sec. 75.80(b), unless otherwise specified in the
final rule implementing a State or Federal Hg mass emissions reduction
program that adopts the requirements of this subpart. The designated
representative for an affected unit shall report the data and
information in this paragraph (f)(1) and the applicable compliance
certification information in paragraph (f)(2) of this section to the
Administrator quarterly, except as otherwise provided in Sec. 75.64(a)
for units in long-term cold storage. Each electronic report must be
submitted to the Administrator within 30 days following the end of each
calendar quarter. Except as otherwise provided in Sec. Sec.
75.64(a)(4) and (a)(5), each electronic report shall include the date
of report generation and the following information for each affected
unit or group of units monitored at a common stack:
* * * * *
(ii) * * *
(I) Supplementary RATA information required under Sec.
75.59(a)(7), except that:
(1) The applicable data elements under Sec. 75.59(a)(7)(ii)(A)
through (T) and under Sec. 75.59(a)(7)(iii)(A) through (M) shall be
reported for flow RATAs at circular or rectangular stacks (or ducts) in
which angular compensation for yaw and/or pitch angles is used (i.e.,
Method 2F or 2G), with or without wall effects adjustments;
(2) The applicable data elements under Sec. 75.59(a)(7)(ii)(A)
through (T) and under Sec. 75.59(a)(7)(iii)(A) through (M) shall be
reported for any flow RATA run at a circular stack in which Method 2 is
used and a wall effects adjustment factor is determined by direct
measurement;
(3) The data under Sec. 75.59(a)(7)(ii)(T) shall be reported for
all flow RATAs at circular stacks in which Method 2 is used and a
default wall effects adjustment factor is applied; and
(4) The data under Sec. 75.59(a)(7)(ix)(A) through (F) shall be
reported for all flow RATAs at rectangular stacks or ducts in which
Method 2 is used and a wall effects adjustment factor is applied.
* * * * *
38. Appendix A to Part 75 is amended by:
a. Revising paragraph (c) of section 2.1.1.1;
b. Revising paragraph (b)(2) of section 2.1.1.5;
c. Revising paragraph (b)(2) of section 2.1.2.5; and
d. Adding a new fourth sentence after the third sentence of section
2.1.3.
e. Revising paragraph (3) of section 3.2;
f. Replacing the phrase ``continuous emission monitoring
system(s)'' with the phrase ``monitoring component of a continuous
emission monitoring system that is'' in section 3.5;
g. Revising section 5.1;
h. Redesignating section 6.1 as section 6.1.1;
i. Adding new sections 6.1 and 6.1.2;
j. Revising the second and third sentences and adding a new fourth
sentence to section 6.2, introductory text;
[[Page 49299]]
k. Replacing the words ``section 2.6'' with the words ``section
2.2.1'', in paragraph (g) of section 6.2;
l. Adding paragraph (h) to section 6.2;
m. Adding a new fourth sentence to section 6.3.1, introductory text;
n. Revising the introductory text of section 6.4;
o. Removing the words ``that uses CEMS to account for its emissions
and for each unit that uses the optional fuel flow-to-load quality
assurance test in section 2.1.7 of appendix D to this part'' from
paragraph (a) of section 6.5.2.1;
p. Adding the words ``or mmBtu/hr'' after the words ``klb/hr of
steam production'', and by adding the words ``or mmBtu/hr of thermal
output'' after the words ``thousands of lb/hr of steam load'' in
paragraph (a)(1) of section 6.5.2.1;
q. Adding the words ``and units using the low mass emissions (LME)
excepted methodology under Sec. 75.19'' after the words ``(except for
peaking units'' in the second sentence in paragraph (c) of section
6.5.2.1;
r. Adding the words ``and LME units'' after the words ``For peaking
units'' in the third sentence of paragraph (d)(1) of section 6.5.2.1;
s. Replacing the words ``quarterly report'' in the first sentence
with the words ``monitoring plan'', by adding the words ``or mmBtu/hr''
after the term ``lb/hr'', by replacing the number ``75.64'' with the
number ``75.53'', by adding the words ``and LME units'' after the words
``Except for peaking units'', and by revising the words ``electronic
quarterly report (as part of the electronic monitoring plan)'' to read
``electronic monitoring plan'' in paragraph (e) of section 6.5.2.1;
t. Replacing all occurrences of the words ``section 3.2'' with the
words ``section 8.1.3'' in paragraph (b)(3) of section 6.5.6, paragraph
(a) of section 6.5.6.2, and paragraph (a) of section 6.5.6.3;
u. Adding the words ``and the same type of sorbent material'' after
the words ``same-size trap'' in the third-to-last sentence of section
6.5.7, paragraph (a);
v. Revising section 6.5.10;
w. Adding a sentence at the end of section 7.6.1;
x. Revising the words ``scfh/megawatts or scfh/1000 lb/hr of
steam'' to read ``scfh/megawatts, scfh/1000 lb/hr of steam, or scfh/
(mmBtu/hr of steam output)'' at the end of the Rref variable
definition, and by revising the words ``megawatts or 1000 lb/hr of
steam,'' to read ``megawatts, 1000 lb/hr of steam, or mmBtu/hr thermal
output'' at the end of the Lavg variable definition in
paragraph (a) of section 7.7; and
y. Revising the words ``Btu/kwh or Btu/lb steam load'' to read
``Btu/kwh, Btu/lb steam load, or mmBtu heat input/mmBtu steam output''
in the (GHR)ref variable definition, and by revising the
words ``megawatts or 1000 lb/hr of steam'' to read ``megawatts, 1000
lb/hr of steam, or mmBtu/hr thermal output'' at the end of the
Lavg variable definition, in paragraph (c) of section 7.7.
The revisions and additions read as follows:
Appendix A to Part 75--Specifications and Test Procedures
* * * * *
2. Equipment Specifications
2.1.1.1 Maximum Potential Concentration
* * * * *
(c) When performing fuel sampling to determine the MPC, use ASTM
Methods: ASTM D3177-89 (1997), ``Standard Test Methods for Total
Sulfur in the Analysis Sample of Coal and Coke''; ASTM D4239-02,
``Standard Test Methods for Sulfur in the Analysis Sample of Coal
and Coke Using High Temperature Tube Furnace Combustion Methods'';
ASTM D4294-98, ``Standard Test Method for Sulfur in Petroleum
Products by Energy-Dispersive X-Ray Fluorescence Spectroscopy'';
ASTM D1552-01, ``Standard Test Method for Sulfur in Petroleum
Products (High Temperature Method)''; ASTM D129-00, ``Standard Test
Method for Sulfur in Petroleum Products (General Bomb Method)'';
ASTM D2622-98, ``Standard Test Method for Sulfur in Petroleum
Products by X-Ray Spectrometry'' for sulfur content of solid or
liquid fuels; ASTM D3176-89 (1997)e1, ``Standard Practice for
Ultimate Analysis of Coal and Coke''; ASTM D240-00 (Reapproved
1991), ``Standard Test Method for Heat of Combustion of Liquid
Hydrocarbon Fuels by Bomb Calorimeter''; or ASTM D5865-01ae1,
``Standard Test Method for Gross Calorific Value of Coal and Coke''
(incorporated by reference under Sec. 75.6).
* * * * *
2.1.1.5 * * *
(b) * * *
(2) For units with two SO2 spans and ranges, if the
low range is exceeded, no further action is required, provided that
the high range is available and its most recent calibration error
test and linearity check have not expired. However, if either of
these quality assurance tests has expired and the high range is not
able to provide quality assured data at the time of the low range
exceedance or at any time during the continuation of the exceedance,
report the MPC as the SO2 concentration until the
readings return to the low range or until the high range is able to
provide quality assured data (unless the reason that the high-scale
range is not able to provide quality assured data is because the
high-scale range has been exceeded; if the high-scale range is
exceeded follow the procedures in paragraph (b)(1) of this section).
* * * * *
2.1.2.5 * * *
(b) * * *
(2) For units with two NOX spans and ranges, if the
low range is exceeded, no further action is required, provided that
the high range is available and its most recent calibration error
test and linearity check have not expired. However, if either of
these quality assurance tests has expired and the high range is not
able to provide quality assured data at the time of the low range
exceedance or at any time during the continuation of the exceedance,
report the MPC as the NOX concentration until the
readings return to the low range or until the high range is able to
provide quality assured data (unless the reason that the high-scale
range is not able to provide quality assured data is because the
high-scale range has been exceeded; if the high-scale range is
exceeded follow the procedures in paragraph (b)(1) of this section).
* * * * *
2.1.3 CO2 and O2 Monitors
* * * An alternative CO2 span value below 6.0 percent
may be used if an appropriate technical justification is included in
the hardcopy monitoring plan.
* * * * *
3.2 * * *
(3) For the linearity check and the 3-level system integrity
check of an Hg monitor, which are required, respectively, under
Sec. Sec. 75.20(c)(1)(ii) and (c)(1)(vi), the measurement error
shall not exceed 5.0 percent of the span value at any of the three
gas levels. To calculate the measurement error at each level, take
the absolute value of the difference between the reference value and
mean CEM response, divide the result by the span value, and then
multiply by 100. Alternatively, the results at any gas level are
acceptable if the absolute value of the difference between the
average monitor response and the average reference value, i.e.,
[bond]
R-A [bond]
in Equation A-4 of this appendix, does not exceed
0.6 [mu]g/m\3\. The principal and alternative performance
specifications in this section also apply to the single-level system
integrity check described in section 2.6 of appendix B to this part.
* * * * *
5.1 Reference Gases.
For the purpose of part 75, calibration gases include the following:
5.1.1 EPA Protocol Gases
(a) An EPA Protocol Gas is a calibration gas mixture prepared
and analyzed according to Section 2 of the ``EPA Traceability
Protocol for Assay and Certification of Gaseous Calibration
Standards,'' September 1997, EPA-600/R-97/121 or such revised
procedure as approved by the Administrator (EPA Traceability Protocol).
(b) An EPA Protocol Gas must have a specialty gas producer-
certified uncertainty (95-percent confidence interval) that must not
be greater than 2.0 percent of the certified concentration (tag
value) of the gas mixture. The uncertainty must be calculated using
the statistical procedures (or equivalent statistical techniques)
that are listed in Section 2.1.8 of the EPA Traceability Protocol.
[[Page 49300]]
(c) A specialty gas producer advertising calibration gas
certification with the EPA Traceability Protocol or distributing
calibration gases as ``EPA Protocol Gas'' must participate in the
EPA Protocol Gas Verification Program (PGVP) described in Section
2.1.10 of the EPA Traceability Protocol or it cannot use ``EPA'' in
any form of advertising for these products, unless approved by the
Administrator. A specialty gas producer may not certify a
calibration gas as an EPA Protocol Gas unless it participates in the
PGVP, unless approved by the Administrator.
(d) A copy of EPA-600/R-97/121 is available from the National
Technical Information Service, 5285 Port Royal Road, Springfield,
VA, 703-605-6585 or http://www.ntis.gov, and from
http://www.epa.gov/ttn/emc/news.html or
http://www.epa.gov/appcdwww/tsb/index.htm.
5.1.2 Mercury Standards
For 7-day calibration error tests of Hg concentration monitors
and for daily calibration error tests of Hg monitors, either
elemental Hg standards or a NIST-traceable source of oxidized Hg may
be used. For linearity checks, elemental Hg standards shall be used.
For 3-level and single-point system integrity checks under Sec.
75.20(c)(1)(vi), sections 6.2(g) and 6.3.1 of this appendix, and
sections 2.1.1, 2.2.1 and 2.6 of appendix B to this part, a NIST-
traceable source of oxidized Hg shall be used. Alternatively, other
NIST-traceable standards may be used for the required checks,
subject to the approval of the Administrator.
5.1.3 Zero Air Material
(a) A calibration gas certified by the specialty gas producer or
vendor not to contain concentrations of SO2,
NOX, or total hydrocarbons above 0.1 parts per million
(ppm), a concentration of CO above 1 ppm, or a concentration of
CO2 above 400 ppm;
(b) Ambient air conditioned and purified by a CEMS for which the
CEMS manufacturer or vendor certifies that the particular CEMS model
produces conditioned gas that does not contain concentrations of
SO2, NOX, or total hydrocarbons above 0.1 ppm,
a concentration of CO above 1 ppm, or a concentration of
CO2 above 400 ppm;
(c) For dilution-type CEMS, conditioned and purified ambient air
provided by a conditioning system concurrently supplying dilution
air to the CEMS; or
(d) A multi-component mixture certified by the supplier of the
mixture that the concentration of the component being zeroed is less
than or equal to the applicable concentration specified in paragraph
(a) of this section, and that the mixture's other components do not
interfere with the CEM readings.
* * * * *
6.1 General Requirements
* * * * *
6.1.2 Requirements for Air Emission Testing Bodies
(a) Any Air Emission Testing Body (AETB) conducting relative
accuracy test audits of CEMS and sorbent trap monitoring systems
under this part must conform to the requirements of ASTM D7036-04.
This section is not applicable to daily operation, daily calibration
error checks, daily flow interference checks, quarterly linearity
checks or routine maintenance of CEMS.
(b) The AETB shall provide to the affected source(s)
certification that the AETB operates in conformance with, and that
data submitted to the Agency has been collected in accordance with,
the requirements of ASTM D7036-04. This certification may be
provided in the form of:
(1) A certificate of accreditation of relevant scope issued by a
recognized, national accreditation body; or
(2) A letter of certification signed by a member of the senior
management staff of the AETB.
(c) The AETB shall either provide a Qualified Individual on-site
to conduct or shall oversee all relative accuracy testing carried
out by the AETB as required in ASTM D7036-04. The Qualified
Individual shall provide the affected source(s) with copies of the
qualification credentials relevant to the scope of the testing conducted.
* * * * *
6.2 Linearity Check (General Procedures)
* * * Notwithstanding these requirements, if the SO2
or NOX span value for a particular monitor range is <=30
ppm, that range is exempted from the linearity check requirements of
this part, both for initial certification and for on-going quality-
assurance. For units with two measurement ranges (high and low) for
a particular parameter, perform a linearity check on both the low
scale (except for SO2 or NOX span values <=30
ppm) and the high scale. Note that for a NOX-diluent
monitoring system with two NOX measurement ranges, if the
low NOX scale has a span value <=30 ppm and is exempt
from linearity checks, this does not exempt either the diluent
monitor or the high NOX scale (if the span is >30 ppm)
from linearity check requirements.
* * * * *
(g) For Hg monitors, follow the guidelines in section 2.2.3 of
this appendix in addition to the applicable procedures in section
6.2 when performing the system integrity checks described in Sec.
75.20(c)(1)(vi) and in sections 2.1.1, 2.2.1 and 2.6 of appendix B
to this part.
(h) For Hg concentration monitors, if moisture is added to the
calibration gas during the required linearity checks or system
integrity checks, and if the Hg monitor measures on a dry basis, the
moisture content of the calibration gas must be accounted for. Under
these circumstances, the dry basis concentration of the calibration
gas shall be used to calculate the linearity error or measurement
error (as applicable).
* * * * *
6.3.1 Gas Monitor 7-Day Calibration Error Test
* * * Also for Hg monitors, if moisture is added to the
calibration gas and the monitoring system measures Hg concentration
on a dry basis, the added moisture must be accounted for and the
dry-basis concentration of the calibration gas shall be used to
calculate the calibration error.
* * * * *
6.4 Cycle Time Test
Perform cycle time tests for each pollutant concentration
monitor and continuous emission monitoring system while the unit is
operating, according to the following procedures (see also Figure 6
at the end of this appendix). Use a zero-level and a high-level
calibration gas (as defined in section 5.2 of this appendix)
alternately. To determine the upscale elapsed time, inject a zero-
level concentration calibration gas into the probe tip (or injection
port leading to the calibration cell, for in situ systems with no
probe). Record the stable starting gas value and start time, using
the data acquisition and handling system (DAHS). Next, allow the
monitor to measure the concentration of flue gas emissions until the
response stabilizes. Record the stable ending stack emissions value
and the end time of the test using the DAHS. Determine the upscale
elapsed time as the time it takes for 95.0 percent of the step
change to be achieved between the stable starting gas value and the
stable ending stack emissions value. Then repeat the procedure,
starting by injecting the high-level gas concentration to determine
the downscale elapsed time, which is the time it takes for 95.0
percent of the step change to be achieved between the stable
starting gas value and the stable ending stack emissions value. End
the downscale test by measuring the stable concentration of flue gas
emissions. Record the stable starting and ending monitor values, the
start and end times, and the downscale elapsed time for the monitor
using the DAHS. A stable value is equivalent to a reading with a
change of less than 2.0 percent of the span value for 2 minutes, or
a reading with a change of less than 6.0 percent from the measured
average concentration over 6 minutes. Alternatively, the reading is
considered stable if it changes by no more than 0.5 ppm or 0.2%
CO2 or O2 (as applicable) for two minutes.
(Owners or operators of systems which do not record data in 1-minute
or 3-minute intervals may petition the Administrator under Sec.
75.66 for alternative stabilization criteria). For monitors or
monitoring systems that perform a series of operations (such as
purge, sample, and analyze), time the injections of the calibration
gases so they will produce the longest possible cycle time. Report
the slower of the two elapsed times (upscale or downscale) as the
cycle time for the analyzer. (See Figure 5 at the end of this
appendix.) Prior to January 1, 2009 for the NOX-diluent
continuous emission monitoring system test, either record and report
the longer cycle time of the two component analyzers as the system
cycle time or record the cycle time for each component analyzer
separately (as applicable). On and after January 1, 2009, record the
cycle time for each component analyzer separately. For time-shared
systems, perform the cycle time tests at each probe locations that
will be polled within the same 15-minute period during monitoring
system operations. To determine the cycle time for time-shared
systems, at each monitoring location, report the sum of the cycle time
[[Page 49301]]
observed at that monitoring location plus the sum of the time
required for all purge cycles (as determined by the continuous
emission monitoring system manufacturer) at each of the probe
locations of the time-shared systems. For monitors with dual ranges,
report the test results from on the range giving the longer cycle
time. Cycle time test results are acceptable for monitor or
monitoring system certification, recertification or diagnostic
testing if none of the cycle times exceed 15 minutes. The status of
emissions data from a monitor prior to and during a cycle time test
period shall be determined as follows:
* * * * *
6.5.10 Reference Methods
The following methods from appendix A to part 60 of this chapter
or their approved alternatives are the reference methods for
performing relative accuracy test audits: Method 1 or 1A for siting;
Method 2 or its allowable alternatives in appendix A to part 60 of
this chapter (except for Methods 2B and 2E) for stack gas velocity
and volumetric flow rate; Methods 3, 3A or 3B for O2 and
CO2; Method 4 for moisture; Methods 6, 6A or 6C for
SO2; Methods 7, 7A, 7C, 7D or 7E for NOX,
excluding the exceptions of Method 7E identified in Sec.
75.22(a)(5); and either the Ontario Hydro Method, Method 29 in
appendix A-8 to part 60 of this chapter, or an approved instrumental
method for Hg (see Sec. 75.22).
* * * * *
7.6 Bias Test and Adjustment Factor
* * * * *
7.6.1 * * * To calculate bias for a Hg monitoring system when
using the Ontario Hydro Method or Method 29 in appendix A-8 to part
60 of this chapter, ``d'' is, for each data point, the difference
between the average Hg concentration value (in [mu]g/m3)
from the paired Ontario Hydro or Method 29 sampling trains and the
concentration measured by the monitoring system. For sorbent trap
monitoring systems, use the average Hg concentration measured by the
paired traps in the calculation of ``d''.
* * * * *
39. Appendix B to Part 75 is amended by:
a. adding section 1.1.4;
b. Revising section 2.1.1;
c. Revising paragraph (2) of section 2.1.1.2;
d. Revising paragraph (2) of section 2.1.5.1;
e. Adding paragraph (3) to section 2.1.5.1;
f. Adding a new fourth sentence to paragraph (e) of section 2.2.3;
g. Revising the words ``scfh/megawatts or scfh/1000 lb/hr of steam
load'' to read ``scfh/megawatts, scfh/1000 lb/hr of steam load, or
scfh/(mmBtu/hr thermal output)'' at the end of the Rh
variable definition, and by revising the words ``megawatts or 1000 lb/
hr of steam'' to read ``megawatts, 1000 lb/hr of steam, or mmBtu/hr
thermal output'' in the Lh variable definition, in paragraph
(a) of section 2.2.5;
h. Revising the words Btu/kwh or Btu/lb steam load'' to read ``Btu/
kwh, Btu/lb steam load, mmBtu heat input/mmBtu thermal output'' in the
(GHR)h variable definition, and by revising the words
``megawatts or 1000 lb/hr of steam'' to read ``megawatts, 1000 lb/hr of
steam, or mmBtu/hr thermal output'' in the Lh variable
definition, in paragraph (a)(2) of section 2.2.5;
i. Replacing the word ``five'' with the word ``twenty'', and by
replacing the word ``years'' with the word ``quarters'', in paragraph
(c)(4) of section 2.3.1.3;
j. Revising paragraph (g) of section 2.3.2;
k. Revising paragraphs (a)(2) and (c) of section 2.3.3;
l. Adding paragraph (d) to section 2.3.3;
m. Revising section 2.6; and
n. Replacing the term ``dscm'' with ``scm'' in Figure 2.
The revisions and additions read as follows:
Appendix B to Part 75--Quality Assurance and Quality Control Procedures
1. Quality Assurance/Quality Control Program
* * * * *
1.1.4 The requirements in section 6.1.2 of appendix A to this
part shall be met by any Air Emissions Testing Body (AETB)
performing the semiannual/annual RATAs described in section 2.3 of
this appendix and the periodic Hg emission tests described in
Sec. Sec. 75.81(c)(1) and 75.81(d)(4)(iii).
* * * * *
2. Frequency of Testing
* * * * *
2.1.1 Calibration Error Test
Except as provided in section 2.1.1.2 of this appendix, perform
the daily calibration error test of each gas monitoring system
(including moisture monitoring systems consisting of wet- and dry-
basis O2 analyzers) according to the procedures in
section 6.3.1 of appendix A to this part, and perform the daily
calibration error test of each flow monitoring system according to
the procedure in section 6.3.2 of appendix A to this part. When two
measurement ranges (low and high) are required for a particular
parameter, perform sufficient calibration error tests on each range
to validate the data recorded on that range, according to the
criteria in section 2.1.5 of this appendix.
* * * * *
2.1.1.2 * * *
(2) For each monitoring system that has passed the off-line
calibration demonstration, off-line calibration error tests may be
used on a limited basis to validate data, in accordance with
paragraph (2) in section 2.1.5.1 of this appendix.
2.1.5.1 * * *
(2) For a monitor that has passed the off-line calibration
demonstration, off-line calibration error tests may be used to
validate data from the monitor for up to 26 consecutive unit or
stack operating hours, after which data from the monitor become
invalid until an on-line calibration error test of the monitor is
passed. Once the required on-line calibration error test has been
passed, another 26 operating hour cycle of data validation using
off-line calibration error tests may begin. Each off-line
calibration error test that is used for data validation has a
prospective data validation window of 26 clock hours, as described
in section 2.1.5 of this appendix. If the sequence of consecutive
operating hours validated by off-line calibrations is broken before
reaching the 26th consecutive unit or stack operating hour, data
from the monitor become invalid and an on-line calibration error
test must be passed to re-establish the quality-assured data status.
The sequence is considered broken when a unit or stack operating
hour is not contained within the 26 clock hour data validation
window of a passed off-line calibration error test.
(3) For units with two measurement ranges (low and high) for a
particular parameter, when separate analyzers are used for the low
and high ranges, a failed or expired calibration on one of the
ranges does not affect the quality-assured data status on the other
range. For a dual-range analyzer (i.e., a single analyzer with two
measurement scales), a failed calibration error test on either the
low or high scale results in an out-of-control period for the
monitor. Data from the monitor remain invalid until corrective
actions are taken and ``hands-off'' calibration error tests have
been passed on both ranges. However, if the most recent calibration
error test on the high scale has expired, while the low scale is up-
to-date on its calibration error test requirements (or vice-versa),
the expired calibration error test does not affect the quality-
assured status of the data recorded on the other scale.
* * * * *
2.2.3 * * *
(e) * * * For a dual-range analyzer, ``hands-off'' linearity
checks must be passed on both measurement scales to end the out-of-
control period.
* * * * *
2.3.2 * * *
(g) Data validation for failed RATAs for a CO2
pollutant concentration monitor (or an O2 monitor used to
measure CO2 emissions), a NOX pollutant
concentration monitor, and a NOX-diluent monitoring
system shall be done according to paragraphs (g)(1) and (g)(2) of
this section:
(1) For a CO2 pollutant concentration monitor (or an
O2 monitor used to measure CO2 emissions)
which also serves as the diluent component in a NOX-
diluent monitoring system, if the CO2 (or O2)
RATA is failed, then both the O2 (or O2)
monitor and the associated NOX-diluent system are
considered out-of-control, beginning with the hour of completion of
the failed CO2 (or O2) monitor RATA, and
continuing until the hour of completion of subsequent hands-off
RATAs which demonstrate that both systems
[[Page 49302]]
have met the applicable relative accuracy specifications in sections
3.3.2 and 3.3.3 of appendix A to this part, unless the option in
paragraph (b)(3) of this section to use the data validation
procedures and associated timelines in Sec. Sec. 75.20(b)(3)(ii)
through (b)(3)(ix) has been selected, in which case the beginning
and end of the out-of-control period shall be determined in
accordance with Sec. Sec. 75.20(b)(3)(vii)(A) and (B).
(2) This paragraph (g)(2) applies only to a NOX
pollutant concentration monitor that serves both as the
NOX component of a NOX concentration
monitoring system (to measure NOX mass emissions) and as
the NOX component in a NOX-diluent monitoring
system (to measure NOX emission rate in lb/mmBtu). If the
RATA of the NOX concentration monitoring system is
failed, then both the NOX concentration monitoring system
and the associated NOX-diluent monitoring system are
considered out-of-control, beginning with the hour of completion of
the failed NOX concentration RATA, and continuing until
the hour of completion of subsequent hands-off RATAs which
demonstrate that both systems have met the applicable relative
accuracy specifications in sections 3.3.2 and 3.3.7 of appendix A to
this part, unless the option in paragraph (b)(3) of this section to
use the data validation procedures and associated timelines in
Sec. Sec. 75.20(b)(3)(ii) through (b)(3)(ix) has been selected, in
which case the beginning and end of the out-of-control period shall
be determined in accordance with Sec. Sec. 75.20(b)(3)(vii)(A) and (B).
* * * * *
2.3.3 RATA Grace Period
(a) * * *
(2) A required 3-load flow RATA has not been performed by the
end of the calendar quarter in which it is due; or
* * * * *
(c) If, at the end of the 720 unit (or stack) operating hour
grace period, the RATA has not been completed, data from the
monitoring system shall be invalid, beginning with the first unit
operating hour following the expiration of the grace period. Data
from the CEMS remain invalid until the hour of completion of a
subsequent hands-off RATA. The deadline for the next test shall be
either two QA operating quarters (if a semiannual RATA frequency is
obtained) or four QA operating quarters (if an annual RATA frequency
is obtained) after the quarter in which the RATA is completed, not
to exceed eight calendar quarters.
* * * * *
(d) When a RATA is done during a grace period in order to
satisfy a RATA requirement from a previous quarter, the deadline for
the next RATA shall be determined as follows:
(1) If the grace period RATA qualifies for a reduced, (i.e.,
annual), RATA frequency the deadline for the next RATA shall be set
at three QA operating quarters after the quarter in which the grace
period test is completed.
(2) If the grace period RATA qualifies for the standard, (i.e.,
semiannual), RATA frequency the deadline for the next RATA shall be
set at two QA operating quarters after the quarter in which the
grace period test is completed.
(3) Notwithstanding these requirements, no more than eight
successive calendar quarters shall elapse after the quarter in which
the grace period test is completed, without a subsequent RATA having
been conducted.
* * * * *
2.6 System Integrity Checks for Hg Monitors
For each Hg concentration monitoring system (except for a Hg
monitor that does not have a converter), perform a single-point
system integrity check weekly, i.e., at least once every 168 unit or
stack operating hours, using a NIST-traceable source of oxidized Hg.
Perform this check using a mid-or high-level gas concentration, as
defined in section 5.2 of appendix A to this part. The performance
specifications in paragraph (3) of section 3.2 of appendix A to this
part must be met, otherwise the monitoring system is considered out-
of-control, from the hour of the failed check until a subsequent
system integrity check is passed. If a required system integrity
check is not performed and passed within 168 unit or stack operating
hours of last successful check, the monitoring system shall also be
considered out of control, beginning with the 169th unit or stack
operating hour after the last successful check, and continuing until
a subsequent system integrity check is passed. This weekly check is
not required if the daily calibration assessments in section 2.1.1
of this appendix are performed using a NIST-traceable source of oxidized Hg.
* * * * *
40. Appendix D to Part 75 is amended by:
a. Revising section 2.1.5.1;
b. Removing all ``±'' symbols from paragraph (c) of
section 2.1.6.1;
c. Revising the Rbase and Lavg variable
definitions in paragraph (a) of section 2.1.7.1;
d. Revising the words ``Btu/kwh or Btu/lb steam load'' to read
``Btu/kwh, Btu/lb steam load, or mmBtu heat input/mmBtu thermal
output'' in the (GHR)base variable definition, and by
revising the words ``megawatts or 1000 lb/hr of steam'' to read
``megawatts, 1000 lb/hr of steam, or mmBtu/hr thermal output'' in the
Lavg variable definition, in paragraph (c) of section 2.1.7.1;
e. Removing the word ``or'' and adding the phrase'',100 scfh/
(mmBtu/hr of steam load), or (lb/hr)/(mmBtu/hr thermal output )'' at
the end of the Rh variable definition, and by replacing the
phrase ``megawatts or 1000 lb/hr of steam'' with the phrase
``megawatts, 1000 lb/hr of steam, or mmBtu /hr thermal output'' in the
Lh variable definition, in paragraph (a) of section 2.1.7.2;
f. Replacing the phrase the ``Btu/kwh or Btu/lb steam load'' with
the phrase ``Btu/kwh, Btu/lb steam load, or mmBtu heat input/mmBtu
thermal output'' in the (GHR)h variable definition; and by
replacing the phrase ``megawatts or 1000 lb/hr of steam'' with the
phrase ``megawatts, 1000 lb/hr of steam, or mmBtu/hr thermal output''
in the Lh variable definition, in paragraph (c) of section
2.1.7.2;
g. Replacing ``D4177-82 (Reapproved 1990)'' with ``D4177-95
(2000)'', in the first sentence of section 2.2.3;
h. Replacing ``D4057-88'' with ``D4057-95 (2000)'', in sections
2.2.4.1 and 2.2.4.2, and in paragraph (c) of section 2.2.4.3;
i. Revising sections 2.2.5, 2.2.6, and 2.2.7;
j. Revising paragraphs (a)(2) and (e) of section 2.3.1.4;
k. Revising section 2.3.3.1.2;
l. Replacing the identifier ``D1826-88'' with the identifier
``D1826-94 (1998)'', by replacing the identifier ``D3588-91'' with the
identifier ``D3588-98'', by adding the number ``(2001)'' after the
identifier ``ASTM D4891-89'', by replacing the numbers ``2172-86'' with
the numbers ``2172-1996'', and by replacing the numbers ``2261-90''
with the numbers ``2261-1999'', in section 2.3.4;
m. Adding two sentences at the end of section 2.3.4.1;
n. Replacing the phrase ``Gas Total Sulfur Content'' in the
``Parameter'' column of Table D-6 with the phrase ``Gas Total Sulfur
Content*'', and adding the following footnote beneath the Table `` *
Required no later than July 1, 2003''; and
o. Replacing the words ``(Reapproved 1990)'' with the words
``(1997)e1'' in section 3.2.2.
The revisions and additions read as follows:
Appendix D to Part 75--Optional SO2 Emissions Data Protocol
for Gas-Fired and Oil-Fired Units.
2. Procedure
* * * * *
2.1.5.1 Use the procedures in the following standards to verify
flowmeter accuracy or design, as appropriate to the type of
flowmeter: ASME MFC-3M-1989 (Reaffirmed 1995) (``Measurement of
Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi''); ASME MFC-
4M-1986 (Reaffirmed 1990), ``Measurement of Gas Flow by Turbine
Meters;'' American Gas Association Report No. 3, ``Orifice Metering
of Natural Gas and Other Related Hydrocarbon Fluids Part 1: General
Equations and Uncertainty Guidelines'' (October 1990 Edition), Part
2: ``Specification and Installation Requirements'' (February 1991
Edition), and Part 3: ``Natural Gas Applications'' (August 1992
edition) (excluding the modified flow-calculation method in part 3);
Section 8, Calibration from American Gas Association Transmission
Measurement Committee Report No. 7: Measurement of Gas by Turbine
Meters (Second Revision, April 1996); ASME
[[Page 49303]]
MFC-5M-1985 (Reaffirmed 2001) (``Measurement of Liquid Flow in
Closed Conduits Using Transit-Time Ultrasonic Flowmeters''); ASME
MFC-6M-1998 (``Measurement of Fluid Flow in Pipes Using Vortex Flow
Meters''); ASME MFC-7M-1987 (Reaffirmed 2001), ``Measurement of Gas
Flow by Means of Critical Flow Venturi Nozzles;'' ISO 8316: 1987(E)
``Measurement of Liquid Flow in Closed Conduits-Method by Collection
of the Liquid in a Volumetric Tank;'' American Petroleum Institute
(API) Manual of Measurement Standards, Chapter 4: Section 2,
``Conventional Pipe Provers'' (Provers Accumulating at Least 10,000
Pulses), Measurement Coordination (Second Edition, March 2001),
Section 3, ``Small Volume Provers'' (First Edition), and Section 5,
``Master-Meter Provers'', Measurement Coordination (Second Edition,
May 2000); API Manual of Petroleum Measurement Standards, Chapter
22--Testing Protocol: Section 2--Differential Pressure Flow
Measurement Devices (First Edition, August 2005); or ASME MFC-9M-
1988 (Reaffirmed 2001) (``Measurement of Liquid Flow in Closed
Conduits by Weighing Method''), for all other flowmeter types
(incorporated by reference under Sec. 75.6). The Administrator may
also approve other procedures that use equipment traceable to
National Institute of Standards and Technology standards. Document
such procedures, the equipment used, and the accuracy of the
procedures in the monitoring plan for the unit, and submit a
petition signed by the designated representative under Sec.
75.66(c). If the flowmeter accuracy exceeds 2.0 percent of the upper
range value, the flowmeter does not qualify for use under this part.
* * * * *
2.1.7.1(a) * * *
Where:
Rbase = Value of the fuel flow rate-to-load ratio during
the baseline period; 100 scfh/MWe, 100 scfh/klb per hour steam load,
or 100 scfh/mmBtu per hour thermal output for gas-firing; (lb/hr)/
MWe, (lb/hr)/klb per hour steam load, or (lb/hr)/mmBtu per hour
thermal output for oil-firing.
* * * * *
Lavg = Arithmetic average unit load during the baseline
period, megawatts, 1000 lb/hr of steam, or mmBtu/hr thermal output.
* * * * *
2.2.5 For each oil sample that is taken on-site at the affected
facility, split and label the sample and maintain a portion (at
least 200 cc) of it throughout the calendar year and in all cases
for not less than 90 calendar days after the end of the calendar
year allowance accounting period. This requirement does not apply to
oil samples taken from the fuel supplier's storage container, as
described in section 2.2.4.3 of this appendix. Analyze oil samples
for percent sulfur content by weight in accordance with ASTM D129-
00, ``Standard Test Method for Sulfur in Petroleum Products (General
Bomb Method),'' ASTM D1552-01, ``Standard Test Method for Sulfur in
Petroleum Products (High Temperature Method),'' ASTM D2622-98,
``Standard Test Method for Sulfur in Petroleum Products by X-Ray
Spectrometry,'' or ASTM D4294-98, ``Standard Test Method for Sulfur
in Petroleum Products by Energy-Dispersive X-Ray Fluorescence
Spectroscopy'' (incorporated by reference under Sec. 75.6).
2.2.6 Where the flowmeter records volumetric flow rate rather
than mass flow rate, analyze oil samples to determine the density or
specific gravity of the oil. Determine the density or specific
gravity of the oil sample in accordance with ASTM D287-92(2000)e1,
``Standard Test Method for API Gravity of Crude Petroleum and
Petroleum Products (Hydrometer Method),'' ASTM D1217-93(1998),
``Standard Test Method for Density and Relative Density (Specific
Gravity) of Liquids by Bingham Pycnometer,'' ASTM D1481-93 (1997),
``Standard Test Method for Density and Relative Density (Specific
Gravity) of Viscous Materials by Lipkin Bicapillary,'' ASTM D1480-93
(1997), ``Standard Test Method for Density and Relative Density
(Specific Gravity) of Viscous Materials by Bingham Pycnometer,''
ASTM D1298-99, ``Standard Practice for Density, Relative Density
(Specific Gravity) or API Gravity of Crude Petroleum and Liquid
Petroleum Products by Hydrometer Method,'' or ASTM D4052-96
(2002)e1, ``Standard Test Method for Density and Relative Density of
Liquids by Digital Density Meter'' (incorporated by reference under
Sec. 75.6).
2.2.7 Analyze oil samples to determine the heat content of the
fuel. Determine oil heat content in accordance with ASTM D240-00
(Reapproved 1991), ``Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter,'' ASTM D4809-00,
``Standard Test Method for Heat of Combustion of Liquid Hydrocarbon
Fuels by Bomb Calorimeter (Precision Method),'' or ASTM D5865-01ae1,
``Standard Test Method for Gross Calorific Value of Coal and Coke''
(incorporated by reference under Sec. 75.6) or any other procedures
listed in section 5.5 of appendix F of this part.
* * * * *
2.3.1.4 * * *
(a) * * *
(2) Historical fuel sampling data for the previous 12 months,
documenting the total sulfur content of the fuel and the GCV and/or
percentage by volume of methane. The results of all sample analyses
obtained by or provided to the owner or operator in the previous 12
months shall be used in the demonstration, and each sample result
must meet the definition of pipeline natural gas in Sec. 72.2 of
this chapter, except where the results of at least 100 daily (or
more frequent) total sulfur samples are provided by the fuel
supplier. In that case you may convert these data to monthly
averages and then if, for each month, the average total sulfur
content is 0.5 grains/100 scf or less, and if the GCV or percent
methane requirement is also met, the fuel qualifies as pipeline
natural gas. Alternatively, the fuel qualifies as pipeline natural
gas if the GCV or percent methane requirement is met and if >= 98
percent of the 100 (or more) samples have a total sulfur content of
0.5 grains/100 scf or less; or
* * * * *
(e) If a fuel qualifies as pipeline natural gas based on the
specifications in a fuel contract or tariff sheet, no additional,
on-going sampling of the fuel's total sulfur content is required,
provided that the contract or tariff sheet is current, valid and
representative of the fuel combusted in the unit. If the fuel
qualifies as pipeline natural gas based on fuel sampling and
analysis, on-going sampling of the fuel's sulfur content is required
annually and whenever the fuel supply source changes. For the
purposes of this paragraph, (e), sampling ``annually'' means that at
least one sample is taken in each calendar year. If the results of
at least 100 daily (or more frequent) total sulfur samples have been
provided by the fuel supplier since the last annual assessment of
the fuel's sulfur content, the data may be used to satisfy the
annual sampling requirement for the current year. If this option is
chosen, all of the data provided by the fuel supplier shall be used.
First, convert the data to monthly averages. Then, if, for each
month, the average total sulfur content is 0.5 grains/100 scf or
less, and if the GCV or percent methane requirement is also met, the
fuel qualifies as pipeline natural gas. Alternatively, the fuel
qualifies as pipeline natural gas if the GCV or percent methane
requirement is met and if the analysis of the 100 (or more) total
sulfur samples since the last annual assessment shows that > 98
percent of the samples have a total sulfur content of 0.5 grains/100
scf or less. The effective date of the annual total sulfur sampling
requirement is January 1, 2003.
* * * * *
2.3.3.1.2 Use one of the following methods when using manual
sampling (as applicable to the type of gas combusted) to determine
the sulfur content of the fuel: ASTM D1072-90(1999), ``Standard Test
Method for Total Sulfur in Fuel Gases,'' ASTM D4468-85 (2000)
``Standard Test Method for Total Sulfur in Gaseous Fuels by
Hydrogenolysis and Radiometric Colorimetry,'' ASTM D5504-01
``Standard Test Method for Determination of Sulfur Compounds in
Natural Gas and Gaseous Fuels by Gas Chromatography and
Chemiluminescence,'' ASTM D6667-04 ``Standard Test Method for
Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and
Liquified Petroleum Gases by Ultraviolet Fluorescence,'' or ASTM
D3246-96 ``Standard Test Method for Sulfur in Petroleum Gas By
Oxidative Microcoulometry'' (incorporated by reference under Sec. 75.6).
* * * * *
2.3.4.1 GCV of Pipeline Natural Gas
* * * If multiple GCV samples are taken and analyzed in a
particular month, the GCV values from all samples shall be averaged
arithmetically to obtain the monthly GCV. Then, for the purposes of
implementing paragraph (c) in section 2.3.7 of this appendix,
consider the latest date of any of the individual GCV samples used
in the monthly average to be the ``date on which the sample was taken''.
* * * * *
41. Appendix E to Part 75 is amended by:
a. Adding a new sentence to the end of section 2.1;
[[Page 49304]]
b. Replacing the words ``section 5.1'' with the words ``section
8.3.1'' in section 2.1.2.1;
c. Replacing the phrase ``(MWge or steam load in 1000 lb/hr)'' with
the phrase ``(MWge or steam load in 1000 lb/hr, or mmBtu/hr thermal
output)'', in section 2.4.1;
d. Revising section 2.5.2; and
e. Adding section 2.5.2.4.
The revisions and additions read as follows:
Appendix E to Part 75--Optional NOX Emissions Estimation
Protocol for Gas-Fired Peaking Units and Oil-Fired Peaking Units.
* * * * *
2.1 Initial Performance Testing
* * * The requirements in section 6.1.2 of appendix A to this
part shall be met by any Air Emissions Testing Body (AETB)
performing O2 and NOX concentration
measurements under this appendix, either for units using the
excepted methodology in this appendix or for units using the low
mass emissions excepted methodology in Sec. 75.19.
* * * * *
2.5.2 Substitute missing NOX emission rate data using
the highest NOX emission rate tabulated during the most
recent set of baseline correlation tests for the same fuel or, if
applicable, combination of fuels, except as provided in sections
2.5.2.1, 2.5.2.2, 2.5.2.3, and 2.5.2.4 of this section.
* * * * *
2.5.2.4 Whenever 20 full calendar quarters have elapsed
following the quarter of the last baseline correlation test for a
particular type of fuel (or fuel mixture), without a subsequent
baseline correlation test being done for that type of fuel (or fuel
mixture), substitute the fuel-specific NOX MER (as
defined in Sec. 72.2 of this chapter) for each hour in which that
fuel (or mixture) is combusted until a new baseline correlation test
for that fuel (or mixture) has been successfully completed. For fuel
mixtures, report the highest of the individual MER values for the
components of the mixture.
42. Appendix F to Part 75 is amended by:
a. Removing the second and third sentences from the introductory
text of section 2;
b. Replacing the phrase ``method 19 in appendix A of part 60 of
this chapter'' with the phrase ``Method 19 in appendix A-7 to part 60
of this chapter'', in the last sentence of section 3.1 and in the last
sentence of section 3.2;
c. Adding the phrase ``, or (if applicable) in the equations in
Method 19 in appendix A-7 to part 60 of this chapter'' after the words
``of this appendix'', in section 3.3;
d. Removing the second and third sentences from section 3.3.4;
e. Adding sections 3.3.4.1 and 3.3.4.2;
f. Revising Table 1;
g. Revising the text preceding Equation F-7a, in section 3.3.6;
h. Adding ``(1997)e1'' after the identifier ``D3176-89'', by
replacing the identifier ``D5291-92'' with the identifier ``D5291-01'',
by replacing the identifier ``D1945-91'' with the identifier ``D1945-96
(2001)'', and by adding the number ``(2000)'' after the identifier
``D1946-90'', in section 3.3.6.1;
i. Revising section 3.3.6.2;
j. Revising the definition of ``Xi'' under Equation F-8
in section 3.3.6.4;
k. Adding the words ``either measured directly with a
CO2 monitor or calculated from wet-basis O2 data
using Equation F-14b,'' after the words ``wet basis,'' in the first
sentence of the Ch variable definition, and by removing the
second and third sentences from the Ch variable definition,
in section 4.1;
l. Revising section 4.4.1;
m. Removing the second and third sentences from the
%CO2w variable definition in 5.2.1;
n. Removing the second and third sentences from the
%CO2d variable definition in 5.2.2;
o. Removing the second and third sentences from the %O2w
variable definition, and by adding a new sentence at the end of the
paragraph, in section 5.2.3;
p. Removing the second and third sentences from the %O2d
variable definition, in section 5.2.4;
q. Replacing the identifier ``D240-87'' with the identifier ``D240-
00'', by replacing the identifier ``D2015-91'' with the identifier
``D5865-01ae1'', and by replacing the identifier ``D2382-88'' with the
identifier ``D4809-00'' in the GCVO variable definition, in
section 5.5.1;
r. Replacing the identifier ``D1826-88'' with the identifier
``D1826-94 (1998)'', by replacing the identifier ``D3588-91'' with the
identifier ``D3588-98'', by adding the number ``(2001)'' after the
identifier ``D4891-89'', by replacing the numbers ``2172-86'' with the
numbers ``2172-1996'', and by replacing the numbers ``2261-90'' with
the numbers ``2261-1999'' in the GCVg variable definition,
in section 5.5.2;
s. Replacing each identifier ``D2234-89'' with the identifier
``D2234-00e1'', in section 5.5.3.1;
t. Revising section 5.5.3.2;
u. Revising the words ``as measured by ASTM D3176-89, D1989-92,
D3286-91a, or D2015-91, Btu/lb'' to read ``as measured by ASTM D3176-89
(1997)e1, or D5865ae1, Btu/lb.'' in the definition of the
GCVc variable in Equation F-21;
v. Revising the word ``lb/hr'' to read ``lb/hr, or mmBtu/hr'' in
the definition of the SF variable in Equation F-21b;
w. Revising the title and text of section 7;
x. Adding the words ``of this appendix'' after the words ``section
8.1, 8.2, or 8.3'' and after the words ``section 8.4'' in the
introductory text for section 8;
y. Revising sections 8.1 and 8.1.1;
z. Revising section 8.2;
aa. Adding sections 8.2.1 and 8.2.2;
bb. Revising section 8.3;
cc. Revising section 8.4; and
dd. Adding section 10.
The revisions and additions read as follows:
Appendix F to Part 75--Conversion Procedures
* * * * *
3.3.4 * * *
3.3.4.1 For boilers, a minimum concentration of 5.0 percent
CO2 or a maximum concentration of 14.0 percent
O2 may be substituted for the measured diluent gas
concentration value for any operating hour in which the hourly
average CO2 concentration is <5.0 percent CO2
or the hourly average O2 concentration is >14.0 percent
O2. For stationary gas turbines, a minimum concentration
of 1.0 percent CO2 or a maximum concentration of 19.0
percent O2 may be substituted for measured diluent gas
concentration values for any operating hour in which the hourly
average CO2 concentration is <1.0 percent CO2
or the hourly average O2 concentration is >19.0 percent O2.
3.3.4.2 If NOX emission rate is calculated using
either Equation 19-3 or 19-5 in Method 19 in appendix A-7 to part 60
of this chapter, a variant of the equation shall be used whenever
the diluent cap is applied. The modified equations shall be
designated as Equations 19-3D and 19-5D, respectively. Equation 19-
3D is structurally the same as Equation 19-3, except that the term
``%O2w'' in the denominator is replaced with the term
``%O2dc x [(100-% H2O)/100]'', where
%O2dc is the diluent cap value. The numerator of Equation
19-5D is the same as Equation 19-5; however, the denominator of
Equation 19-5D is simply ``20.9-%O2dc'', where
%O2dc is the diluent cap value.
* * * * *
[[Page 49305]]
Table 1.--F and FC-Factors \1\
------------------------------------------------------------------------
F-factor (dscf/ FC-factor (scf
Fuel mmBtu) CO2/mmBtu)
------------------------------------------------------------------------
Coal (as defined by ASTM D388-99e1):
Anthracite.......................... 10,100 1,970
Bituminous.......................... 9,780 1,800
Sub-bituminous...................... 9,819 1,840
Lignite............................. 9,860 1,910
Petroleum Coke.......................... 9,832 1,853
Tire Derived Fuel 1..................... 10,261 1,803
Oil..................................... 9,190 1,420
Gas:
Natural gas......................... 8,710 1,040
Propane............................. 8,710 1,190
Butane.............................. 8,710 1,250
Wood:
Bark................................ 9,600 1,920
Wood residue........................ 9,240 1,830
------------------------------------------------------------------------
\1\ Determined at standard conditions: 20 [deg]C (68 [deg]F) and 29.92
inches of mercury.
* * * * *
3.3.6 Equations F-7a and F-7b may be used in lieu of the F or
Fc factors specified in Section 3.3.5 of this appendix to
calculate a site-specific dry-basis F factor (dscf/mmBtu) or a site-
specific Fc factor (scf CO2/mmBtu), on either
a dry or wet basis. At a minimum, the site-specific F or
Fc factor must be based on 9 samples of the fuel. Fuel
samples taken during each run of a RATA are acceptable for this
purpose. The site-specific F or Fc factor must be re-
determined at least annually, and the value from the most recent
determination must be used in the emission calculations.
Alternatively, the previous F or Fc value may continue to
be used if it is higher than the value obtained in the most recent
determination. The owner or operator shall keep records of all site-
specific F or Fc determinations, active for at least 3
years. (Calculate all F- and Fc factors at standard
conditions of 20 [deg]C (68 [deg]F) and 29.92 inches of mercury).
* * * * *
3.3.6.2 GCV is the gross calorific value (Btu/lb) of the fuel
combusted determined by ASTM D5865-01ae1 ``Standard Test Method for
Gross Calorific Value of Coal and Coke'', and ASTM D240-00
``Standard Test Method for Heat of Combustion of Liquid Hydrocarbon
Fuels by Bomb Calorimeter'', or ASTM D4809-00, ``Standard Test
Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb
Calorimeter (Precision Method) for oil; and ASTM D3588-98 ``Standard
Practice for Calculating Heat Value, Compressibility Factor, and
Relative Density (Specific Gravity) of Gaseous Fuels,'' ASTM D4891-
89 (2001) ``Standard Test Method for Heating Value of Gases in
Natural Gas Range by Stoichiometric Combustion,'' GPA Standard 2172-
1996 ``Calculation of Gross Heating Value, Relative Density and
Compressibility Factor for Natural Gas Mixtures from Compositional
Analysis,'' GPA Standard 2261-1999 ``Analysis for Natural Gas and
Similar Gaseous Mixtures by Gas Chromatography,'' or ASTM D1826-94
(1998), ``Standard Test Method for Calorific (Heating) Value of
Gases in Natural Gas Range by Continuous Recording Calorimeter'' for
gaseous fuels, as applicable. (These methods are incorporated by
reference under Sec. 75.6).
* * * * *
3.3.6.4 * * *
Xi = Fraction of total heat input derived from each type
of fuel (e.g., natural gas, bituminous coal, wood). Each
Xi value shall be determined from the best available
information on the quantity of fuel combusted and the GCV value,
over a specified time period. The owner or operator shall explain
the method used to calculate Xi in the hardcopy portion
of the monitoring plan for the unit. The Xi values may be
determined and updated either hourly, daily, weekly, or monthly. In
all cases, the prorated F-factor used in the emission calculations
shall be determined using the Xi values from the most
recent update.
* * * * *
4. Procedure for CO2 Mass Emissions
* * * * *
4.4.1 If the owner or operator elects to use data from an
O2 monitor to calculate CO2 concentration, the
appropriate F and FC factors from section 3.3.5 of this
appendix shall be used in one of the following equations (as
applicable) to determine hourly average CO2 concentration
of flue gases (in percent by volume) from the measured hourly
average O2 concentration:
[GRAPHIC]
[TIFF OMITTED]
TP22AU06.051
Where:
CO2d = Hourly average CO2 concentration during
unit operation, percent by volume, dry basis.
F, FC = F-factor or carbon-based Fc-factor
from section 3.3.5 of this appendix.
20.9 = Percentage of O2 in ambient air.
O2d = Hourly average O2 concentration during
unit operation, percent by volume, dry basis.
[GRAPHIC]
[TIFF OMITTED]
TP22AU06.052
Where:
CO2w = Hourly average CO2 concentration during
unit operation, percent by volume, wet basis.
O2w = Hourly average O2 concentration during
unit operation, percent by volume, wet basis.
[[Page 49306]]
F, Fc = F-factor or carbon-based FC-factor
from section 3.3.5 of this appendix.
20.9 = Percentage of O2 in ambient air.
%H2O = Moisture content of gas in the stack, percent.
For any hour where Equation F-14b results in a negative hourly
average CO2 value, 0.0% CO2w shall be recorded
as the average CO2 value for that hour.
* * * * *
5. Procedures for Heat Input
* * * * *
5.2.3 * * *
For any hour where Equation F-17 results in a negative hourly
heat input rate, 1.0 mmBtu/hr shall be recorded and reported as the
heat input rate for that hour.
* * * * *
5.5.3.2 Use ASTM D2013-01, ``Standard Method of Preparing Coal
Samples for Analysis,'' for preparation of a daily coal sample and
analyze each daily coal sample for gross calorific value using ASTM
D5865-01ae1, ``Standard Test Method for Gross Calorific Value of
Coal and Coke'' (All ASTM methods are incorporated by reference
under Sec. 75.6 of this part.)
On-line coal analysis may also be used if the on-line analytical
instrument has been demonstrated to be equivalent to the applicable
ASTM methods under Sec. Sec. 75.23 and 75.66.
* * * * *
7. Procedures for SO2 Mass Emissions, Using Default
SO2 Emission Rates and Heat Input Measured by CEMS
The owner or operator shall use Equation F-23 to calculate
hourly SO2 mass emissions in accordance with Sec.
75.11(e)(1) during the combustion of gaseous fuel, for a unit that
uses a flow monitor and a diluent gas monitor to measure heat input,
and that qualifies to use a default SO2 emission rate
under section 2.3.1.1, 2.3.2.1.1, or 2.3.6(b) of appendix D to this
part. Equation F-23 may also be applied to the combustion of solid
or liquid fuel that meets the definition of very low sulfur fuel in
Sec. 72.2 of this chapter, combinations of such fuels, or mixtures
of such fuels with gaseous fuel, if the owner or operator has
received approval from the Administrator under Sec. 75.66 to use a
site-specific default SO2 emission rate for the fuel or
mixture of fuels.
[GRAPHIC]
[TIFF OMITTED]
TP22AU06.053
Where:
Eh = Hourly SO2 mass emission rate, lb/hr.
ER = Applicable SO2 default emission rate for gaseous
fuel combustion, from section 2.3.1.1, 2.3.2.1.1, or 2.3.6(b) of
appendix D to this part, or other default SO2 emission
rate for the combustion of very low sulfur liquid or solid fuel,
combinations of such fuels, or mixtures of such fuels with gaseous
fuel, as approved by the Administrator under Sec. 75.66, lb/mmBtu.
HI = Hourly heat input rate, determined using the procedures in
section 5.2 of this appendix, mmBtu/hr.
* * * * *
8. Procedures for NOX Mass Emissions
* * * * *
8.1 The owner or operator may use the hourly NOX
emission rate and the hourly heat input rate to calculate the
NOX mass emissions in pounds or the NOX mass
emission rate in pounds per hour, (as required by the applicable
reporting format), for each unit or stack operating hour, as follows:
8.1.1 If both NOX emission rate and heat input rate
are monitored at the same unit or stack level (e.g., the
NOX emission rate value and the heat input rate value
both represent all of the units exhausting to the common stack),
then (as required by the applicable reporting format) either:
(a) Use Equation F-24 to calculate the hourly NOX
mass emissions (lb)
[GRAPHIC]
[TIFF OMITTED]
TP22AU06.054
Where:
M(NOX)h = NOX mass emissions in lbs
for the hour.
ER(NOX)h = Hourly average NOX
emission rate for hour h, lb/mmBtu, from section 3 of this appendix,
from method 19 of appendix A to part 60 of this chapter, or from
section 3.3 of appendix E to this part. (Include bias-adjusted
NOX emission rate values, where the bias-test procedures
in appendix A to this part shows a bias-adjustment factor is necessary.)
HIh = Hourly average heat input rate for hour h, mmBtu/
hr. (Include bias-adjusted flow rate values, where the bias-test
procedures in appendix A to this part shows a bias-adjustment factor
is necessary.)
th = Monitoring location operating time for hour h, in
hours or fraction of an hour (in equal increments that can range
from one hundredth to one quarter of an hour, at the option of the
owner or operator). If the combined NOX emission rate and
heat input are monitored for all of the units in a common stack, the
monitoring location operating time is equal to the total time when
any of those units was exhausting through the common stack; or
(b) Use Equation F-24a to calculate the hourly NOX
mass emission rate (lb/hr).
[GRAPHIC]
[TIFF OMITTED]
TP22AU06.055
Where:
E(NOX)h = NOX mass emissions rate
in lbs/hr for the hour.
ER(NOX)h = Hourly average NOX
emission rate for hour h, lb/mmBtu, from section 3 of this appendix,
from method 19 of appendix A to part 60 of this chapter, or from
section 3.3 of appendix E to this part. (Include bias-adjusted
NOX emission rate values, where the bias-test procedures
in appendix A to this part shows a bias-adjustment factor is necessary.)
HIh = Hourly average heat input rate for hour h, mmBtu/
hr. (Include bias-adjusted flow rate values, where the bias-test
procedures in appendix A to this part shows a bias-adjustment factor
is necessary.)
* * * * *
8.2 Alternatively, the owner or operator may use the hourly
NOX concentration (as measured by a NOX
concentration monitoring system) and the hourly stack gas volumetric
flow rate to calculate the NOX mass emission rate (lb/hr)
for each unit or stack operating hour, in accordance with section
8.2.1 or 8.2.2 of this appendix (as applicable). If the hourly
NOX mass emissions are to be reported in lb, Equation F-
26c in section 8.3 of this appendix shall be used to convert the
hourly NOX mass emission rates to hourly NOX
mass emissions (lb).
8.2.1 When the NOX concentration monitoring system
measures on a wet basis, first calculate the hourly NOX
mass emission rate (in lb/hr) during unit (or stack) operation,
using Equation F-26a. (Include bias-adjusted flow rate or
NOX concentration values, where the bias-test procedures
in appendix A to this part shows a bias-adjustment factor is necessary.)
[GRAPHIC]
[TIFF OMITTED]
TP22AU06.056
Where:
E(NOX)h = NOX mass emissions rate in lb/hr.
K = 1.194 x 10-7 for NOX, (lb/scf)/ppm.
Chw = Hourly average NOX concentration during
unit operation, wet basis, ppm.
Qh = Hourly average volumetric flow rate during unit
operation, wet basis, scfh.
8.2.2 When NOX mass emissions are determined using a
dry basis NOX concentration monitoring system and a wet
basis flow monitoring system, first calculate hourly NOX
mass emission rate (in lb/hr) during unit (or stack) operation,
using Equation F-26b. (Include bias-adjusted flow rate or
NOX concentration values, where the bias-test procedures
in appendix A to this part shows a bias-adjustment factor is necessary.)
[GRAPHIC]
[TIFF OMITTED]
TP22AU06.057
Where:
E(NOX)h = NOX mass emissions rate,
lb/hr.
K = 1.194 x 10-7 for NOX, (lb/scf)/ppm.
Chd = Hourly average NOX concentration during
unit operation, dry basis, ppm.
Qh = Hourly average volumetric flow rate during unit
operation, wet basis, scfh
[[Page 49307]]
%H2O = Hourly average stack moisture content during unit
operation, percent by volume.
8.3 When hourly NOX mass emissions are reported in
pounds and are determined using a NOX concentration
monitoring system and a flow monitoring system, calculate
NOX mass emissions (lb) for each unit or stack operating
hour by multiplying the hourly NOX mass emission rate
(lb/hr) by the unit operating time for the hour, as follows:
[GRAPHIC]
[TIFF OMITTED]
TP22AU06.058
Where:
M(NOx)h = NOX mass emissions for
the hour, lb.
Eh = Hourly NOX mass emission rate during unit
(or stack) operation from Equation F-26a in section 8.2.1 of this
appendix or Equation F-26b in section 8.2.2 of this appendix (as
applicable), lb/hr.
th = Unit operating time or stack operating time (as
defined in Sec. 72.2 of this chapter) for hour ``h'', in hours or
fraction of an hour (in equal increments that can range from one
hundredth to one quarter of an hour, at the option of the owner or
operator).
8.4 Use the following procedures to calculate quarterly,
cumulative ozone season, and cumulative yearly NOX mass
emissions, in tons:
(a) When hourly NOX mass emissions are reported in
lb, use Eq. F-27.
[GRAPHIC]
[TIFF OMITTED]
TP22AU06.059
Where:
M(NOX)time period = NOX mass
emissions in tons for the given time period (quarter, cumulative
ozone season, cumulative year-to-date).
M(NOX)h = NOX mass emissions in lb
for the hour.
p = The number of hours in the given time period (quarter,
cumulative ozone season, cumulative year-to-date).
(b) When hourly NOX mass emission rate is reported in
lb/hr, use Eq. F-27a.
[GRAPHIC]
[TIFF OMITTED]
TP22AU06.060
Where:
M(NOX)time period = NOX mass
emissions in tons for the given time period (quarter, cumulative
ozone season, cumulative year-to-date).
E(NOX)h = NOX mass emission rate in
lb/hr for the hour.
p = The number of hours in the given time period (quarter,
cumulative ozone season, cumulative year-to-date).
th = Monitoring location operating time for hour h, in
hours or fraction of an hour (in equal increments that can range
from one hundredth to one quarter of an hour, at the option of the
owner or operator).
* * * * *
10. Moisture Determination from Wet and Dry O2 Readings
If a correction for the stack gas moisture content is required
in any of the emissions or heat input calculations described in this
appendix, and if the hourly moisture content is determined from wet-
and dry-basis O2 readings, use Equation F-31 to calculate
the percent moisture, unless a ``K'' factor or other mathematical
algorithm is developed as described in section 6.5.7(a) of appendix
A to this part:
[GRAPHIC]
[TIFF OMITTED]
TP22AU06.061
Where:
% H2O = Hourly average stack gas moisture content,
percent H2O
O2d = Dry-basis hourly average oxygen concentration,
percent O2
O2w = Wet-basis hourly average oxygen concentration,
percent O2
* * * * *
43. Appendix G to Part 75--is amended by:
a. Revising section 2.1.2;
b. Replacing the identifier ``D3174-89'' with the identifier
``D3174-00'' in section 2.2.1; and
c. Adding the number ``(1997)'' after the identifier ``D3178-89''
in section 2.2.2.
The revisions and additions read as follows:
Appendix G to Part 75--Determination of CO2 Emissions
* * * * *
2.1.2 Determine the carbon content of each fuel sample using one
of the following methods: ASTM D3178-89 (1997) or ASTM 5373-93 for
coal; ASTM D5291-01 ``Standard Test Methods for Instrumental
Determination of Carbon, Hydrogen, and Nitrogen in Petroleum
Products and Lubricants,'' ultimate analysis of oil, or computations
based upon ASTM D3238-95 (2000)e1 and either ASTM D2502-92 (1996) or
ASTM D2503-92 (1997) for oil; and computations based on ASTM D1945-
96 (2001) or ASTM D1946-90 (2000) for gas.
* * * * *
44. Appendix K to Part 75 is amended by:
a. Adding a sentence to the end of section 7.2.3; and
b. Revising Table K-1 of section 8.
c. Adding the number ``2'' after the words ``sections 1 and'' in
the definition of the variable M* in Equation K-5.
The revisions and additions read as follows:
Appendix K to Part 75--Quality Assurance and Operating Procedures for
Sorbent Trap Monitoring Systems
* * * * *
7.2.3 * * * The sample flow rate through a sorbent trap
monitoring system during any hour (or portion of an hour) in which
the unit is not operating shall be zero.
* * * * *
[[Page 49308]]
Table K-1.--Quality Assurance/Quality Control Criteria for Sorbent Trap Monitoring Systems
----------------------------------------------------------------------------------------------------------------
QA/QC test or specification Acceptance criteria Frequency Consequences if not met
----------------------------------------------------------------------------------------------------------------
Pre-test leak check.................. < =4% of target sampling Prior to sampling...... Sampling shall not
rate. commence until the
lead check is passed.
Post-test leak check................. < =4% of average After sampling......... Sample invalidated.**
sampling rate.
Ratio of stack gas flow rate to Maintain within < plus- Every hour throughout Sample invalidated if
sample flow rate. minus> 25% of initial data collection period. more than 5% of the
ratio from first hour hourly ratios or 5
of data collection hourly ratios
period. (whichever is less
restrictive) are not
maintained within the
acceptance criteria.**
Sorbent trap section 2 break-through. < =5% of Section 1 Hg Every sample........... Sample invalidated.**
mass.
Paired sorbent trap agreement........ < =10% Relative Every sample........... Either invalidate the
Deviation (RD) if the data from the paired
average concentration traps or report the
is >1.0 [mu]g/m3, and results from the trap
< =20% RD if the resulting in the
average concentration higher Hg
is < =1.0 [mu]g/m3. concentration.
Spike Recovery Study................. Average recovery Prior to analyzing Field samples shall not
between 85% and 115% field samples and be analyzed until the
for each of the 3 prior to use of new percent recovery
spike concentration sorbent media. criteria has been met.
levels.
Multipoint analyzer calibration...... Each analyzer reading On the day of analysis, Recalibrate until
within ±10% before analyzing any successful.
of true value and samples.
r2>=0.99.
Analysis of independent calibration Within ±10% Following daily Recalibrate and repeat
standard. of true value. calibration, prior to independent standard
analyzing field analysis until
samples. successful.
Spike recovery from section 3 of 75-125% of spike amount Every sample........... Sample invalidated.**
sorbent trap.
RATA................................. RA < =20.0% or Mean For initial Data from the system
difference < =1.0 [mu]g/ certification and are invalidated until
dscm for low emitters. annually thereafter. a RATA is passed.
Dry gas meter calibration (At 3 Calibration factor (Y) Prior to initial use Recalibrate the meter
orifice initially, and 1 setting within ±5% and at least quarterly at three orifice
thereafter). of average value from thereafter. settings to determine
the initial (3-point) a new value of Y.
calibration.
Temperature sensor calibration....... Absolute temperature Prior to initial use Recalibrate. Sensor may
measured by sensor and at least quarterly not be used until
within < plus- thereafter. specification is met.
minus>1.5% of a
reference sensor.
Barometer calibration................ Absolute pressure Prior to initial use Recalibrate. Instrument
measured by instrument and at least quarterly may not be used until
within ±10 thereafter. specification is met.
mm Hg of reading with
a mercury barometer.
----------------------------------------------------------------------------------------------------------------
** However, if only one of the paired samples fails to meet this specification and the other sample meets all of
the applicable QA criteria, the results of the valid sample may be used for reporting under this part,
provided that the measured Hg concentration is multiplied by a factor of 1.222. If both samples are
invalidated and quality-assured data from a certified backup monitoring system, reference method, or approved
alternative monitoring system are unavailable, substitute data must be used.
[FR Doc. 06-6819 Filed 8-21-06; 8:45 am]
BILLING CODE 6560-50-P