[Federal Register: January 24, 2008 (Volume 73, Number 16)]
[Rules and Regulations]
[Page 4311-4377]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr24ja08-32]
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Part II
Environmental Protection Agency
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40 CFR Parts 72 and 75
Revisions to the Continuous Emissions Monitoring Rule for the Acid Rain
Program, NOX Budget Trading Program, Clean Air Interstate
Rule, and the Clean Air Mercury Rule; Final Rule
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 72 and 75
[EPA-HQ-OAR-2005-0132; FRL-8511-1]
RIN 2060-AN16
Revisions to the Continuous Emissions Monitoring Rule for the
Acid Rain Program, NOX Budget Trading Program, Clean Air
Interstate Rule, and the Clean Air Mercury Rule
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: EPA is finalizing rule revisions that 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 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 do not impose significant new requirements upon sources with
regard to monitoring or quality assurance activities.
DATES: This final rule is effective on January 24, 2008, for good cause
found as explained in this rule.
The incorporation by reference of certain publications listed in
the rule is approved by the Director of the Federal Register as of
January 24, 2008, for good cause found as explained in this rule.
ADDRESSES: The EPA has established a docket for this action under
Docket ID No. EPA-HQ-OAR-2005-0132. 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 Building, EPA Headquarters Library,
Room 3334, 1301 Constitution Avenue, 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:
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Examples of potentially regulated
Category NAICS code 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.
World Wide Web (WWW). In addition to being available in the docket,
an electronic copy of the final rule is also available on the WWW
through the Technology Transfer Network Web site (TTN Web). Following
signature, a copy of the 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.
Judicial Review. Under CAA section 307(b), judicial review of this
final action is available only by filing a petition for review in the
U.S. Court of Appeals for the District of Columbia Circuit on or before
March 24, 2008. Under CAA section 307(d)(7)(B), only those objections
to the final rule that were raised with specificity during the period
for public comment may be raised during judicial review. Moreover,
under CAA section 307(b)(2), the requirements established by today's
final rule may not be challenged separately in any civil or criminal
proceedings brought by EPA to enforce these requirements. Section
307(d)(7)(B) also provides a mechanism for the EPA to convene a
proceeding for reconsideration if the petitioner demonstrates that it
was impracticable to raise an objection during the public comment
period or if the grounds for such objection arose after the comment
period (but within the time for judicial review) and if the objection
is of central relevance to the rule. Any person seeking to make such a
demonstration to EPA should submit a Petition for Reconsideration,
clearly labeled as such, to the Office of the Administrator, U.S. EPA,
Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave., Washington, DC
20460, with a copy to the Associate General Counsel for the Air and
Radiation Law Office, Office of General Counsel, Mail Code 2344A, U.S.
EPA, 1200 Pennsylvania Ave., NW., Washington, DC 20460.
Outline
I. Detailed Discussion of Rule Revisions
A. Rule Definitions
B. General Monitoring Provisions
C. Certification Requirements
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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
O. Other Rule Revisions
II. Statutory and Executive Order Reviews
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
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
K. Congressional Review Act
L. Petition for Judicial Review
M. Determination Under Section 307(d)
I. Detailed Discussion of 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 in 2009.
Therefore, EPA finds good cause to determine that the final rule is
effective on January 24, 2008. EPA normally issues final regulations
with at least a 30-day effective date after Federal Register
publication. However, this provision of the rule which pertains to the
re-engineering of the Clean Air Markets Division's data systems and to
implementation of the Clean Air Mercury Regulation (CAMR), must be
effective by January 1, 2008. Today's rule allows sources the option of
reporting emissions data in the new XML data reporting format in 2008,
one year before the use of XML becomes mandatory. The final rule
provides the necessary record keeping and reporting requirements to
support the XML format. Second, sources subject to CAMR are required to
install and certify continuous mercury (Hg) monitoring systems by
January 1, 2009. To meet this deadline, companies with multiple CAMR-
affected units will begin monitor certification testing in the first
quarter of 2008. As described in Sections I.C.3 and I.O.3., today's
rule adds two recently-published Hg test methods, i.e., Methods 30A and
30B, to Part 75 as alternatives to the Ontario Hydro Method. For many
sources, 30A and 30B will be the test methods of choice. Third, as
discussed in Section I.A., today's rule defers until January 1, 2010
the requirement for the calibration standards used to certify Hg
continuous emission monitoring systems (CEMS) under CAMR to be
traceable to the National Institute of Standards and Technology (NIST).
Fourth, for CAMR units that seek to qualify as low mass emitting units
under Sec. 75.81, Hg emission testing is required in 2008. As
discussed in Section G.2., today's rule adds considerable flexibility
to the way in which this testing is conducted, particularly for common
stack configurations and groups of identical units. The use of Methods
30A and 30B for this testing is also desirable. Absent this
determination of good cause, sources would not be able to begin
scheduled monitoring certification activities until the necessary
provisions of this rule became effective. A thirty day delay would
significantly decrease the overall amount of time available for
industry to comply with the certification deadline of January 1, 2009.
Such a delay could result in sources not being able to meet the
certification deadline, since industry would lose some of its ability
to spread utilization of various certification resources (i.e., test
teams, equipment, and vendor support) over the entire course of 2008.
For these reasons, EPA believes it has good cause to expedite the
effective date of this final rule.
A. Rule Definitions
Background
EPA proposed to add several new definitions to Part 72, including
definitions for: ``Long-term cold storage'' (to mean the complete
shutdown of a unit intended to last for at least two calendar years);
``EPA Protocol Gas Verification Program'' (to support the proposed
calibration gas audit program); ``Air Emission Testing Body (AETB)''
and ``Qualified Individual'' (to support the proposed stack tester
accreditation program).
EPA also proposed to modify the definitions of ``Capacity factor'',
``EPA protocol gas,'' and ``Excepted monitoring system'', and to remove
the definition of ``Calibration gas'' and related definitions
describing the various types of gas standards that are classified as
calibration gas.
Summary of Rule Changes
All of the proposed new and modified definitions have been
finalized without substantive changes. However, one commenter cautioned
that removing the definitions of the calibration gas standards from
Part 72 might have consequences that could necessitate further rule
revisions. In view of this, the Agency reconsidered these proposed
changes and the final rule retains all but one of the definitions. The
definition of ``Research gas material'' was found to be identical to
the definition of ``Research gas mixture'' and has been removed from
the rule.
Further, for consistency with Method 30A, the new instrumental
reference method for mercury (Hg) (which, as noted in sections I.C.3
and I.O.3 of this preamble has been added to the list of acceptable Hg
reference methods in Sec. 75.22), and in light of other changes in
today's rule related to the certification of Hg monitoring systems, EPA
is adding definitions of ``NIST traceable elemental Hg standards'' and
``NIST traceable source of oxidized Hg'' to Sec. 72.2. These
definitions pertain to Hg calibration gas standards and are deemed
necessary for implementation of the continuous monitoring requirements
of the Clean Air Mercury Regulation (CAMR).
Affected units under CAMR are required to install and certify Part
75-compliant Hg monitoring systems by January 1, 2009. To meet this
requirement, the vast majority of the
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certification testing will be performed in 2008. When CAMR was first
proposed, only one reference test method (the Ontario Hydro (OH)
Method) was prescribed for the relative accuracy test audits (RATAs) of
the required Hg monitoring systems. However, the OH method is wet
chemistry-based, and is both difficult and expensive to perform. Also,
the laboratory analysis required to obtain the test results can take a
week or more, making the OH method incompatible with the Hg emissions
trading program described in the CAMR model rule.
In a cap and trade program, the RATA results must be known while
the test team is still on-site, so that any necessary corrective
actions can be taken and retesting performed without delay. With the OH
method, if the results of the lab analysis indicate a RATA failure, a
retest must be rescheduled and the Hg monitoring system is considered
out-of-control until a subsequent RATA is passed. This can result in an
extended missing data period and loss of Hg allowances.
Thus, it became apparent during the CAMR rulemaking that an
alternative to the OH method was needed. An instrumental Hg reference
method was put forth as the logical choice, because it would provide
real-time Hg concentration data, allowing the RATA results to be known
on the day of the test. When CAMR was published on May 18, 2005, EPA
stated its intention to ``propose and promulgate'' an instrumental Hg
reference method (see 70 FR 28636). In support of the final CAMR rule,
Hg monitoring provisions were added to Part 75. Among these was an
amendment to Sec. 75.22, allowing the use of either the OH method or
an ``instrumental reference method * * * subject to the approval of the
Administrator'' for the certification testing of Hg continuous
monitoring systems. Method 30A was published on September 7, 2007 in a
direct-final rulemaking, and became effective on November 6, 2007 (see
72 FR 51494). Method 30A represents the fulfillment of the Agency's
commitment to publish an instrumental reference method for Hg.
One of the most important Part 75 requirements for the
certification of Hg continuous emission monitoring systems (CEMS) is
that the concentrations of the elemental and oxidized Hg calibration
gas standards used for the 7-day calibration error tests, linearity
checks, and system integrity checks of the CEMS must be traceable to
the National Institute of Standards and Technology (NIST) (see Part 75,
Appendix A, Section 5.1.9). This NIST traceability requirement for Hg
standards is modeled after the NIST traceability requirements in
Section 5 of Appendix A for SO2, NOX, and diluent
gas (CO2 and O2) calibration gas standards.
For the SO2, NOX, CO2, and
O2 compressed gas standards used in Part 75 applications,
``NIST traceability'' means that the calibration gases have been
prepared according to the EPA-approved protocol cited in Section 5.1.4
of Appendix A. Further, Sec. 75.22(c)(1) requires NIST-traceable gas
standards to be used to calibrate the instrumental reference methods
used for relative accuracy testing of SO2, NOX,
CO2, and O2 CEMS (i.e., Methods 6C, 7E and 3A).
Prior to today's rulemaking, no NIST traceability protocols for Hg
calibration standards were referenced in Part 75. The new definitions
of ``NIST traceable elemental Hg standards'' and ``NIST traceable
source of oxidized Hg'' address this deficiency and cite the EPA
protocols that must be followed to ensure that the elemental and
oxidized Hg standards are traceable to NIST. However, these protocols,
which are referenced in Section 16.0 of Method 30A, are not yet fully
developed, and are not expected to be ready for use until the latter
part of 2008. A cooperative field demonstration program that will
include representatives from EPA, NIST, industry, equipment vendors,
and other key personnel is planned for the coming months, to gather the
data necessary to refine and finalize the traceability protocols. Once
these traceability protocols are finalized, they will be posted on the
Agency's Technology Transfer Network Web site (http://www.epa.gov/ttn/emc/) and on the Agency's Clean Air Markets Division Web site (http://
http://www.epa.gov/airmarkets/).
In view of this, EPA is temporarily deferring (until January 1,
2010) the requirement for elemental and oxidized Hg standards to be
NIST traceable. The deferral affects both initial certifications of the
CEMS and routine quality-assurance tests of the CEMS performed prior to
January 1, 2010. Note that only the NIST traceability requirement for
the Hg calibration standards is being waived, not the requirement to
perform the calibration error tests, linearity checks, and system
integrity checks of the Hg monitoring systems by January 1, 2009.
Beginning on January 1, 2010, all daily calibration error tests,
linearity checks, and system integrity checks of Hg CEMS must be
performed using NIST traceable elemental and oxidized Hg calibration
standards, as defined in Sec. 72.2. Section 5.1.9 of Appendix A to
Part 75 has been revised to reflect this. In view of this, EPA strongly
recommends that in 2009, all CAMR-affected sources should take the
necessary steps to ensure that the NIST traceability requirement is
met. In most cases, this will involve the certification of elemental
and oxidized Hg generators, according to the traceability protocols. If
a source elects to perform daily calibrations and/or linearity checks
using compressed gas cylinders instead of an elemental Hg generator,
the owner or operator will have to obtain cylinder gases that conform
to the EPA traceability protocol for gaseous calibration standards.
Finally, note that EPA is conditionally allowing Method 30A to be
used for Part 75 Hg emission testing and RATA applications prior to
finalization of the traceability protocols in section 16.0 of the
method. The condition is that interim traceability protocols are
developed and posted on the Agency's Technology Transfer Network Web
site (http://www.epa.gov/ttn/emc/), as ``broadly applicable alternative
test method approvals'' that will expire when the final protocols are
issued. EPA's authority to approve such test method alternatives is
described in 72 FR 4257, January 30, 2007.
EPA believes that a phased-in approach to NIST traceability is
appropriate and necessary, in light of the additional time needed to
finalize the traceability protocols and the time required for the
affected sources and equipment vendors to set up the necessary
infrastructure to implement the protocols. The Agency also believes
that this approach will not compromise the quality of the data for the
emissions trading program under CAMR, since in 2010, the first year in
which Hg emissions count against allowances held, NIST traceability of
the Hg calibration standards is mandatory.
B. General Monitoring Provisions
1. Update of Incorporation by Reference (Sec. 75.6)
Background
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). EPA
proposed changes to Sec. 75.6 that would reflect the need to
incorporate
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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.
Summary of Rule Changes
The updates and additions to Sec. 75.6 have been finalized as
proposed. One commenter requested that an additional ASTM method for
analyzing the sulfur content of low-sulfur fuel oil, i.e., ASTM D5453-
06, ``Standard Test Method for Determination of Total Sulfur in Light
Hydrocarbons, Spark Ignition Engine Fuel, Diesel Engine Fuel, and
Engine Oil by Ultraviolet Fluorescence'', be added to the list of
acceptable methods in Sec. 75.6. This method has been incorporated by
reference as Sec. 75.6(a)(49) and has been added to section 2.2.5 of
Appendix D.
2. Default Emission Rates for Low Mass Emissions (LME) Units
Background
EPA proposed to 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, if made, would allow more
representative, yet still conservatively high, SO2 emissions
data to be reported from oil-burning LME units. As proposed, 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 of Appendix D to Part 75,
and would be required to keep records documenting the sulfur content of
the fuel.
The Agency also proposed to 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. Lastly, the
Agency proposed technical revisions to the Equations LM-5 and LM-6
changing the units of rate to units of measure to make the equations
correct as units of rate cannot technically be summed.
Summary of Rule Changes
Commenters were generally supportive of the proposed revisions to
Sec. 75.19, and they have been finalized with only one substantive
change. EPA has incorporated one commenter's suggestion not to restrict
the allowable fuel oil sampling options to those described in Appendix
D. The final rule allows the use of other consensus standard fuel
sampling methods (e.g., ASTM, API, etc.) specified in applicable State
or Federal regulations or in the unit's operating permit, to determine
the sulfur content of the oil.
Another commenter requested that EPA go beyond its proposal for
SO2 and consider providing a similar, more reasonable site-
specific alternative to reporting the generic NOX emission
rates in Table LM-2. Specifically, the commenter suggested that for
units with very low annual capacity factors, the Agency should waive
the testing requirements of Sec. Sec. 75.19(c)(1)(iv) and allow
emission test data that was generated more than 5 years ago (e.g., from
a Part 60 performance test) to be used to determine fuel-specific
default NOX emission rates. The commenter asserted that the
cost of additional testing could impose a financial burden on smaller
affected sources. After careful consideration, EPA decided against
allowing infrequently-operated units to use emission test data older
than 5 years for Part 75 reporting. However, Sec. 75.19(c)(1)(iv)(I)
has been amended to provide reduced emission testing requirements for
very low capacity factor LME units. The final rule allows single-load
testing, between 75 and 100 percent of maximum load, to be performed
(both for the initial Appendix E testing and for retests) if, for the 3
years prior to the year of the test, the unit's average capacity factor
was 2.5 percent or less and did not exceed 4.0 percent in any of those
three years. Alternatively, for combustion turbines, the emission test
may be done at the maximum attainable load corresponding to the season
of the year in which the test is performed. For a group of identical
units, the single-load testing option may be used for any unit(s) in
the group that meet the very low capacity factor requirements. For a
more detailed discussion of this issue, refer to section 2.3.2 of the
Response to Comments (RTC) document.
3. Default Moisture Value for Natural Gas
Background
EPA proposed to allow gas-fired boilers equipped with CEMS to use
default moisture values in lieu of continuously monitoring the stack
gas moisture content. Two conservative default values were proposed:
14.0% H2O under Sec. 75.11(b), and 18.0% H2O under Sec.
75.12(b). The Agency also proposed that the higher default value would
apply only when Equation 19-3, 19-4, or 19-8 (from Method 19 in
appendix A-7 to part 60 of this chapter) is used to determine the
NOX emission rate. The proposed default values represent the
10th and 90th percentile values from two sets of supplemental moisture
data provided to the Agency, which is consistent with the approach that
the Agency has used in responding to past petitions under Sec. 75.66
for site-specific default moisture values.
Summary of Rule Changes
No adverse comments were received on these proposed rule changes
and they have been finalized.
4. Expanded Use of Equation F-23
Background
EPA proposed to 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, by allowing 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. The proposal would allow Equation
F-23 to be used for any gaseous fuel that qualifies for a default
SO2 emission rate under Section 2.3.6(b) of Appendix D.
Further, Equation F-23 could 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. Under the proposed rule,
petitions would also be accepted for the combustion of mixtures of
these fuels and for the co-firing of these fuels with gaseous fuel.
Summary of Rule Changes
Commenters were supportive of the expanded use of Equation F-23 and
the revisions to Sec. 75.11(e) and corresponding changes to section 7
of Appendix F have been finalized as proposed.
[[Page 4316]]
5. Calculation of NOX Emission Rate--LME Units
Background
EPA proposed to re-title Sec. 75.19(c)(4)(ii) as ``NOX
mass emissions and NOX emission rate'' and to add a new
subparagraph (D) to Sec. 75.19 (c)(4)(ii), providing instructions for
determining quarterly and cumulative NOX emission rates for
a 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. Then, the Agency proposed that 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.
Summary of Rule Changes
No adverse comments were received on these proposed rule changes
and the revisions to Sec. 75.19(c)(4)(ii) have been finalized as
proposed.
6. LME Units--Scope of Applicability
Background
EPA proposed to 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 is 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 is permitted. Parallel
revisions to Sec. Sec. 75.11(d)(3), 75.12(e)(3), and 75.13(d)(3),
consistent with the changes to Sec. 75.19(a)(1), were also proposed to
clarify the Agency's intent.
Summary of Rule Changes
No adverse comments were received on the proposed changes and they
have been finalized.
7. Use of Maximum Controlled NOX Emission Rate When Using
Bypass Stacks
Background
Revisions to Sec. 75.17(d)(2) were proposed that would allow a
maximum controlled NOX emission rate (MCR) to be reported
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.
For example, for 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 MCR, rather than
the MER, would be the more appropriate NOX emission rate to
report for the bypass hour(s). 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).
Summary of Rule Changes
Commenters were generally supportive of the proposed rule changes
and they have been finalized. One commenter recommended that parallel
language be added to Sec. 75.72(c)(3), to cover non-Acid Rain Program
units that are subject to the NOX mass emissions monitoring
provisions of Subpart H. EPA agrees with this comment and has added the
necessary language to Sec. 75.72(c)(3).
C. Certification Requirements
1. Alternative Monitoring System Certification
Background
EPA proposed to 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 in Sec. Sec. 75.40 through 75.48 that
alternative monitoring systems must meet in order to be certified.
Summary of Rule Changes
Commenters were supportive of the proposed amendments to Sec.
75.20(f), and they have been finalized.
2. Part 60 Reference Test Methods
Background
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). These test methods are
prescribed for Part 75 emission testing and RATAs. Three new testing
options that were added to the methods were deemed unacceptable for use
under Part 75. These include:
(1) Section 7.1 of revised EPA Method 7E, allowing for custom
calibration gas concentrations to be produced by diluting EPA protocol
gases, in accordance with Method 205 in Appendix M of 40 CFR Part 51.
(2) Section 8.4 of revised EPA Method 7E, allowing the use of a
multi-hole ``rake'' probe to satisfy the multipoint traverse
requirement of the method.
(3) Section 8.6 of revised EPA Method 7E, allowing for the use of
``dynamic spiking'' as an alternative to the interference and system
bias checks of the method.
Although revised Method 7E states that for use under Part 75 the
three options above require approval by the Administrator, EPA proposed
to add similar language to Sec. 75.22(a)(5) to reinforce its position
regarding these testing alternatives.
Summary of Rule Changes
No adverse comments were received on the proposed amendments to
Sec. 75.22(a)(5) and they have been finalized. However, one commenter
brought to EPA's attention another revision to the Part 60 reference
methods that impacts Part 75. EPA Method 20 was also revised on May 15,
2006. Method 20 has been the NOX emission test method
prescribed for combustion turbines (CTs) in section 2.1.2.2 of Appendix
E. Method 20 has also been used to determine fuel-specific
NOX emission rates for combustion turbines that qualify as
low mass emissions (LME) units under Sec. 75.19.
The original Method 20 required testing at 8 sampling points per
run, with typical run times averaging about 15 to 20 minutes. However,
the revised Method 20 no longer specifies the minimum number of test
points per run, but rather requires sampling point selection to be done
according to Method 7E. Revised Method 7E requires 12 traverse points
for an emission test run (which would suffice for Appendix E testing),
but the method also allows the results of stratification testing to be
used to justify using three or, in some cases, one sample point
instead. This raises questions about the required length of an Appendix
E test run. For instance, if testing were required at only one point,
each Appendix E test run would be reduced from 15-20 minutes to as
little as 2 minutes (depending on the system response time). The
commenter stated that such short sampling runs seem inadequate to
[[Page 4317]]
develop a substantial correlation curve for emission reporting. The
commenter recommended that EPA modify Appendix E or Method 20 and
either set a minimum run time of 20 minutes (providing an hour of data
at each load) or specify a minimum number of sampling points for an
Appendix E test of a CT.
EPA has incorporated the commenter's recommendations into Part 75.
First, Sec. 75.22(a)(5) has been amended to prohibit the use of Method
7E to determine the required number of sample points for the emission
testing of a combustion turbine. Section 75.22(a)(5)(ii) requires the
sample points to be determined according to section 2.1.2.2 of Appendix
E, instead. Second, for the emission test of a CT, section 2.1.2.2 of
Appendix E has been revised to require a minimum of 12 test points per
run, located according to EPA Method 1. Third, amendments have been
made to Sec. 75.22(a)(6), Sec. 75.19(c)(1)(iv)(A), section 6.5.10 of
Appendix A, and sections 2.1.2.2 and 2.1.2.3 of Appendix E, to remove
all references to EPA Method 20 from Part 75. Fourth, for the testing
of an Appendix E boiler, the text of section 2.1.2.1 of Appendix E has
been revised to require 12 traverse points per run, making it
consistent with revised section 2.1.2.2 (note that this is not a new
requirement--section 2.1.2.1 has always required 12 test points,
located according to section 8.3.1 of Method 3, and that section refers
back to Method 1). Finally, in section 2.1.2.3 of Appendix E, the
references to the measurement system response time in section 5.5 of
Method 20 (which section no longer exists) have been replaced with
references to the response time provisions in sections 8.2.5 and 8.2.6
of Method 7E. Appendix E tests performed on CTs prior to the effective
date of these amendments are grandfathered from the revised test point
location requirements.
3. Mercury Reference Methods
Background
EPA proposed to add an alternative relative deviation (RD)
specification for the results of mercury (Hg) emission data collected
with paired Ontario Hydro (OH) reference method sampling trains. The
principal RD specification in Sec. 75.22(a)(7) is 10 percent. However,
this acceptance criterion may be too stringent for sources with low Hg
emissions. Therefore, for average Hg concentrations of 1.0 [mu]g/m\3\
or less, EPA proposed an alternative RD specification of 20 percent.
This is consistent with the acceptance criteria for data from paired OH
trains, as specified in Performance Specification 12A in Appendix B of
40 CFR Part 60.
EPA also proposed amendments to Sec. Sec. 75.22(a)(7),
75.59(a)(7), 75.81(c)(1), and to sections 6.5.10 and 7.6.1 of Appendix
A, allowing EPA Method 29 (back-half impinger catch, only) 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). Two caveats on the use of Method 29 were proposed. First, sources
electing to use Method 29 (which is similar to the OH method, but
somewhat simpler and more familiar to stack testers) would be required
to use paired sampling trains (i.e., two trains sampling the source
effluent simultaneously), and the RD specifications in Sec.
75.22(a)(7) would have to be met for each run. Second, certain
analytical and quality assurance (QA) procedures in the OH method (ASTM
D6784-02) would have to be followed instead of the corresponding
procedures in Method 29 (because the analytical and quality assurance/
quality control (QA/QC) requirements of the OH method are more detailed
and rigorous than those in Method 29), and testers could opt to follow
several of the sample recovery and preparation procedures in the OH
method instead of the Method 29 procedures.
Finally, the Agency solicited comment on the use of sorbent traps
for reference method testing. Members of the regulated community had
expressed an interest in using portable sorbent trap monitoring systems
for Hg reference method testing, as an alternative to the OH method.
EPA proposed to accommodate a possible future sorbent-based reference
method by adding language to Sec. 75.22(a)(7) that would allow an
``other suitable'' reference method approved by the Administrator to be
used for Hg emission testing and RATAs.
Summary of Rule Changes
Commenters were generally supportive of the proposed amendments
that would add Method 29 as an alternative Hg reference method, and
those provisions have been finalized without substantive change. One
commenter objected to the requirement to use paired sampling trains for
OH and Method 29 tests, asserting that this adds to the cost of testing
and may result in significant numbers of test runs being discarded.
However, EPA does not agree with the commenter. The Agency believes
rather that paired sampling trains provide added assurance of data
quality when these test methods are used. The decision to require
paired trains for the OH method was made during the rulemaking that led
to publication of the Clean Air Mercury Regulation (CAMR) (see 70 FR
28636-28639, May 18, 2005).
Two commenters supported the proposed 20 percent alternative RD
specification for low emitters, and that provision has been finalized.
However, one of the commenters noted that even a 20 percent RD
specification may be too stringent for extremely low Hg concentrations.
EPA agrees that when Hg concentrations are exceptionally low (0.1
[mu]g/m\3\ or less), the 20 percent RD specification may be difficult
to meet. Therefore, the final rule adds a third tier to the RD
specifications in Sec. 75.22. The paired train agreement is also
considered to be acceptable if the absolute difference between the two
measured Hg concentrations does not exceed 0.03 [mu]g/m\3\.
Several commenters strongly supported the proposal to allow the use
of a sorbent-based reference method for Hg emission testing and for the
RATAs of Hg monitoring systems. Since publication of the proposed rule,
a great deal of progress has been made in this area. First, EPA
conducted a Method 301 analysis of available data comparing sorbent
trap sampling to the OH method. The results of this analysis showed
that a sorbent-based sampling method can be a viable alternative
reference method. Second, EPA drafted ``Method 30B'', a reference
method that uses iodated carbon traps to measure vapor phase Hg
emissions. Finally, as part of a direct final rulemaking, Method 30B
was published on September 7, 2007 (see 72 FR 51494-51531), along with
Method 30A, an instrumental Hg reference method. Today's final rule
allows both Methods 30A and 30B to be used.
D. Missing Data Substitution
1. Block Versus Step-Wise Approach
Background
Historically, EPA's policy has required sources to use a ``block''
approach for CEMS missing data substitution. The percent monitor data
availability (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 reconsidered and revised its missing
substitution data policy, to allow sources to apply the missing data
algorithms in a stepwise manner instead of using the block approach.
Under the
[[Page 4318]]
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.
Since Part 75 is not clear about which of the two methods should be
used for missing data substitution, EPA proposed to amend Sec. Sec.
75.33 and 75.32(b), to clarify that the stepwise, hour-by-hour method
is the preferred one, and that use of that method would be required for
all CEMS data recorded on and after January 1, 2009, and for any CEMS
data recorded in XML-format during the transition year of 2008.
Summary of Rule Changes
Commenters unanimously supported the proposal to adopt stepwise
missing data substitution and the proposed amendments to Sec. Sec.
75.32 and 75.33 have been finalized.
2. Substitute Data Values for Controlled Units
Background
For units with add-on emission controls, when the PMA for
SO2 or NOX is below 90.0 percent, Sec.
75.34(a)(3) has historically allowed the designated representative (DR)
to petition the Administrator under Sec. 75.66 for permission to
report the maximum controlled concentration or emission rate recorded
in a specified lookback period instead of reporting the maximum value
recorded in that lookback period, for each missing data hour in which
the add-on controls are documented to be operating properly. After more
than ten years of implementing the Acid Rain Program, EPA no longer
believes that such special petitions are necessary, 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.
In view of this, the Agency proposed to 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 also proposed 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 missing data 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, except that the MEC, rather than
the MPC, would be used in the calculation. The proposed alternative
data substitution methodology in Sec. 75.34(a)(5) would ensure that
the substitute data values for the fourth missing data tier are always
higher than the corresponding substitute data values for the third
tier.
Finally, EPA proposed to 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).
Summary of Rule Changes
Comments on the proposed alternative missing data substitution
values for controlled units were generally supportive and these
provisions have been finalized. Two commenters requested that parallel
language be added to Sec. 75.72(c)(3), to extend the use of the new
missing data provisions to ozone season-only reporters. Another
commenter asked EPA to clarify that the MCR may be implemented on a
fuel-specific basis. EPA has incorporated both of these suggestions in
the final rule. Two other commenters suggested that, for common stack
configurations, EPA should allow the substitute data values to be
apportioned or prorated in some way instead of requiring maximum
potential values to be reported, in cases where the emission controls
installed on some of the units sharing the stack are documented to be
operating properly, but such documentation cannot be provided for the
controls on the other units. The Agency believes that this approach
would unnecessarily complicate the missing data substitution process
and would provide no assurance that emissions are not being
underestimated. Therefore, this suggestion was not incorporated in the
final rule.
3. Substitute Data Values for Hg
Background
EPA proposed to revise the Hg missing data procedures. First, for
Hg CEMS, the text of Sec. 75.38(a) would be amended to clarify that
the 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 proposed to completely revise the missing data
provisions in Sec. 75.39 for sorbent trap monitoring systems, to make
them the same as for Hg CEMS, so that. the initial missing data
procedures of Sec. 75.31(b) and the standard Hg missing data
provisions of Sec. 75.38 would be followed for sorbent trap systems.
EPA believes that this proposed missing data approach greatly
simplifies the missing data substitution process for Hg monitoring
systems. 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, under the
proposal, when the owner or operator elects to use a primary Hg CEMS
and a backup sorbent trap system (or vice-versa), the appropriate
substitute data values would be derived from a lookback through the
previous 720 hours of quality-assured data, irrespective of
[[Page 4319]]
whether they were from the primary monitoring system or from the backup
system.
Summary of Rule Changes
Commenters were supportive of the proposed changes to the sorbent
trap missing data procedures in Sec. 75.39, and these provisions have
been finalized.
4. Correction of Cross-References
Background
For sources that report emissions data on an ozone season-only
basis, EPA proposed to revise Sec. 75.74(c)(3)(xi) and (c)(3)(xii) by
replacing references to specific missing data sections with more
general references to the entire block of CEMS missing data sections,
i.e., Sec. Sec. 75.31 through 75.37.
Summary of Rule Changes
No adverse comments were received on these proposed rule changes
and they have been finalized, as proposed.
E. Recordkeeping and Reporting
Background
To accommodate its new, re-engineered XML reporting format, which
will replace the current electronic data reporting (EDR) format in
2009, EPA proposed to revise the monitoring plan recordkeeping
requirements in Sec. 75.53, with corresponding revisions to Sec.
75.73(c)(3) (for sources reporting NOX mass emissions under
Subpart H) and to Sec. 75.84 (for sources reporting Hg mass emissions
under Subpart I).
EPA proposed 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. Under this proposal, the
provisions of paragraphs (g) and (h) would be followed instead of the
existing recordkeeping requirements of paragraphs (e) and (f), on and
after January 1, 2009. In 2008, sources would be allowed to choose
between the EDR format and XML, but new sources reporting for the first
time in 2008 would be strongly encouraged to use the XML format.
Included among the proposed monitoring plan changes would be mandatory
recording and reporting of the key rectangular duct wall effects data
elements using these record types. The proposed requirements to record
and report the results of wall effects adjustment factor (WAF)
determinations in the monitoring plan are found in Sec. Sec. 75.53 (e)
and (g) and in Sec. 75.64.
EPA also proposed to make a series of modifications to Sec. Sec.
75.58 and 75.59 to support the new XML data structure. The proposed
changes to the monitoring plan and recordkeeping sections were
presented, section-by-section, in Tables 1, 2, and 3 in the preamble to
the August 22, 2006 proposed rule.
Summary of Rule Changes
No significant adverse comments were received on the proposed
changes and they have been finalized.
1. Other Reporting Issues
a. Long-Term Cold Storage and Deferred Units
Background
EPA proposed changes to Part 75 to clarify the meaning of the term
``long-term cold storage (LTCS)'', found in Sec. 75.4(d). First, a
proposed 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, the
Agency proposed to add a new paragraph, (a)(7), to Sec. 75.61,
requiring the owner or operator to provide notifications when a unit is
placed in LTCS and when the unit re-commences operation. Third,
modifications to Sec. 75.20(b) were proposed, requiring
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 LTCS 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, for consistency.
EPA also proposed 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
proposed revisions would broaden the scope of Sec. 75.4(d) beyond the
Acid Rain Program, to include units in State or Federal pollutant mass
emissions reduction programs that adopt 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 proposed revisions to Sec. Sec. 75.4(d) and 75.61(a)(3) were
deemed necessary because the CAIR and CAMR rules do not address
deferred units.
The proposed revisions to 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, EPA proposed that the Part 75 continuous
monitoring systems would have to be certified within 90 unit operating
days or 180 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. Finally, the Agency proposed to revise the
notification requirements of Sec. 75.61(a)(3) to be consistent with
the proposed changes to Sec. 75.4(d).
Summary of Rule Changes
Commenters were generally supportive of the proposed long-term cold
storage provisions, requesting only minor clarifications. These
provisions have been finalized with no substantive changes. One
commenter encouraged EPA to adopt the proposed amendments to broaden
the scope of Sec. 75.4(d), to ensure that deferred units under
programs such as CAIR and CAMR are provided with a reasonable window of
time in which to certify the required monitoring systems, when the
units resume operation. EPA has finalized these amendments to Sec.
75.4(d), as proposed.
b. Notice of Initial Certification Deadline
Background
EPA proposed to add a new paragraph (a)(8) to Sec. 75.61, 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, this date will always be a
particular number of calendar days or unit operating days after a unit
either:
[[Page 4320]]
(a) Commences commercial operation; (b) commences operation; or (c)
becomes an affected unit. For Acid Rain Program sources, 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.
Summary of Rule Changes
One commenter asserted that the requirement for sources to submit
to EPA a notification of the deadline for initial monitoring system
certification is unnecessarily burdensome and should not be
incorporated into Part 75. Another commenter requested that the
information be reported in the electronic monitoring plan, rather than
requiring a separate notification. EPA does not agree that reporting
this information will be burdensome or that it is appropriate to report
the date of the initial certification deadline in the electronic
monitoring plan. Rather, this date is an essential data element that
will be managed using the web-based CAMD Business System (CBS).
Therefore, the notification requirement can be met electronically using
the CBS. In view of this, the amendment to Sec. 75.61 has been
finalized, as proposed.
c. Monitoring Plan Submittal Deadline
Background
EPA proposed to amend Sec. 75.62(a) by changing 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, in order to synchronize the initial monitoring plan submittal
with the initial test notice. Corresponding changes to Subpart H (Sec.
75.73(e)) and to Subpart I (Sec. 75.84(e)) were proposed, for
consistency.
EPA also proposed to remove the requirement from Sec. 75.62(a)(1)
that the electronic 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, but this option would only be available to
sources reporting in the new XML format under the re-engineered data
submission process.
Summary of Rule Changes
No adverse comments were received on these proposed rule changes
and they have been finalized, as proposed.
d. EPA Form 7610-14
Background
EPA proposed to amend Sec. Sec. 75.63(a)(1) and (a)(2), to remove
the requirement to submit hardcopy EPA form 7610-14 along with every
certification or recertification application. Significant upgrades to
EPA's data systems have been made in recent years, and Form 7610-14 is
no longer needed to process these applications.
Summary of Rule Changes
No adverse comments were received on these proposed rule changes
and they have been finalized, as proposed.
e. LME Applications
Background
EPA proposed to remove the requirement from Sec.
75.63(a)(1)(ii)(A) for a hardcopy LME certification application to be
submitted to the Administrator. The proposal would require only the
electronic portion of the application, including the monitoring plan
and LME qualification records, to be sent to EPA's Clean Air Markets
Division. The hardcopy portion of the LME application would be sent to
the State and to the EPA Regional Office.
Summary of Rule Changes
No adverse comments were received on these proposed rule changes
and they have been finalized, as proposed.
f. Reporting Test Data for Diagnostic Events
Background
EPA proposed 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 proposed flexibility in the reporting of diagnostic test results
would only be available to sources reporting in the new XML format
under the re-engineered data submission process.
Summary of Rule Changes
No adverse comments were received on these proposed rule changes
and they have been finalized, as proposed.
g. Modifications to Sec. 75.64
Background
As part of its data systems re-engineering effort, EPA proposed to
revise Sec. 75.64(a) to describe the transition from the existing EDR
reporting requirements to the reporting requirements of the new XML
format. The Agency proposed to renumber several paragraphs, to replace
paragraphs (a)(1) and (a)(2) with new paragraphs (a)(3) through (a)(7),
and to remove existing paragraph (a)(8).
Summary of Rule Changes
No adverse comments were received on these proposed rule changes.
These amendments to Sec. 75.64(a) have been finalized, as proposed.
h. Steam Load Reporting
Background
EPA proposed to add a third option to Part 75 for reporting load
data 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. The Agency proposed to add text to several
sections in the main body of Part 75 and to the Appendices, to
accommodate the new reporting option.
Summary of Rule Changes
No adverse comments were received on these proposed rule changes
and they have been finalized, as proposed.
i. Test Notification Requirements--Hg Low Mass Emission Units
Background
Section 75.61(a)(5) requires the owner or operator or the
designated representative to provide 21-day advance notice for various
periodic quality-assurance tests, including the semiannual or annual
relative accuracy tests of CEMS, and for the re-tests of Appendix E
peaking units and low mass emissions (LME) units. Test notices must be
provided to the Administrator, to the appropriate EPA Regional Office
and to the State or local agency (unless a particular agency issues a
waiver from the requirement).
Under Subpart I of Part 75, certain low-emitting units covered by
the Clean Air Mercury Regulation (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. EPA proposed to expand the notification
requirements of Sec. 75.61(a)(5) and to add
[[Page 4321]]
corresponding introductory text to Sec. 75.61(a)(1), requiring the
owner or operator or the designated representative to provide at least
21 days notice of the scheduled dates of these periodic Hg emission
tests.
Summary of Rule Changes
No adverse comments were received on this proposed rule change and
this test notification requirement has been finalized, as proposed.
j. Hardcopy Reports for Retests of Hg Low Mass Emission Units
Background
Sections 75.60(b)(6) and (b)(7) 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. EPA proposed to 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 Hg emission tests required
under Sec. 75.81(d)(4) for low-emitting units covered by CAMR. The
proposed time frame for submitting these Hg emission test results would
be the same as the current one for the RATAs and Appendix E re-tests.
Summary of Rule Changes
No adverse comments were received and this provision has been
finalized, as proposed.
k. Wall Effects Adjustment Factors
Background
For sources with flow monitors installed on circular stacks,
reporting of wall effects information is currently required by
Sec. Sec. 75.64(a)(2)(xiii), 75.73(f)(1)(ii)(K) and
75.84(f)(1)(ii)(I), when Method 2H is used in conjunction with Method
2, 2F or 2G. The specific wall effects data elements that must be
reported are found in Sec. 75.59(a)(7)(ii) and (a)(7)(iii). These data
are submitted along with flow RATA results, as supplementary
information.
For rectangular stacks and ducts, some of the same supporting data
elements in 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, EPA proposed to 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 to add RATA support data elements to a new
paragraph, (vii), in Sec. 75.59(a)(7), to 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.
Summary of Rule Changes
No adverse comments were received on these proposed rule changes
and they have been finalized, as proposed.
F. Subpart H (NOX Mass Emissions)
1. Subpart H Diluent Monitoring Systems
Background
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''. EPA proposed to revise the text of Sec.
75.71(a)(2) accordingly.
Summary of Rule Changes
No adverse comments were received. This clarification of Sec.
75.71(a)(2) has been finalized, as proposed.
2. Identifying a NOX Mass Methodology
Background
EPA proposed to revise Sec. 75.72 to require that only one
NOX mass emissions methodology be identified in the
monitoring plan at any given time, and to disallow the designation of
primary and secondary NOX mass calculation methodologies.
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.
Summary of Rule Changes
No adverse comments were received. This provision has been
finalized, as proposed.
3. Reporting of Subpart H Facility Information
Background
Consistent with the proposed revisions to Sec. 75.64, EPA proposed
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.
Summary of Rule Changes
No adverse comments were received. This provision has been
finalized, as proposed.
4. Linearity Check Requirements for Ozone Season-Only Reporters
Background
For Subpart H sources that report emissions data on an ozone
season-only (OSO) basis, EPA proposed to revise the linearity check
provisions in Sec. 75.74(c)(2), (c)(2)(i), (c)(2)(ii), (c)(3)(ii),
(c)(3)(vi), and (c)(3)(viii). Historically, OSO reporters have been
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. In some
cases, this has resulted in CEMS out-of-control periods and has
required the use of missing data substitution. OSO reporters have also
been required 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 also not well-understood by the
affected sources and assessing compliance with the provision has been
difficult, since sources have not been required to report the results
of any off-season calibration error tests done prior to April.
In view of these considerations, EPA proposed to revise Sec.
75.74(c)(2) to require the pre-season linearity checks to be conducted
in the month of April, and to delete all references to
[[Page 4322]]
performing the pre-season linearity checks at other times. The Agency
also proposed to remove the conditional grace period provision from
Sec. 75.74(c)(2)(i)(D), and to address (in Sec. 75.74(c)(3)(ii)(E))
data validation in the case where the April linearity check is not
completed prior to the start of the ozone season. In that case, 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. A 168 unit operating hour period of conditional data
validation would be allowed, in which to perform the required linearity
check. Passing the linearity check on the first attempt within the
allotted time would result in the conditionally valid data becoming
quality-assured. Failing the linearity check would result in all data
from the monitor be invalidated back to the beginning of the ozone
season and the data would remain invalid until a linearity check is
passed. Performing the linearity check after the 168-hour period
expires would require the data validation provisions in Sec.
75.20(b)(3)(viii) to be applied, subject to the restrictions of Sec.
75.74(c)(3)(xii).
EPA proposed to 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, and to remove and reserve
related Section 75.74(c)(3)(viii). 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, the Agency proposed
that 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 a
linearity check is performed and passed in the third quarter, before
the 168 operating hour window expires, EPA proposed that this 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.
Summary of Rule Changes
The amendments to Sec. 75.74(c) have been finalized, as proposed.
Commenters supported EPA's proposal to allow a linearity check
performed in April to satisfy both the pre-season and second quarter
linearity check requirements. However, several commenters requested
that the Agency allow greater flexibility in the timing of the required
linearity checks. The proposed amendments requiring the pre-season
linearity check to be performed April and the 3rd quarter test to be
done in July were perceived as being too restrictive. EPA does not
agree with these commenters that the revised quality assurance
requirements for ozone season-only reporters lack flexibility. The
amendments allow sources to use conditional data validation for up to
168 unit or stack operating hours, in situations where the linearity
check cannot be completed by the prescribed deadline. If the required
test is performed and passed within the allotted window of time, the
source will incur no data loss. OSO reporters desiring greater
flexibility in scheduling quality assurance tests should seriously
consider switching to year-round reporting. Doing so would provide many
benefits, such as grace periods, test deadline extensions, and in some
cases, test exemptions.
5. RATA Requirements for Ozone Season Only Reporters
Background
For Subpart H sources that report NOX mass emission data
on an ozone season-only (OSO) basis, Part 75 has required, 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. In past years, this requirement has been 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. The rule has further required each
CEMS to be operated, calibrated and maintained in the time period
extending from the completion of the RATA, through April 30. 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.
In view of these considerations, EPA proposed to restrict the
window of time in which pre-season RATAs may be performed. As 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. That restriction
would prohibit RATAs done in the previous year from being used to
validate data in the current ozone season.
EPA also proposed to revise Sec. 75.74(c)(2)(ii)(F), to address
data validation. The proposed data validation rules for RATAs are
similar to those proposed for linearity checks, in that a period of
conditional data validation (720 operating hours) would be allowed when
the pre-season RATA is not completed by the April 30th deadline.
Consistent with these revisions, the Agency proposed to delete the data
validation and conditional grace period provisions in Sec.
75.74(c)(2)(ii)(G) and (c)(2)(ii)(H) and to remove and reserve Sec.
75.74(c)(3)(vi), (vii), and (viii).
Summary of Rule Changes
The amendments to Sec. 75.74(c) have been finalized, as proposed.
One commenter objected to the proposed restriction on the timing of the
RATAs and requested that the existing flexibility in the rule be
retained. The commenter expressed a strong preference to perform RATAs
in the autumn, rather than in the January-April time frame proposed by
EPA. A second commenter stated that EPA should remove the requirement
to keep records of off-season daily calibration and interference check
records in a format suitable for inspection from Sec.
75.74(c)(2)(ii)(E)(1).
Regarding the first commenter's assertion that the proposed RATA
time frame for OSO reporters is too restrictive, EPA recommends that
the owner or operator seriously consider switching to year-round
reporting. Year-round reporting allows complete freedom to schedule
RATAs at any convenient time during the year and provides many
benefits, such as grace periods, test deadline extensions, and in some
cases, test exemptions. Even if EPA had decided not to amend the RATA
provisions for OSO reporters, Sec. 75.74(c)(2)(ii)(E)(1) would still
require the CEMS to be operated, maintained and calibrated in the time
period between the RATA and the start of the next ozone season. Thus,
if the RATAs are performed in the autumn (e.g., November), the CEMS
would have to be maintained and calibrated for at least 10 months of
the year; in this case, OSO reporting offers no clear advantage over
year-round reporting.
EPA did not incorporate the second commenter's suggestion to remove
the recordkeeping requirement from Sec. 75.74(c)(2)(ii)(E)(1).
However, the text of Sec. 75.74(c)(6)(iii) has been revised to remove
the requirement to report the daily calibrations and interference
checks done in the month of April. The requirement to record these data
remains intact, but the reporting has been made optional.
[[Page 4323]]
6. Determining Peaking Status for Ozone Season Only Reporters
Background
EPA proposed 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.
Summary of Rule Changes
No adverse comments were received. This provision has been
finalized, as proposed.
7. Calculation of Ozone Season NOX Mass Emissions--LME Units
Background
EPA proposed to correct an organizational error in Subpart H of
Part 75. The proposal would remove Sec. 75.72(f), which describes
ozone season NOX mass calculations for units using the low
mass emission (LME) methodology under Sec. 75.19, and the basic
content of Sec. 75.72(f) 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.
Summary of Rule Changes
No adverse comments were received. This provision has been
finalized, as proposed.
G. Subpart I (Hg Mass Emissions)
1. Heat Input Provisions for Common and Multiple Stacks
Background
Due to an apparent oversight, the heat input monitoring provisions
for certain monitoring configurations in Subpart I of Part 75 were
inadvertently omitted when Subpart I was promulgated. In particular,
EPA found the heat input methodologies for common stacks shared by
affected and non-affected units and for multiple stack or duct
configurations to be missing. In view of this, the Agency proposed to
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. 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.
Summary of Rule Changes
No adverse comments were received. These provisions have been
finalized, as proposed.
2. Low Mass Emission Alternative
Background
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), as originally published, allowed 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 was
implied that the periodic retests for common stack configurations would
also have to be done at the unit level. EPA has reconsidered this
approach, believing it to be overly restrictive, unnecessarily
difficult, and costly to implement.
Therefore, EPA proposed 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 proposed option, the group of 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 amendments allowed 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, i.e.,
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.
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 have to be
``normal'', as defined in Section 6.5.2.1 of Appendix A.
EPA also proposed to revise Sec. 75.81(c)(1), to specify the
acceptable time frame in which to perform the initial certification
testing for the low mass emission option. As originally published, the
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.
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. This
also raises questions about which default emission rate to use for the
initial reporting. In view of these considerations, EPA proposed 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
[[Page 4324]]
(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 proposed to amend Sec. Sec. 75.81(d)(4) and (d)(5) to
address the emission testing requirements when the fuel supply is
changed. The proposed revisions would require additional Hg retesting
within 720 unit operating hours, following a change in the fuel supply.
The results of this retest would then be applied retrospectively, back
to the time of the fuel switch. The Agency also proposed to revise
Sec. 75.81(c)(1) 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 proposed revisions only
addressed 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. EPA solicited comments and suggestions on how to apply
the Hg low mass emitter option in situations 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 (i.e., what emission
testing and reporting requirements might be appropriate).
Summary of Rule Changes
Commenters were generally supportive of the proposed amendments
that would reduce the testing requirements for Hg low mass emission
units in common stack configurations. The final rule differs somewhat
from the proposal, however, in that it also allows the initial
qualifying test to be performed at the common stack, if certain
conditions are met. The conditions are: (1) Testing must be done at a
combined load corresponding to the designated normal load level (low,
mid, or high) defined in the monitoring plan; (2) 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; (3) the coal combusted
in each unit during the testing must be representative of the coal that
will be combusted in that unit at the start of the Hg mass emission
reduction program (preferably from the same source(s) of supply); and
(4) if flue gas desulfurization and/or add-on Hg emission controls are
used to reduce the level of emissions exiting from the common stack,
these emission controls must be operating normally during the emission
testing and the owner or operator must record parametric data or
SO2 concentration data in accordance with Sec.
75.58(b)(3)(i) to document proper operation of the controls.
For retests, provided that the required load level is attained and
that all of the units sharing the stack are fed from the same on-site
coal supply during normal operation, it is not necessary for all of the
units sharing the stack to be in operation during a retest. However, if
two or more of the units that share the stack are fed from different
on-site coal supplies (e.g., one unit burns low-sulfur coal for
compliance and the other combusts higher-sulfur coal), then the owner
or operator must either: (1) Perform the retest with all units in
normal operation; or (2) if this is not possible, due to circumstances
beyond the control of the owner or operator (e.g., a forced unit
outage), perform the retest with the available units operating and
assess the test results as follows. The Hg concentration obtained in
the retest is used for reporting purposes if the concentration is
greater than or equal to the value obtained in the most recent test.
However, if the retested value is lower than the Hg concentration from
the previous test, then the higher value from the previous test
continues to be used for reporting purposes, and that same higher Hg
concentration is used in Equation 1 to determine the due date for the
next retest.
The final rule expands the testing of groups of identical units
beyond identical units that share a common stack. Section
75.81(c)(1)(iv) has been amended to allow a subset of any group of
identical units to be tested according to Table LM-4 in Sec. 75.19,
whether or not the units share a common stack. This amendment is
modeled after the provisions of Sec. 75.19(c)(1)(iv)(B) for testing
groups of identical LME units.
Several commenters objected to the proposed requirement to perform
retesting of low mass emission units when the fuel supply is changed.
Concerns were expressed that the term ``change in fuel supply'' is not
clearly defined and could be interpreted to require frequent,
unnecessary retesting, especially in light of the variation in coal
supplies from day to day in competitive wholesale power markets. A
number of the commenters recommended that retesting be limited to
changes in coal rank or classification (e.g., changing from bituminous
coal to sub-bituminous coal). EPA has incorporated the commenters'
suggestion into the final rule. Section 75.81(d)(4) of the final rule
clarifies what constitutes a ``change in fuel supply'' that will
trigger LME retesting. If a unit switches to a different rank of coal
as the primary fuel for the unit, in-between the scheduled LME retests
(where coal rank is defined by ASTM D388-99), an additional LME retest
is required within 720 operating hours of the change. The results of
this retest are then applied retrospectively back to the date and hour
of the fuel switch. The four principal coal ranks are anthracitic,
bituminous, subbituminous, and lignitic. The ranks of anthracite coal
refuse (culm) and bituminous coal refuse (gob) are considered to be
anthracitic and bituminous, respectively.
Equation 1 in Sec. 75.81(c )(2), which is used to demonstrate that
a unit qualifies as a Hg low mass emissions unit, conservatively
estimates the unit's potential annual Hg emissions by assuming that it
operates at the maximum potential flow rate for 8,760 hours per year.
One commenter requested that EPA consider modifying Equation 1 to
conditionally allow a number of hours less than 8,760 to be used in the
calculations, the condition being that there is a Federally-enforceable
permit provision in place, limiting the unit's annual operating hours.
EPA has incorporated this suggestion into the final rule. The term
``8,760'' in Equation 1 has been replaced with ``N'', which will either
be 8,760 or the maximum number of operating hours per year allowed by
the unit's Federally-enforceable operating permit (if less than 8,760).
If the operating permit restricts the unit's annual heat input but not
the number of annual unit operating hours, the owner or operator may
divide the allowable annual heat input (mmBtu) by the design rated heat
input capacity of the unit (mmBtu/hr) to determine the value of ``N''.
Finally, no comments were received on the proposal to require that
the Hg emission testing for initial certification of a low mass
emission unit be done no more than 1 year prior to the applicable
compliance date. Therefore, this provision has been finalized, as
proposed. For units subject to the Clean Air Mercury Regulation (CAMR),
the certification deadline is January 1, 2009. In view of this, only
those Hg emission tests of candidate low mass emission units that are
performed on and after January 1, 2008 will be accepted for initial
certification.
3. Harmonization of Subpart I With Other Proposed Rule Revisions
Background
Subpart I of Part 75 also contains a recordkeeping and reporting
section (Sec. 75.84). which, for the most part, cross-references the
primary monitoring
[[Page 4325]]
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.
To make Subpart I consistent with the proposed revisions to the
monitoring plan, recordkeeping, notification, and reporting sections of
Part 75, EPA proposed to make a number of minor adjustments to the text
of Sec. Sec. 75.84(c)(3), (e)(1), (e)(2), and (f)(1).
Summary of Rule Changes
No adverse comments were received. These provisions have been
finalized, as proposed.
H. Appendix A
1. CO2 Span Values
Background
EPA proposed 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.
Summary of Rule Changes
No adverse comments were received. This provision has been
finalized, as proposed.
2. Protocol Gas Audit Program
Background
EPA is responsible for implementing air quality programs that rely
heavily on the accuracy of calibration gas standards. 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. One notable result of these audits was a steady,
significant reduction in the failure rate of the audited gas cylinders,
from about 27% in 1992 down to 5% in 1996. The annual audits were
discontinued after 1996. Then, in 2003, EPA conducted a ``surprise''
audit of 14 national specialty gas producers and found that the failure
rate had risen to 11%.
In view of this, EPA proposed to establish a Protocol Gas
Verification Program (PGVP) and would require that EPA Protocol Gases
being used for 40 CFR Part 75 purposes be obtained from specialty gas
producers who participate in the PGVP. As proposed, the rule would
allow only program participants to market their gas standards as ``EPA
Protocol Gases.'' EPA proposed to maintain a web site, listing the PGVP
participants and the audit results, in order to provide calibration gas
users with detailed information about the quality of EPA Protocol
Gases.
EPA also proposed to: (1) Add a definition of ``specialty gas
producer'' to Sec. 72.2; (2) delete several calibration gas standards
and reference materials from section 5.1 of appendix A (believing them
to be prohibitively expensive and not used in practice by Part 75
sources); (3) remove from Sec. 72.2 the corresponding definitions of
the deleted calibration gas standards; and (4) consolidate the
remaining calibration gas standards under section 5.1 of appendix A.
Finally, EPA requested 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 other EPA Protocol gases to be within 2
percent of the certified tag values.
Summary of Rule Changes
Only one organization commented on the proposed protocol gas
verification program (PGVP). The commenter stated that a transition
period is needed to implement the program. Sources need time to
communicate with their gas vendors regarding their participation in the
PGVP. The commenter further asserted that the PGVP would be disruptive
and costly, both in the short-term and in the long-term, and that the
affected sources would bear the brunt of the cost impact.
EPA agrees with the commenter regarding the need for a transition
period. The final rule amends section 5.1.4 (c) to have the Protocol
Gas Verification Program (PGVP) take effect on January 1, 2009. As the
commenter has stated, the costs of the PGVP will be borne by the Part
75 sources using the calibration gases, and the Agency notes that these
minimal costs ($5 to $10 added to a $500 to $1,000 cylinder) will be
offset by the savings generated by fewer failed calibration error
tests, linearity checks, and relative accuracy test audits.
3. Requirements for Air Emission Testing Bodies
Background
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. In view of this, EPA
proposed to 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 that
an air emission testing body (AETB) is competent to perform emission
tests of stationary sources.
Proposed revisions to Section 6.1.2 of Appendix A, Section 2.1 of
Appendix E, and Section 1 of Appendix B make it clear that this
requirement would apply 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.
EPA also proposed to incorporate ASTM Method D7036-04 by reference
in Sec. 75.6(a)(45), and to add a definition of ``Air Emission Testing
Body'' to Sec. 72.2.
Summary of Rule Changes
The amendments to Section 6.1.2 of Appendix A, Section 2.1 of
Appendix E, and to Section 1 of Appendix B, requiring AETBs to conform
to ASTM D7036-04, have been finalized, as proposed. Two commenters
strongly supported the proposed revisions. However, several others
objected to them, believing they would be costly and burdensome,
without producing any noticeable improvement in data quality. EPA does
not agree with these commenters, for the following reasons.
The experience of the State and Federal regulators in the ASTM work
group indicates that implementation of the ASTM Practice will result in
improved data quality. EPA believes the evidence is abundant that
unqualified, under-trained and inexperienced testers are often deployed
on testing projects. The Agency has had experiences with tests that
have been invalidated or called into question due to poor performance
by testing contractors (see Docket Items OAR-2005-0132-0009, -0021, and
-0035). Conformance with ASTM D7036-04 does not guarantee that every
test will be performed properly. However, it will reduce the likelihood
of problems. Furthermore, it provides a guideline for both regulatory
agencies and affected sources to evaluate and select competent testing
[[Page 4326]]
firms. One of the cornerstones of the Practice is that AETBs must
collect performance data on how well they plan and execute test
projects. These data must be shared with regulators and clients upon
request.
In response to claims that ASTM D7036-04 will significantly
increase the cost and burden of Part 75 testing, EPA notes that no data
were provided to support these claims. The ISO 17025 standard upon
which the ASTM standard is based has been implemented in Europe for
many years. Mark Elliot, Chairman of the Stack Testing Association
(STA) of Great Britain, has provided the following information on the
costs of their programs. Their certification program (for individuals)
is called MCERTS.
MCERTS testing fees: Level 1 $350; Level 2 $940
Technical endorsements (1-4): $350 each
The Level 2 certification requires a personal interview with the
applicant. Please note that according to Mr. Elliot, this program has
been successfully implemented in the UK with no small companies going
out of business and no complaints of being overly burdensome on
industry. In fact, many large companies such as Mobil, Dow, Pfizer, and
3M are members of the STA and fully support the program because,
according to Mr. Elliot, they believe it improves the quality of the
data provided by testing companies. Even major UK utility companies
such as Drax Power, Energy Power Resources, the Electricity Supply
Board, PB Power, Scottish and Southern Energy, and Scottish Power
participate in the program. And they do this voluntarily because they
have found it to their benefit to do so.
There are several differences between the program described in the
final rule and the UK program. First, the final rule does not require
accreditation. The individual testing requirements in the rule are less
expensive and less stringent than the UK program. In the US, The Source
Evaluation Society is currently providing Qualified Individual testing.
The fees are $155 for the first test (including a one-time $15 SES
membership) and $89 for any subsequent tests taken during the same
testing session). It should also be noted that ASTM D7036-04 does not
require that every individual be tested. Only one ``Qualified
Individual'' need be present on-site during a test. Therefore, even
this minimal cost and burden is considerably less than the successful
UK program.
The costs of coming into initial compliance with the ASTM D7036-04
standard depend on the current state of an AETB's quality program.
Those that do not currently have an organized quality program will most
likely incur greater costs than those who do. In any case, the burden
will be no greater than that experienced by the UK companies who
successfully went through the same process.
The main costs to comply with the ASTM D7036-04 standard are
associated with taking a stack test QSTI (qualified stack test
individual) competency exam, and developing or revising a quality
assurance (QA) manual. A nationwide compliance cost estimate may be
obtained using the following estimates:
450 stack test companies in U.S. (The number of private
(external) stack test companies came from http://www.epa.gov/ttn/emc/software.html#testfirm.
RMB Consulting, Inc. estimated 10 in-house
utility RATA test teams in the U.S.);
On average, 10 people per company (Source: http://www.epa.gov/ttn/emc/software.html#testfirm
);
QSTI exam (required by ASTM) costs $150 and must be taken
every 5 years (Source: December 11, 2006 letter from the Source
Evaluation Society in Docket OAR-2005-0132); and
Roughly 1 QSTI is required for every 3 people in a stack
test company.
Using these inputs, the Agency estimates the cost to comply with
ASTM D7036-04 at about $100 per yr per company to cover the QSTI exam.
There is also approximately a $4,000 one time cost per company, whether
a large or small entity as defined by the Small Business
Administration's (SBA) regulations at 13 CFR 121.201, to develop a QA
manual (estimate provided by Air Tech, see Docket Item EPA-
HQ-OAR-2005-0132-0093). However, the costs will be borne by the Part 75
sources using the air emission testing bodies, and the Agency notes
that these costs will be offset by the savings generated by fewer
failed or incorrectly performed relative accuracy test audits, and
fewer repeat tests required. Therefore, the effect of this revision is
to actually relieve a regulatory burden on these entities.
Regarding the issue of the financial impact on smaller companies
and the request to provide funds to these companies, EPA notes that
small stack test companies were represented on the ASTM work group. At
least one small stack test company (3 people) has already complied with
ASTM D7036-04, is supportive of the requirement, and expects to
actually realize an increase in business because of their compliance
with ASTM D7036-04. As stated in another response, the costs to comply
with ASTM D7036-04 are reasonable. Similar requirements have been
successfully implemented for many years in the UK with no small
companies going out of business and no complaints of being overly
burdensome on industry. EPA does not expect to provide funds to support
small stack test companies in meeting the requirements of ASTM D7036-
04.
EPA notes that virtually the same program has been in place in
Europe for several years and is functioning very well with the support
of stack testers, the government, and industry. The ASTM standard is
actually less stringent in some areas than the European program. Based
on this extensive experience in Europe, EPA believes that this program
can be successfully implemented here in the U.S. with very little
additional burden. In summary, there is an abundance of both data and
experience showing that this program can be implemented without an
unreasonable burden, and also (according to UK industry participants)
that it will improve the quality of data.
Two commenters asserted that the existing infrastructure is not
adequate for testers to comply with the ASTM method. EPA disagrees with
these claims. The Source Evaluation Society is currently offering
qualification exams in several areas. The commenters may be concerned
that the SES website used to state that their exams may not
specifically satisfy the requirements of the ASTM Practice (because
they were not developed specifically for that purpose). However, SES
has updated the wording on their Web site to say that their
qualification exams do meet the exam requirement of the ASTM Practice.
The Stack Testing Accreditation Council (STAC) also recognizes that not
only does the SES program meet the requirements of the ASTM standard--
it actually exceeds them. It requires more experience than the ASTM
standard and also requires letters of recommendation. Both EPA and STAC
accept an SES certification as meeting the external testing and
experience requirements of the ASTM Practice.
If an external QSTI test is not available to a company, an internal
test may be used to meet the requirements of ASTM D7036-04 until an
external test becomes available. EPA is aware of at least one large
stack test company that has developed a training module for mercury
methods meeting the requirements of the ASTM D7036-04, and has trained
and tested their people according to the internal qualification exam
provision of ASTM D7036-04. When a third party test becomes
[[Page 4327]]
available, this company has indicated that they will re-certify their
people according to the requirements of ASTM D7036-04. The Source
Evaluation Society is reviewing steps to improve and expand the QSTI
examination process.
Four commenters asked EPA to clarify how compliance with ASTM
D7036-04 would be determined. Section 6.1.2 in Appendix A of the final
rule specifically states that there are two ways an AETB can certify
compliance: (1) A certificate of accreditation, or (2) a letter of
certification signed by senior management. The latter option is similar
to the way major sources certify compliance with their Title V permits.
However, AETBs are under much more direct regulatory scrutiny than a
Title V source. Every state has a field test observer program. In the
case of one large stack testing company, Clean Air Engineering, about
half of their compliance tests are directly observed by state
regulators. This oversight provides an on-going check of whether an
AETB remains in conformance. In co-operation with the New Jersey DEP, a
standardized state observer checklist is being developed that will
facilitate incorporating state observer assessments into the ASTM
process.
EPA expects to treat non-compliance with this standard in the same
way it treats noncompliance with any other standard--using its
enforcement discretion. EPA does not anticipate invalidating test
results because of minor infractions. The proper way to deal with these
issues, if either the regulatory authority or the client discovers
them, is to notify the AETB that a problem has been found. The AETB is
then obligated to initiate a corrective action to address the problem.
This becomes part of the AETB's Performance Data required by the
Practice. The Agency recommends that the client also ask the AETB to
report back on what corrective actions were taken. In the case of
serious infractions, EPA may exercise the same authority it has always
had to reject the test.
EPA encounters deviations in test methodology routinely in
reviewing stack test reports. Minor deviations are noted and reported
back to the source but the underlying results are accepted. Major
deviations result in a rejection of the test. This situation is no
different. This Practice should be treated much like a test method in
this regard. Minor deviations may be of the type the commenters cite in
their examples. Major deviations may include (for example) not having a
Qualified Individual on-site, not having proper calibration records for
the equipment used, or failing to follow through with corrective
actions when required.
There will undoubtedly be some discussions between EPA, affected
sources and AETB's as this program unfolds that will help define the
implementation of the Practice. But this is the case with every new
rule and standard.
There is always a balance in standard writing between being overly
detailed and prescriptive and being too loose and flexible. The
stakeholders involved in the consensus process of ASTM determined that
the proper balance had been achieved. It is important to keep in mind
that ASTM D7036-04 is essentially an international standard that has
been used successfully in countries all over the world.
Three commenters requested that EPA provide a 1-2 year transition
period after promulgation of the final rule, to allow AETBs sufficient
time to conform to ASTM D7036-04. Particular concerns were expressed
about the availability of Qualified Individuals (QIs) for Hg emission
testing. EPA agrees that a transition period is appropriate, given the
testers' relative unfamiliarity with Hg test methods. Therefore, the
final rule gives AETBs until January 1, 2009 to comply with ASTM D7036-
04.
A number of other comments were received on the proposed AETB
certification program. These are addressed in detail in the Response to
Comments (RTC) document.
4. Linearity Requirements for Dual-Span Applications
Background
In May 1999, EPA revised the linearity check provisions in Part 75,
Appendix A, section 6.2, to exempt SO2 and NOX
span values of 30 ppm or less from performing linearity checks. Since
the May 1999 revisions became effective, 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. In view of
this, EPA proposed to 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.
Summary of Rule Changes
The proposed amendments to Section 6.2 of Appendix A have been
finalized, without substantive change. At the request of one commenter,
the final rule clarifies that the low-span linearity exemption applies
to recertification as well as to initial certification and ongoing QA.
5. Dual Span Applications-Data Validation
Background
EPA proposed 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. Sections 2.1.1.5(b) and 2.1.2.5(b) of Appendix A
have provided instructions for reporting SO2 and
NOX concentration data when the full-scale range of the
monitor is exceeded. For single-range applications, reporting a value
of 200 percent of the range has been required when a full-scale
exceedance occurs. For dual range applications, if the low range is
exceeded, no special reporting has been 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 sources
have been required to report the maximum potential concentration (MPC).
Believing that 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'' to be too general, the Agency proposed
to 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 be reported until the expired high-range test is
redone or until the data return to the low scale. Thus, the proposed
revisions would clarify that when the low range is up-to-date on its QA
tests but the high range is not, the QA status of each range is
evaluated separately.
[[Page 4328]]
Summary of Rule Changes
No adverse comments were received. These provisions have been
finalized, as proposed.
6. Cycle Time Test-Stability Criteria
Background
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 test is
designed to determine how long it takes for a monitor to respond to
step changes in gas concentration. Two calibration gases (zero- and
high-level) are used for the test, which has both an upscale and a
downscale component.
Section 6.4 has specified criteria for determining when a stable
gas concentration 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 can become overly stringent and difficult to
meet. In view of this, the Agency proposed to 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.
Summary of Rule Changes
Substantive changes have been made to the cycle time test
procedure, in response to comments received. The sequence of the test
has been reversed, i.e., it now begins with a stable reading of stack
emissions and ends with a stable reading of calibration gas
concentration (see section 2.6 of the Response to Comments document for
further discussion). Commenters were generally supportive of the
proposed alternative stability criteria, and these have been
incorporated into the final rule. One commenter noted the absence of
corresponding alternative stability criteria for Hg monitors. To
correct this apparent oversight, the final rule includes an alternative
specification of 0.5 [mu]g/m\3\ for Hg CEMS. The same commenter also
expressed concerns about temporal variations in stack gas concentration
(particularly for Hg) that can make it difficult to meet the stability
criteria, and recommended that the order of the cycle time test be
reversed, i.e., begin the test by measuring stack gas emissions and
then inject the calibration gas. EPA agrees with this comment and has
revised the cycle time test procedure and Figure 6 in Appendix A
accordingly. EPA believes this change in the test procedure (which is
closer to the way in which the test was originally presented in the
January 1993 rule) gives a more accurate indication of the monitor's
true response time and will help to prevent ``false positive'' test
failures.
EPA has also revised the reporting requirement (in Appendix A Sec.
6.4) for cycle time tests of dual range monitors in light of the
transition to the revised XML format. The change requires that cycle
time for both ranges of a component be reported separately (consistent
with the reporting of other component level tests for CEMS), rather
than only reporting the results from the range with the longer cycle
time. This change is consistent with the proposed changes that required
reporting of certain test at the component level rather than at a
system/component level, which overall reduces redundant reporting of
test data from shared components. No adverse comments were received on
those similar proposed changes. This revision was necessary for
consistency with those other proposed changes which EPA is finalizing.
7. System Integrity and Linearity Checks of Hg CEMS
Background
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, has been 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 has been
provided. EPA proposed to restructure paragraph (3) of Section 3.2, to
add the necessary mathematical procedure.
Believing that 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), the Agency also proposed to make the linearity and system
integrity check specifications for Hg monitors the same, i.e., 5.0
percent of the span value, with an alternative specification to 0.6
[mu]g/m\3\ absolute difference between the reference gas value and the
monitor response.
Summary of Rule Changes
In the final rule, the performance specifications for the linearity
checks and system integrity checks of Hg monitors have been made the
same, but the proposed 5.0 percent of span criterion (with an
alternative specification of 0.6 [mu]g/m\3\) has not been adopted. The
commenters did not take issue with the proposal to equalize the
performance specifications for the two QA tests, but several commenters
objected to the proposed values of the specifications, citing a lack of
supporting data to demonstrate that the specifications are achievable.
Two commenters favored setting both specifications at the existing
values for the linearity check, i.e., 10.0 percent of the reference gas
value, with an alternative specification of 1.0 [mu]g/m\3\.
In response to these comments, EPA analyzed data from two recent
field studies in which elemental and oxidized Hg calibration gases were
injected into commercially-available Hg CEMS, at different
concentration levels (low, mid, high). Based on the results of the data
analysis, the Agency has concluded that equalizing the performance
specifications for linearity checks and system integrity checks of Hg
monitors at 10.0 percent of the reference gas value, with an alternate
specification of 0.8 [mu]g/m\3\ absolute difference is appropriate, and
the final rule incorporates these specifications.
A total of 97 data points from the two field studies were analyzed.
Data recorded during known periods of probe malfunction and excessive
analyzer drift were excluded from the analysis. Eighteen of the 97 data
points analyzed were elemental Hg injections, and the rest were
oxidized Hg injections. Each gas injection was evaluated on a pass/fail
basis against six candidate sets of performance specifications. These
were: (1) The proposed performance specifications, i.e., 5.0 percent of
span, with an alternative specification of 0.6 [mu]g/m\3\; (2) the
existing linearity specifications, i.e., 10.0 percent of the reference
gas value, with alternative specification of 1.0 [mu]/m\3\; (3) the
existing system integrity specification, i.e., 5.0 percent of span,
with no alternative specification; (4) 5.0 percent of span, with an
alternative specification of 0.8 [mu]g/m\3\ ; (5) 5.0 percent of span,
with an alternative specification of 1.0 [mu]g/m\3\; and (6) 10.0
percent of the reference gas value, with alternative specification of
0.8 [mu]g/m\3\. For each set of performance specifications, the pass
rate of the 97 gas
[[Page 4329]]
injections was determined. The two highest pass rates (96.9% and 95.9%)
were attained with sets (2) and (5), respectively, which have the
widest alternative specification of 1.0 [mu]g/m\3\. Similarly high pass
rates (93.8% and 94.8%) were also attained with sets (4) and (6), both
of which have an alternative specification of 0.8 [mu]g/m\3\. The
lowest pass rates (85.5% and 75.3%) were attained with sets (1) and
(3), the proposed performance specifications and the existing system
integrity check specification.
From these results, EPA concludes, on the one hand, that both the
proposed performance specifications (set 1) and existing system
integrity check specifications (set 3) may be too stringent. On the
other hand, very high pass rates were achieved with the four sets
having the wider alternate specifications of 1.0 [mu]g/m\3\ and 0.8
[mu]g/m\3\, i.e., sets (2), (5), (4), and (6). For these four sets, it
seems to make little or no difference whether the main specification is
5.0 percent of span or 10.0 percent of the reference gas value. In view
of these considerations, EPA has selected the main specification for
the system integrity and linearity checks to be 10.0 percent of the
reference gas value, and the alternative specification to be the more
stringent value of 0.8 [mu]g/m\3\. These values have been incorporated
into paragraph (3) of Section 3.2 in Appendix A.
8. Correction of Hg Calibration Gas Concentrations for Moisture
Background
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
is sometimes added to the calibration gas. This creates a potential
source of error in the calculations. In view of this, EPA proposed 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. The proposed
revisions would also require the calibration gas concentration to be
converted to a dry basis for purposes of performing the calibration
error calculations.
The Agency also proposed to add parallel language 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.
Summary of Rule Changes
No comments were received on the proposal. Therefore, the
provisions have been finalized, but there is one notable change. The
proposed rule inappropriately limited the requirement to account for
added moisture in the calibration gas to dry-basis Hg CEMS. In the
final rule text, this restriction has been removed. This is simply a
technical correction of a misstatement in the proposal.
9. Correction of Cross-References
Background
EPA proposed to 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 referred 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. Finally,
corrections to sections 6.5.6(b)(3) and 6.5.6.3 of Appendix A were
proposed, changing references to Section 3.2 of Performance
Specification No. 2 (PS2) to Section 8.1.3, of PS2.
Summary of Rule Changes
No adverse comments were received. These corrections have been
finalized, as proposed.
I. Appendix B
1. 3-Load Flow RATA Frequency and RATA Grace Period
Background
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''. As written, this rule
provision actually allows more than five years (20 calendar quarters)
to elapse between 3-load flow RATAs. For instance, if successive 3-load
flow RATAs are performed in the 1st quarter of 2002 and in the 4th
quarter of 2007, this satisfies the ``once every 5 consecutive calendar
years'' requirement, but there would be 23 calendar quarters between
the two tests.
In light of this, EPA proposed 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 both the other 5-year
testing requirements in Part 75 (i.e., for Appendix E and LME units)
and the maximum allowable interval between successive accuracy tests of
Appendix D fuel flowmeters.
EPA also proposed to revise the RATA grace period provisions in
Section 2.3.3, by removing the method of determining the deadline for
the next RATA after a grace period test from paragraph (c) of Section
2.3.3 and replacing it with a different method described in new
paragraph (d).
Paragraph (d) proposed a change to the methodology for determining
RATA deadlines, without changing the end result. The intent of
paragraph (c) in Section 2.3.3 had 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. However, for
infrequently operated units (e.g., many 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 proposed a simpler 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 two QA operating quarters
after the quarter of the test, if the RATA results trigger a semiannual
test frequency, and three QA operating quarters after the quarter of
the test if the RATA qualifies for an annual test frequency. As
proposed, there was one exception to these rules. Regardless of the
number of QA operating quarters that have elapsed following the grace
period test, the maximum allowable interval between a grace period RATA
and the next RATA would be eight calendar quarters. This is consistent
with Section 2.3.1.1(a) of Appendix B.
Finally, EPA proposed to amend paragraph (c ) of Section 2.3.3, to
state that when a RATA is performed after the expiration of a grace
period, the ``clock'' is reset, and the deadline for the next RATA is
determined in the usual manner, i.e., the next test would be due within
two QA operating quarters (for semiannual frequency) or four QA
operating quarters (for annual frequency), not to exceed eight calendar
quarters.
Summary of Rule Changes
Commenters were supportive of the proposed amendments to the RATA
grace period provisions, and no comments were received on the proposal
to determine 3-load flow RATA deadlines on a calendar quarter basis.
Therefore, these provisions have been finalized, as proposed.
[[Page 4330]]
2. RATA Requirement for Shared Components
Background
EPA proposed to 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. In such cases, the Agency
proposed that 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, and successful RATAs of both monitoring systems would
be required to get them back in-control.
Summary of Rule Changes
No adverse comments were received. This amendment has been
finalized, as proposed.
3. AETB Requirements
Background
EPA proposed to amend Appendix B 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.
Summary of Rule Changes
No adverse comments were received. This provision has been
finalized, as proposed.
4. Calibration Error Tests and Linearity Checks-Dual Range Applications
Background
EPA proposed to 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).
The proposed revisions to Section 2.1.1 of Appendix B would require
that ``sufficient'' calibration error tests be performed on the low and
high monitor ranges to validate the data recorded on each range, in
accordance with Section 2.1.5 of Appendix B. EPA also proposed to add a
new paragraph, (3), to Section 2.1.5.1 of Appendix B, to clarify how
the QA status of the low and high ranges is 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. Under
proposed paragraph (3), when 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 expires, this would have no effect on the QA
status of the other range.
Further, the Agency proposed to amend Section 2.2.3(e) of Appendix
B to make it clear that ``hands-off'' linearity checks of both ranges
of a dual-range analyzer are required whenever a linearity check on
either range fails or is aborted (unless, of course, a particular range
is exempted from linearity checks under Section 6.2 of Appendix A).
Summary of Rule Changes
These provisions have been finalized, as proposed. Two commenters
did not understand why failure of a calibration error test or a
linearity check on one scale of a dual-range analyzer should invalidate
data on both ranges, and asked for EPA to more fully explain the
technical basis for this requirement.
The requirement to perform calibration error tests or linearity
checks on both scales of a dual-range analyzer to resolve an out-of-
control period does not reflect a change in Agency policy. Rather,
EPA's proposal intended to clarify the existing requirement that each
range of a dual-range monitor must be known to be in-control in order
to validate data from the monitor.
The final rule allows data to be considered valid from a particular
measurement range that has passed a calibration error check when the
calibration error test for the other measurement range has expired. In
such instances, since there is no indication that the monitor is not
functioning properly, but there is evidence that the measurement range
being used is properly calibrated, EPA is allowing that range to be
considered quality assured. However, whenever a monitor fails any
required daily, quarterly, semi-annual or annual quality assurance
test, regardless of range, EPA maintains that data from that monitor
must be considered invalid until the required quality assurance tests
are passed. A failed test on either range of a dual range monitor
indicates a problem with the monitor's ability to accurately measure
emissions. While it is possible that in some instances, the problem
causing the failure of a test on one range does not affect the accuracy
of the monitor's measurements on the other range, it is far from
certain. Therefore, the Agency's firm position is that whenever a
calibration error test or linearity check is failed on either
measurement scale of a dual-range analyzer, it is necessary to
calibrate both ranges following corrective actions (which usually
involve adjustments to the monitor), to verify that the monitor is back
in-control and is able to generate quality-assured data on both ranges.
5. Off-Line Calibration Error Tests
Background
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. In view of this, the
Agency proposed to 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.
EPA proposed to revise paragraph (2) in Section 2.1.1.2 to state
that sources may make limited use of off-line calibrations if the off-
line calibration demonstration has been performed and passed. The
proposed changes to 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.
Summary of Rule Changes
Numerous commenters objected to the proposed revisions to Section
2.1.5.1 of Appendix B. The commenters found the proposed rule language
to be confusing
[[Page 4331]]
rather than clarifying, and several of them asserted that EPA appeared
to be placing new restrictions on the use of off-line calibration error
tests.
After careful consideration of these comments, EPA agrees that the
proposed rule language, particularly the term ``sequence of consecutive
unit operating hours'' can be misinterpreted. However, the Agency's
intent was (and is) simply to clarify the existing procedures for using
off-line calibrations to validate CEMS data. That is, a source desiring
to use the off-line calibration provisions in paragraph (2) of Appendix
B, section 2.1.5.1 must first pass the off-line calibration
demonstration described in section 2.1.1.2. After successfully
completing this demonstration, off-line calibrations may be used on a
limited basis for data validation. In particular, off-line calibrations
may be used to validate data for up to 26 consecutive unit operating
hours following a passed on-line calibration error test.
The term ``consecutive unit operating hours'' does not mean
consecutive clock hours. For example, two consecutive unit operating
hours could be separated by several hours, days, weeks, etc., due to a
unit outage. Each off-line calibration error test has the same
prospective, 26 clock hour window of data validation as an on-line
calibration error test.
Therefore, for a source that has passed the off-line calibration
demonstration, EPA considers the data for a particular operating hour
to be valid if there is: (1) A passed on-line calibration within the 26
unit operating hours preceding that operating hour; and (2) a passed
off-line calibration within the 26 clock hours immediately preceding
that operating hour. The Agency has revised the proposed rule language
to clarify these requirements. For each hour of unit operation, these
criteria will be used to evaluate each monitoring system's control
status with respect to daily calibrations.
6. Weekly System Integrity Check--Data Validation
Background
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, due to an apparent oversight, Section 2.6 did
not explain the consequences of either failing the test or failing to
perform the test on schedule. In view of this, EPA proposed to add the
following data validation rules for the weekly system integrity check
to Section 2.6 of Appendix B: (a) If the test fails, it would trigger
an out-of-control period until a subsequent system integrity check is
passed; and (b) 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.
The Agency also proposed to correct a typographical error in
Section 2.6 of Appendix B. The performance specification for the weekly
system integrity check was incorrectly referenced as Section 3.2 (c)(3)
of Appendix A. The correct citation is Appendix A, Section 3.2,
paragraph (3)(iii).
Summary of Rule Changes
The revision has been finalized as proposed. Several commenters
objected to the proposed data validation rules for weekly system
integrity checks of Hg CEMS. Commenters expressed concern that the
specified test frequency, i.e., once every 168 unit operating hours,
will cause scheduling difficulties, due to the limited availability of
qualified technicians and other factors. The commenters requested that
EPA provide a grace period of 72 to 96 hours for this QA test, to
minimize the possibility of data loss.
EPA does not agree with the commenters' assertions that the 168
operating hour requirement will be difficult to implement and that a
grace period should be added. The number of operating hours since the
last weekly system integrity check can (and should) be tracked by the
data acquisition and handling system (DAHS). An alarm or prompt could
be activated when the deadline for the next test is near (e.g., when
120 or 144 operating hours have elapsed since the last test).
EPA favors basing the interval between successive tests on
operating hours rather than clock hours in a week, primarily for
reasons of simplicity. The Agency acknowledges that this is distinctly
different from the way in which the deadlines for RATAs and linearity
checks are determined. For a RATA or linearity check, the deadline is
always at the end of a calendar quarter. Grace periods are provided for
these tests because the deadlines can pass while the unit is either
off-line or experiencing operational abnormalities that prevent the
monitors from being tested on time. Also, a limited number of RATA
deadline extensions and linearity check exemptions are provided for
``non-QA operating quarters'', i.e., calendar quarters in which the
unit operates for < 168 hours.
However, the required frequency for the system integrity checks of
a Hg CEMS is weekly, not quarterly. This is the only weekly QA test
required by Part 75. Therefore, the existing ``QA operating quarter''
model and grace period scheme cannot be directly applied to the system
integrity check. A new concept, perhaps a ``QA operating week'' would
have to be introduced and an appropriate grace period determined. EPA
considered this approach and decided against it, believing that it
would unnecessarily complicate the process of QA status tracking for Hg
CEMS.
The Agency believes that if the DAHS is programmed to track the
number of unit operating hours since the last system integrity check
and if an alert is provided to let plant personnel know when the test
deadline is approaching, there will seldom, if ever be a missed test.
Furthermore, the Agency believes that as experience is gained with Hg
monitors, it may be possible to automate the weekly system integrity
check so that during the 168th hour of operation since the last system
integrity check, the check is automatically initiated by the DAHS
computer system or other appropriate programmable logic controller
(PLC) systems. Such automation would further reduce the probability of
a missed test.
7. Correction of Hg Units of Measure--Figure 2
Background
EPA proposed to correct a minor error in the units of measure for
Hg concentration in Figure 2 of Appendix B, changing the units of
micrograms per dry standard cubic meter ([mu]g/dscm) to micrograms per
standard cubic meter ([mu]g/scm). This change was proposed because not
all Hg monitoring systems measure Hg concentration on a dry basis.
Summary of Rule Changes
No adverse comments were received. The proposed correction to
Figure 2 has been made.
J. Appendix D
1. Update of Incorporation by Reference
Background
As previously noted, EPA proposed to update the list of test
methods, sampling and analysis procedures, and other items that are
incorporated by reference in Sec. 75.6. As such, the proposed rule
[[Page 4332]]
included corresponding updates to the references in Appendix D.
EPA also proposed 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.
Summary of Rule Changes
These provisions have been finalized, as proposed. Note that in
response to a comment, EPA has also incorporated by reference ASTM
D5453-06, ``Standard Test Method for Determination of Total Sulfur in
Light Hydrocarbons, Spark Ignition Engine Fuel, Diesel Engine Fuel, and
Engine Oil by Ultraviolet Fluorescence'' \1\, and has added ASTM D5453-
06 to the list of acceptable oil sampling methods in Section 2.2.5 of
Appendix D (see section 2.7 of the Response to Comments document for
further discussion). In addition, the equation for Hourly SO2
Mass Emissions from the Combustion of all Fuels in Appendix D, section
3.5.1 has been revised to be consistent with the new XLM format. This
change is considered to be insignificant and was made to be consistent
with the proposed changes to harmonize the units of measure for
reporting hourly mass emissions.
---------------------------------------------------------------------------
\1\ ASTM D5453-05 is no longer available. EPA is thus adding
ASTM D5453-06, the version currently available. EPA considers this a
minor ministerial correction.
---------------------------------------------------------------------------
2. Pipeline Natural Gas--Method of Qualification and Monthly GCV Values
Background
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 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, the rule
has required that 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, the rule has required each one to meet the 0.5 gr/
100 scf total sulfur limit.
Many suppliers of natural gas regularly sample the total sulfur
content of the gas (in many cases, daily) and 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 asked 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. EPA has been
handling these requests individually, on a case-by-case basis. However,
the Agency believes it will be more efficient to address the issue
through rulemaking. In view of this, amendments to Sections
2.3.1.4(a)(2) and (e) of Appendix D were proposed.
For the initial documentation that the gas meets the 0.5 gr/100 scf
total sulfur limit, the proposed revisions to Section 2.3.1.4(a)(2)
would allow sources with at least 100 total sulfur samples from the
previous 12 months to reduce the data to monthly averages. Then, 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 from the previous 12 months have a
total sulfur content of 0.5 gr/100 scf or less, the fuel would qualify
as pipeline natural gas.
The proposed 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 the results of at least 100 total
sulfur samples from the past 12 months are obtained, 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 also proposed to clarify the gross calorific value (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, the Agency
proposed to revise Section 2.3.4.1 to require that the 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 in
the case where the owner or operator has elected to use the actual
monthly GCV value in the emission calculations, revisions to Section
2.3.7(c) of Appendix D were proposed, requiring the monthly average GCV
value to be applied starting from the latest date of any of the
individual GCV samples used to calculate the monthly average. In the
case where an assumed GCV value is used in the calculations (i.e.,
either a contract value or the highest monthly average from the
previous year), the assumed value would continue to be used unless
superseded by a higher monthly average GCV value.
Summary of Rule Changes
The provisions pertaining to documentation that a particular
gaseous fuel qualifies as pipeline natural gas have been finalized,
with only minor editorial changes. Regarding the proposed requirement
to average the results of all GCV samples of natural gas taken in each
calendar month, one commenter asked whether the monthly average would
be used to back-calculate the heat input values for each day in that
month.
The proposed revisions to Section 2.3.7(c) of Appendix D specified
that when the option to use the actual monthly GCV in the calculations
is selected and multiple samples are taken, each monthly average GCV
would be applied prospectively, starting on the date of the last sample
taken during the month. However, in light of the commenter's question,
EPA has reconsidered this approach. The final rule requires instead
that each monthly GCV value be applied to every day in that month. The
Agency believes that this approach provides a more representative
estimate of the unit's true monthly heat input.
Note that the text of paragraph (b)(2) in section 2.3.7 has also
been modified to address the new alternative methodology for making
annual assessments of the sulfur content of natural gas.
3. Requirement to Split Oil Samples
Background
For affected units that combust fuel oil and use the Appendix D
[[Page 4333]]
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 density of the oil (as applicable). 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.
Believing that the requirement to split and maintain oil samples
should only apply to samples that are taken at the affected facility,
EPA proposed to revise Section 2.2.5 of Appendix D to limit this
requirement to samples that are taken on-site. If this proposed
amendment were finalized, sources electing to sample each fuel lot
would no longer be required to split and maintain oil samples in cases
where the samples are taken off-site, from the fuel supplier's storage
container.
Summary of Rule Changes
No adverse comments were received. This provision has been
finalized, as proposed.
K. Appendix E
1. AETB Requirements
Background
EPA proposed 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 a LME unit, would have to conform to ASTM D7036-04.
Summary of Rule Changes
No adverse comments were received. This provision has been
finalized, as proposed.
2. Reporting Data When the Correlation Curve Expires
Background
For oil and gas-fired peaking units using the Appendix E
methodology to estimate NOX emissions, the owner or operator
is 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. However, the appropriate missing data procedure to follow
when a correlation curve expires has been conspicuously absent from
Section 2.5 of Appendix E. To address this deficiency, EPA proposed to
add a new Section, 2.5.2.4, to Appendix E, requiring the fuel-specific
maximum potential NOX emission rate (MER) to be reported,
from the date and hour in which a baseline correlation curve expires
until a new correlation curve is generated.
Summary of Rule Changes
No adverse comments were received. This provision has been
finalized, as proposed.
L. Appendix F
1. NOX Mass Calculations
Background
EPA proposed to revise the manner in which NOX mass data
are collected under the XML format that will be required in 2009 as
part of EPA's effort to re-engineer the Agency's data collection
systems. To achieve this, the hourly NOX mass emission rate
(lb/hr) would be reported instead of hourly NOX mass
emission (lb), when the source transitions from EDR reporting format to
the XML format.
To effect this, Equations F-24, and F-27 in Appendix F of Part 75
would have to be modified and Equation F-26 removed. However, since the
current EDR reporting format will continue to be supported through
2008, these equations must remain in the rule until the transition to
XML is complete. Therefore, EPA proposed to revise Section 8 of
Appendix F by adding Equations F-24a for the reporting of hourly
NOX mass emission rate (lb/hr) and Equation F-27a , for the
calculation of cumulative NOX mass emissions. In 2009, the
use of Equations F-24a and F-27a would become mandatory for all sources
and Equations F-24 and F-27 would no longer be applicable.
EPA also proposed to revise Section 8.2 of Appendix F, by splitting
it into two subsections, 8.2.1 and 8.2.2. Section 8.2 had described 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.
However, Section 8.2 simply cross-referenced other parts of the rule,
rather than showing the actual equations used. To correct this, the
Agency proposed to add Equation F-26a to subsection 8.2.1 and Equation
F-26b to subsection 8.2.2, clearly showing how the NOX mass
emission rate is calculated on a wet and dry basis, and to renumber
Equation F-26 in Section 8.3 as Equation F-26c. Proposed Equations F-
26a and F-26b have been used since 2002 by sources in the
NOX Budget Program, and the equations have been represented
in the EDR reporting instructions as Equations N-1 and N-2,
respectively.
Summary of Rule Changes
No adverse comments were received. These provisions have been
finalized, as proposed.
2. Use of the Diluent Cap
Background
EPA proposed to restrict the use of the diluent cap to
NOX emission rate determinations. The original purpose for
allowing the diluent cap to be used was to keep calculated
NOX emission rates from approaching infinity during periods
of unit startup and shutdown, when the diluent gas (CO2 or
O2) concentration is close to the level in the ambient air.
However, since 1999, Part 75 has allowed 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 have been allowed to use the
cap value for some of these calculations and not others, which 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,
the Agency proposed to remove all of the references in Sections 4 and 5
of Appendix F that allow the diluent cap to be used for other
parameters besides NOX emission rate.
Summary of Rule Changes
No adverse comments were received. These provisions have been
finalized, as proposed.
[[Page 4334]]
3. Negative Emission Values
Background
EPA proposed 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 proposed to require
0.0% CO2 to be reported as the average CO2 value
for that hour. Third, the Agency proposed 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.
Summary of Rule Changes
These provisions have been finalized, with one notable change. The
final rule will 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 hourly
heat input rate that is less than or equal to zero.
4. Calculation of Stack Gas Moisture Content
Background
EPA proposed to add Equation F-31 to a new Section 10 in Appendix
F, to be used to calculate stack gas moisture values from wet and dry
oxygen measurements, as described in Appendix A, Section 6.5.7(a).
Sources have been using this equation for many years and it has been
represented in the EDR reporting instructions as Equation M-1.
Summary of Rule Changes
No adverse comments were received. This provision has been
finalized, as proposed.
5. Site-Specific F-Factors (Single Fuel)
Background
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 has
never specified how much fuel sampling data is required to develop a
site-specific F-factor or how often the F-factor must be updated.
To address this issue, EPA proposed to 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.
Summary of Rule Changes
No adverse comments were received. These provisions have been
finalized, as proposed.
6. Prorated F-Factors
Background
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 has required 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 has never
specified 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.
To correct this situation, EPA proposed to revise the definition of
``Xi'' (the fraction of the total heat input derived from
each fuel) in the Equation F-8 nomenclature. The proposed revision
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.
Summary of Rule Changes
The revisions to Section 3.3.6.4 of Appendix F regarding the
prorating of F-factors have been finalized, with only minor changes.
However, several commenters requested that EPA consider allowing the
use of the ``worst-case'' (i.e., highest) F-factor as an alternative to
prorating, when combinations of fuels are co-fired. After careful
consideration of these comments, EPA is persuaded by the commenters'
arguments in favor of this option and has decided to incorporate this
suggestion into the final rule (see section 2.4 of the Response to
Comments document). New Section 3.3.6.5 of Appendix F allows sources
that burn combinations of fuels listed in Table 1 of Appendix F to use
the highest (``worst-case'') F-factor for any unit operating hour, in
lieu of prorating the F-factor. Note that in view of the revisions to
Section 3.3.6.4, Agency has deemed it necessary to modify the language
in Section 3.3.6.3 of Appendix F. Administrative approval of the F-
factor is no longer required when combinations of fossil fuels with
wood or bark are combusted, since F-factors for these fuels are listed
in Table 1. Rather, revised Section 3.3.6.3 requires Administrative
approval of the F-factor only when a fuel not listed in Table 1 is co-
fired with a fuel (or fuels) listed in the Table.
7. Default F-Factors
Background
In recent years, petroleum coke and tires have begun to be used as
primary or secondary fuels by a number of affected sources. In view of
this, EPA proposed 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 were 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. The Agency also proposed F-
factors of 9,819 dscf/mmBtu (for Fd) and 1,840 scf
CO2/mmBtu (for Fc) for sub-bituminous coal. All
of the proposed F-factors were calculated using Equations F-7a and F-7b
and representative composition and gross calorific value (GCV) data for
each fuel.
[[Page 4335]]
Summary of Rule Changes
These provisions have been finalized, with minor editorial changes.
One commenter recommended that the proposed F-factor values be rounded
off to the nearest multiple of 10, to be consistent with the other
values in Table 1. EPA agrees with this comment and has rounded off the
F-factors accordingly.
8. Revisions to Equation F-23
Background
Consistent with the proposed changes to Sec. 75.11(e), expanding
the applicability of Equation F-23, EPA proposed to amend Section 7 of
Appendix F (introductory text), and the Equation F-23 nomenclature.
Summary of Rule Changes
No adverse comments were received. These provisions have been
finalized, as proposed.
M. Appendix G
Background
Consistent with the changes to other parts of the rule, EPA
proposed 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.
Summary of Rule Changes
No adverse comments were received. These provisions have been
finalized, as proposed.
N. Appendix K
Background
EPA proposed to 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, paired sorbent
traps are required 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 in Appendix K specify consequences of varying severity. In
the months following promulgation of these rule provisions, EPA
revisited them and concluded that some of the consequences were too
lenient and others unnecessarily severe. The Agency therefore proposed
to revise them to make them more consistent and equitable.
Whenever one of the paired traps is accidentally lost, damaged, or
broken and cannot be analyzed, Sec. 75.15(h) has allowed the owner or
operator 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 no adjustment of the data
has been required to compensate for the loss of one of the samples. In
view of this, EPA proposed 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 also proposed 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 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 < plus-
minus>25 percent of the initial ratio established in the first hour of
the data collection period. However, the rule has stated that when this
criterion is not met, the appropriate consequences are to be determined
on a ``case-by-case'' basis. EPA has reconsidered this approach and now
believes that it allows for inconsistent application of the sorbent
trap monitoring methodology. Therefore, the Agency proposed to revise
Table K-1 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 STAF value of 1.222 is
applied to the measured Hg concentration.
Appendix K has required data from a sorbent trap monitoring system
to be invalidated whenever the relative deviation between the Hg
concentrations measured by the paired traps is greater than 10 percent.
EPA proposed 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. The Agency
also proposed, for consistency with the proposed changes Sec.
75.22(a), to revise Table K-1 to include an alternative relative
deviation specification of 20 percent for paired sorbent traps, when
low effluent concentrations of Hg (< = 1 [mu]g/m\3\) are encountered.
EPA further proposed to add two new paragraphs, (k) and (l), to
Sec. 75.15. Proposed Sec. 75.15(k) would have required 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 have required a diagnostic RATA of the
sorbent trap system whenever either the size of the sorbent traps or
the type of sorbent material was changed. Data from the modified
sorbent trap system would not have been 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.
Finally, revisions to section 7.2.3 of Appendix K were proposed,
requiring that the sample flow rate through a sorbent trap monitoring
system must be zero when the unit is not operating. EPA believes this
clarification is needed to prevent the system from sampling ambient air
during periods when the combustion unit is off-line, which would
artificially lower the Hg concentrations measured by the sorbent traps,
resulting in under-reporting of Hg mass emissions.
Summary of Rule Changes
The commenters generally favored the proposal to add a 20 percent
alternative relative deviation (RD) specification for sources with low
Hg emissions (< = 1.0
[[Page 4336]]
[mu]g/m3). However, concerns were expressed that even a 20
percent RD specification might be difficult to meet when emissions are
exceptionally low. For instance, following a flue gas desulfurization
system, the Hg emission levels can be as low as 0.1 to 0.2 [mu]g/m\3\.
One commenter suggested that the allowable RD for low emitters should
be either 20 percent or 0.03 [mu]g/m\3\ absolute difference, whichever
is less restrictive (see section 2.9.2 of the Response to Comments
document). EPA agrees with this comment and has incorporated the 0.03
[mu]g/m\3\ alternative RD specification into both Appendix K (for
sorbent trap monitoring systems), and Sec. 75.22 (for the Ontario
Hydro Method and EPA Method 29).
The commenters were divided on the proposed single trap adjustment
factor (STAF) provisions. Two commenters supported the proposed
amendments and four others objected to them. Those objecting expressed
concern that applying the proposed STAF value of 1.222 in cases where
one trap meets all of the QA requirements is unnecessarily punitive.
Several of the commenters recommended that the STAF value should be
1.111, which would be consistent with the averaging that is performed
when the results of both traps are available and would appropriately
weight the results of the valid trap (see section 4.3 of the Response
to Comments document for further discussion). After careful
consideration of the comments, EPA has decided to incorporate the
commenters' suggestion regarding the value of the STAF. Therefore, the
single-trap adjustment factor provisions have been finalized as
proposed, except that the value of the STAF is 1.111.
Regarding proposed paragraphs (k) and (l) in Sec. 75.15, EPA has
reconsidered its position and has withdrawn the requirement for the
sorbent traps used for RATA testing to be the same size as the traps
used for daily operation of the monitoring system. Accordingly, the
proposed requirement to perform a diagnostic RATA when the trap size is
changed has also been withdrawn. The Agency is finalized paragraph (k)
as part of a direct-final rulemaking on September 7, 2007 (72 FR 51494-
51531). Paragraph (k) requires only that the type of sorbent material
used for the RATAs be the same as the sorbent material used for daily
operation. Today's rule finalizes paragraph (l) of Sec. 75.15, to
require a diagnostic RATA within 720 operating hours whenever a new
type of sorbent material begins to be used in the traps (e.g., using
brominated carbon instead of iodated carbon). Commenters on proposed
paragraph (l) questioned why data collected by the modified sorbent
trap system are considered invalid prior to the diagnostic RATA. The
commenters requested that EPA revise paragraph (l) to allow data
collected prior to the diagnostic RATA to be reported as valid if the
RATA is passed. The commenters' suggestion is reasonable and has been
incorporated into the final rule. A passed diagnostic RATA demonstrates
that the change in sorbent material has not significantly affected the
monitoring system's ability to accurately measure Hg emissions.
Therefore, Sec. 75.15(l) allows the data from the modified sorbent
trap system to be considered conditionally valid according to Sec.
75.20(b)(3), for up to 720 unit or stack operating hours after
switching to a new type of sorbent material. If the diagnostic RATA is
passed within the 720 operating hour window, the data recorded by the
modified system prior to the RATA may be reported as quality-assured.
If the RATA is failed, no data from the modified system may be reported
as quality-assured until a subsequent RATA is passed. If the diagnostic
RATA is not completed within the allotted 720 operating hour window but
is passed on the first attempt, data from the modified system are
considered to be invalid from the first hour after the expiration of
the 720 operating hour window until the completion of the RATA.
No comments were received on the following proposed amendments: (1)
The proposal to allow the higher Hg concentration to be reported when
the RD criterion for the paired sorbent traps is not met; (2) the
proposed acceptance criteria for the hourly ratios of stack gas flow
rate to sample flow rate; and (3) the proposal to require the sample
flow rate through a sorbent trap monitoring system to be zero when the
affected unit is off-line. Therefore, these provisions have been
finalized, as proposed.
O. Other Rule revisions
1. Particulate Matter Monitoring Systems
Background
EPA received a comment that was outside the scope of the proposed
rule, requesting that units with installed particulate matter (PM)
monitoring systems be exempted from the opacity monitoring requirements
of Sec. 75.14.
Summary of Rule Changes
Although the comment was outside the scope of this rulemaking and
no response is required, EPA believes that it has merit in light of
June 13, 2007 amendments to Subparts Da and Db of 40 CFR Part 60 (see:
72 FR p.32710). For certain affected units (some of which are also
subject to Part 75), these rule revisions either require or allow a
particulate matter (PM) monitoring system to be used in lieu of an
opacity monitor (e.g., see Sec. Sec. 60.49Da(t), and 60.48b(j)).
Summary of Rule Changes
Today's rule incorporates the commenter's recommendation, as new
paragraph (e) in Sec. 75.14. The Agency believes that this revision to
Part 75 is non-controversial and is consistent with EPA's ongoing
commitment to harmonization of the Part 60 and Part 75 continuous
monitoring regulations.
2. Default Moisture Values for Hg Monitoring
Background
For dry-basis Hg CEMS and sorbent trap monitoring systems, the
hourly Hg emissions data must be corrected for the stack gas moisture
content. This requirement can be met by using one of the fuel-specific
default moisture values specified in Part 75. Several places in Sec.
75.80, Sec. 75.81, and Appendix K state that for the purposes of Hg
monitoring, a default moisture value from Sec. 75.11(b) or Sec.
75.12(b) may be used in lieu of installing a continuous moisture
monitoring system. However, the reference to Sec. 75.12(b) is
incorrect. Only the default moisture values in Sec. 75.11(b) are
appropriate for Hg monitoring applications. Equation F-29, the only Hg
mass emissions equation with a moisture correction term, is
structurally similar to Equation F-2 for SO2 mass emissions.
The default moisture values in Sec. 75.11(b) are the ones that apply
to Equation F-2. Hence, they apply also to Equation F-29. The default
moisture values in Sec. 75.12(b) are used for NOX emission
rate calculations, and several of them are not applicable to Hg mass
emissions monitoring.
Summary of Rule Changes
All references to the default moisture values in Sec. 75.12(b)
have been removed from Sec. 75.80, Sec. 75.81, and Appendix K.
3. Hg Stratification Testing
Background
To support the Clean Air Mercury Regulation (CAMR), which was
published in 2005 (see: 70 FR 28606, May 18, 2005), EPA added Hg
monitoring provisions to Part 75, among which were revisions to Sec.
75.22(a) and to section 6.5.10 of Appendix A, specifying ASTM D6784-02,
the ``Ontario Hydro Method'', as the appropriate reference method for
[[Page 4337]]
measuring Hg concentration. On August 22, 2006 EPA proposed to add
Method 29 (which is similar to Ontario Hydro) to Part 75, as an
alternative Hg reference method. Most recently, in a direct-final
action on September 7, 2007. EPA published two more alternative
reference methods (RMs) for measuring vapor phase Hg emissions, Method
30A (an instrumental method) and Method 30B (a sorbent-based method).
Today's rule allows the use of Methods 29, 30A, and 30B as alternatives
to the Ontario Hydro Method (see the revisions to Sec. 75.22(a) and
Section 6.5.10 of Appendix A). EPA anticipates that in 2008 and beyond,
all four of the Hg reference methods in Part 75 will be used, to a
greater or lesser extent, for the Hg emission testing required under
Sec. Sec. 75.81(c) and (d) and for RATAs of Hg monitoring systems.
For Hg emission tests, Methods 30A and 30B require 12 sampling
points (located according to EPA Method 1) for each test run, unless
the results of a Hg stratification test justify using fewer points. The
Ontario Hydro Method and Method 29 each require a minimum of 12 sample
points and do not include any stratification test provisions or
alternative sampling point location criteria.
For the RATAs of Part 75 Hg monitoring systems, when Methods 30A
and 30B are used, both methods defer to the RM point selection and
location procedures described in Part 75, Appendix A, section 6.5.6 and
Performance Specification 2 (PS2) in Appendix B of 40 CFR Part 60. This
is the familiar sampling approach that allows the use of a ``short'' 3-
point measurement line at locations where stratification is not
expected, but requires the use of a 3-point ``long'' measurement line
(which includes a point at the center of the stack) at locations where
stratification is suspected (e.g., after a wet scrubber), unless the
results of a stratification test justify using the 3-point short line
(or perhaps a single sampling point). As an alternative, Part 75 allows
the use of six Method 1 sampling points located along a diameter, at
any test location (including those where stratification is suspected).
This same RM sampling point location methodology applies to Hg RATAs in
which the Ontario Hydro Method or Method 29 is used as the reference
method.
However, when testing is performed downstream of a scrubber,
measuring at the center of a large-diameter stack is extremely
difficult logistically, and testing at 6 points along a diameter may
not be possible for certain test platform and test port configurations.
Therefore, historically, most testers have opted to perform
stratification testing at scrubbed stacks to justify sampling along a
3-point short line (or at a single point), which greatly simplifies the
test procedures, in that all measurements can be made at one test port,
using a probe of reasonable length. Unfortunately, Part 75 does not
have a stratification test procedure for Hg, and, as previously noted,
neither the Ontario Hydro Method nor Method 29 has any stratification
test provisions--but there is a Hg stratification test procedure in
Method 30A.
Summary of Rule Changes
In view of these considerations, EPA has deemed it necessary to
revise Section 6.5.6(c) of Appendix A, to cross-reference the Hg
stratification test provisions in Sections 8.1.3 through 8.1.3.5 of
Method 30A. Further, Sec. 75.22(a)(7) has been revised to address RM
sample point location and stratification testing when the Ontario Hydro
Method or Method 29 is used for the Hg low mass emission testing
required under Sec. Sec. 75.81(c) and (d). For that particular
application, revised Sec. 75.22(a)(7) requires the sampling points to
be located according to Section 8.1 of Method 30A and cross-references
the stratification test provisions in sections 8.1.3 through 8.1.3.5 of
Method 30A.
These amendments to Appendix A and Sec. 75.22 provide a consistent
approach to stratification testing and RM sampling point location for
Hg emission testing and Hg monitoring system RATAs, irrespective of
which Hg reference method is used for the testing.
II. Statutory and Executive Order Reviews
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 final 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 2203.02. The
information collection requirements are not enforceable until OMB
approves them.
The information requirements are based on the 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 preexisting Part 75
rule requirements amended in this final rule are covered by existing
ICRs for the Acid Rain Program (EPA ICR number 1633.14; OMB control
number 2060-0258), the NOX SIP Call (EPA ICR number 1857.04;
OMB number 2060-0445), and the Clean Air Interstate Rule (EPA ICR
number 2152.02; OMB number 2060-0570). The separate ICR for the final
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 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
[[Page 4338]]
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. When this
ICR is approved by OMB, the Agency will publish a technical amendment
to 40 CFR part 9 in the Federal Register to display the OMB control
number for the approved information collection requirements contained
in this final rule.
C. Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions. For purposes
of assessing the impacts of today's rule on small entities, small
entity is defined as: (1) A small business as defined by the SBA's
regulations at 13 CFR 121.201; (2) a small governmental jurisdiction
that is a government of a city, county, town, school district or
special district with a population of less than 50,000; and (3) a small
organization that is any not-for-profit enterprise which is
independently owned and operated and is not dominant in its field.
After considering the economic impacts of today's final 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. These final rule revisions represent minor changes
to existing monitoring requirements used in EPA emission trading
programs and we expect these revisions to reduce the economic burden
for affected entities in the long term.
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 revisions will be 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.
D. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Pub.
L. 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 final 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 to
the private sector in any 1 year, nor does this rule significantly or
uniquely impact small governments, because it contains no requirements
that impose new obligations upon them. Thus, this final 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 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 clarify
certain issues that have been raised during ongoing implementation of
the existing rule and 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
modifications to Part 75, but the rule revisions and the impact on the
States are not 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 final
rule does not have federalism implications. It will not have
substantial direct effects on the States, on the relationship between
the national government and the States, or on the distribution of power
and responsibilities among the various levels of government, as
specified in Executive Order 13132. These rule revisions represent
minor adjustments to existing regulations. The revisions primarily 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 clarify certain issues that have been raised during
ongoing implementation of the existing rule and 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
[[Page 4339]]
associated with reviewing the modifications to Part 75, but the rule
revisions and the impact on the States are not significant. Thus,
Executive Order 13132 does not apply to this final rule.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
Executive Order 13175, entitled ``Consultation and Coordination
With Indian Tribal Governments'' (65 FR 67249, 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 final rule does not have
tribal implications, as specified in Executive Order 13175. It will not
have substantial direct effects on tribal governments, on the
relationship between the Federal government and Indian tribes, or on
the distribution of power and responsibilities between the Federal
government and Indian tribes. Thus, Executive Order 13175 does not
apply to this final rule.
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 determined to be ``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. EPA
interprets Executive Order 13045 as applying only to those regulatory
actions that are based on health or safety risks, such that the
analysis required under section 5-501 of the Order has the potential to
influence the regulation. This rule is not subject to Executive Order
13045 because it does not establish an environmental standard intended
to mitigate health or safety risks.
H. Executive Order 13211: Actions That Significantly Affect Energy
Supply, Distribution, or Use
This rule is not subject to Executive Order 13211, ``Actions
Concerning Regulations That Significantly Affect Energy Supply,
Distribution, or Use'' (66 FR 28355, May 22, 2001) because it is not a
significant regulatory action under Executive Order 12866.
I. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law No. 104-113, section 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
rule includes updated information on a number of voluntary consensus
standards previously included in 40 CFR Part 75, as well as the
addition of certain other voluntary consensus standards.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629 (Feb. 16, 1994)) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States. EPA has determined that this final
rule will not have disproportionately high and adverse human health or
environmental effects on minority or low-income populations because it
does not affect the level of protection provided to human health or the
environment. This final rule does not affect or relax the control
measures on sources impacted by emission trading programs that rely on
monitoring under 40 CFR Part 75.
K. Congressional Review Act
The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the Agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
United States. EPA will submit a report containing this rule and other
required information to the U.S. Senate, the U.S. House of
Representatives, and the Comptroller General of the United States prior
to publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is not a ``major rule'' as defined by 5 U.S.C.
804(2). This rule will be effective on January 24, 2008 for good cause
found as explained in this rule.
L. Petitions for Judicial Review
Under Clean Air Act section 307(b)(1), petitions for judicial
review of this action must be filed in the United States Court of
Appeals for the appropriate circuit by March 24, 2008. Filing a
petition for reconsideration by the Administrator of this final rule
does not affect the finality of this rule for the purposes of judicial
review, nor does it extend the time within which a petition for
judicial review may be filed, and shall not postpone the effectiveness
of such a rule or action. This action may not be challenged later in
proceedings to enforce its requirements. (See section 307(b)(2) of the
Administrative Procedures Act.)
M. Determination Under Section 307(d)
Pursuant to Clean Air Act section 307(d)(1)(U), the Administrator
determines that this action is subject to the provisions of section
307(d). Section 307(d)(1)(U) provides that the provisions of section
307(d) apply to ``such other actions as the Administrator may
determine.'' While the Administrator did not make this determination
earlier, the Administrator believes that all of the procedural
requirements, e.g., docketing, hearing and comment periods, of section
307(d) have been complied with during the course of this rulemaking.
List of Subjects in 40 CFR Parts 72 and 75
Environmental protection, Acid rain, Administrative practice and
procedure, Air pollution control, Carbon dioxide, Continuous emission
monitoring, Electric utilities, Incorporation by reference, Nitrogen
oxides, Reporting and recordkeeping requirements, Sulfur oxides.
[[Page 4340]]
Dated: December 19, 2007.
Stephen L. Johnson,
Administrator.
0
For the reasons set forth in the preamble, parts 72 and 75 of chapter I
of title 40 of the Code of Federal Regulations are amended as follows:
PART 72--PERMITS REGULATION
0
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
0
2. Section 72.2 is amended as follows:
0
a. Revising the definition of ``Capacity factor'';
0
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'';
0
c. In the definition of ``EPA protocol gas'', by adding a new sentence
to the end of the definition;
0
d. Revising the definition of ``Excepted monitoring system'';
0
e. Adding the new definitions in alphabetical order for ``Air Emission
Testing Body (AETB)'', ``EPA Protocol Gas Verification Program'',
``Long-term cold storage'', ``NIST traceable elemental Hg standards'',
``NIST traceable source of oxidized Hg'', ``Qualified Individual'', and
``Specialty gas producer''; and
0
f. Removing the definition for ``Research gas material (RGM)''
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
(incorporated by reference under Sec. 75.6 of this part).
* * * * *
Capacity factor means either:
(1) The ratio of a unit's actual annual electric output (expressed
in MWe/hr) to the unit's nameplate capacity (or maximum observed hourly
gross load (in MWe/hr) if greater than the nameplate capacity) times
8760 hours; or
(2) The ratio of a unit's annual heat input (in million British
thermal units or equivalent units of measure) to the unit's maximum
rated hourly heat input rate (in million British thermal units per hour
or equivalent units of measure) times 8,760 hours.
* * * * *
EPA protocol gas * * * On and after January 1, 2009, vendors
advertising certification with the EPA 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 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).
* * * * *
NIST traceable elemental Hg standards means either:
(1) Compressed gas cylinders having known concentrations of
elemental Hg, which have been prepared according to the ``EPA
Traceability Protocol for Assay and Certification of Gaseous
Calibration Standards''; or
(2) Calibration gases having known concentrations of elemental Hg,
produced by a generator that fully meets the performance requirements
of the ``EPA Traceability Protocol for Qualification and Certification
of Elemental Mercury Gas Generators''.
* * * * *
NIST traceable source of oxidized Hg means a generator that: Is
capable of providing known concentrations of vapor phase mercuric
chloride (HgCl2), and that fully meets the performance
requirements of the ``EPA Traceability Protocol for Qualification and
Certification of Oxidized Mercury Gas Generators''.
* * * * *
Qualified Individual means an individual who meets the requirements
as described in ASTM D7036-04, ``Standard Practice for Competence of
Air Emission Testing Bodies'' (incorporated by reference under Sec.
75.6 of this part).
* * * * *
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
0
3. The authority citation for Part 75 continues to read as follows:
Authority: 42 U.S.C. 7601, and 7651k, and 7651k note.
Subpart A--General
0
4. Section 75.4 is amended by revising paragraph (d) to read as
follows:
Sec. 75.4 Compliance dates.
* * * * *
(d) This paragraph, 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
shut down 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:
[[Page 4341]]
(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.
* * * * *
0
5. Section 75.6 is amended by:
0
a. Removing ``D129-91'' and adding in its place ``D129-00'', in
paragraph (a)(1);
0
b. Removing ``D240-87 (Reapproved 1991)'' and adding in its place
``D240-00'', in paragraph (a)(2);
0
c. Removing ``D287-82 (Reapproved 1987)'' and adding in its place
``D287-92 (Reapproved 2000)'', in paragraph (a)(3);
0
d. Removing ``D388-92'' and adding in its place ``D388-99'', in
paragraph (a)(4);
0
e. Removing and reserving paragraph (a)(5);
0
f. Removing ``D1072-90'' and adding in its place ``D1072-06'', and also
by adding the phrase ``by Combustion and Barium Chloride Titration''
after the word ``Gases'', in paragraph (a)(6);
0
g. Removing ``D1217-91'' and adding in its place ``D1217-93 (Reapproved
1998)'', in paragraph (a)(7);
0
h. Removing the phrase ``(Reapproved 1990)'', and by removing ``D1250-
80'' and adding in its place ``D1250-07'', and also by adding the
phrase ``Use of the'' after the first occurrence of the word ``for'',
in paragraph (a)(8);
0
i. Removing the phrase ``D1298-85 (Reapproved 1990), Standard Practice
for Density, Relative Density (Specific Gravity)'' and adding in its
place ``D1298-99, Standard Test Method for Density, Relative Density
(Specific Gravity),'', in paragraph (a)(9);
0
j. Removing ``D1480-91'' and adding in its place ``D1480-93 (Reapproved
1997)'', in paragraph (a)(10);
0
k. Removing ``D1481-91'' and adding in its place ``D1481-93 (Reapproved
1997)'', in paragraph (a)(11);
0
l. Removing ``D1552-90'' and adding in its place ``D1552-01'', and also
by removing the phrase, ``High Temperature'' and adding in its place
``High-Temperature'', in paragraph (a)(12);
0
m. Removing ``D1826-88'' and adding in its place ``D1826-94 (Reapproved
1998)'', in paragraph (a)(13);
0
n. Removing ``D1945-91'' and adding in its place ``D1945-96 (Reapproved
2001)'', in paragraph (a)(14);
0
o. Adding the phrase ``(Reapproved 2006)'' after ``D1946-90'', in
paragraph (a)(15);
0
p. Removing and reserving paragraph (a)(16);
0
q. Removing ``D2013-86'' and adding in its place ``D2013-01'', and also
by removing the phrase, ``Method of'', and adding in its place,
``Practice for'', in paragraph (a)(17);
0
r. Removing and reserving paragraph (a)(18);
0
s. Removing ``D2234-89'' and adding in its place ``D2234-00'', and also
by removing the phrase ``Test Methods'', and adding in its place,
``Practice'', in paragraph (a)(19);
0
t. Removing and reserving paragraph (a)(20);
0
u. Removing ``D2502-87'' and adding in its place ``D2502-92 (Reapproved
1996)'', in paragraph (a)(21);
0
v. Removing ``D2503-82 (Reapproved 1987)'' and adding in its place
``D2503-92 (Reapproved 1997)'', and also by removing the phrase
``Molecular Weight (Relative Molecular Mass)'', and by adding in its
place, ``Relative Molecular Mass (Molecular Weight)'', in paragraph
(a)(22);
0
w. Removing ``D2622-92'' and adding in its place ``D2622-98'', and also
by removing the phrase ``X-Ray Spectrometry'', and adding in its place
``Wavelength Dispersive X-ray Fluorescence Spectrometry'', in paragraph
(a)(23);
0
x. Removing ``D3174-89'' and adding in its place ``D3174-00'', and also
by removing the word ``From'' and adding in its place ``from'', in
paragraph (a)(24);
0
y. Adding the phrase ``(Reapproved 2002)'' after ``D3176-89'', in
paragraph (a)(25);
0
z. Removing ``D3177-89'' and adding in its place the phrase `` D3177-02
(Reapproved 2007)'' in paragraph (a)(26);
0
aa. Removing `` D3178-89 (1997), ``Standard Test Methods for Carbon and
Hydrogen in the Analysis Sample of Coal and Coke'' and adding in its
place ``D5373-02 (Reapproved 2007) Standard Test Methods for
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
Laboratory Samples of Coal and Coke'' in paragraph (a)(27);
0
bb. Removing ``D3238-90'' and adding in its place ``D3238-95
(Reapproved 2000)'', in paragraph (a)(28);
0
cc. Removing ``D3246-81 (Reapproved 1987)'' and adding in its place
``D3246-96'', and also by removing the word ``By'' and adding in its
place, ``by'', in paragraph (a)(29);
0
dd. Removing and reserving paragraph (a)(30);
0
ee. Removing ``D3588-91'' and adding in its place ``D3588-98'', and
also by removing the phrase, ``(Specific Gravity)'', in paragraph
(a)(31);
0
ff. Removing ``D4052-91'' and adding in its place ``D4052-96
(Reapproved 2002)'', in paragraph (a)(32);
0
gg. Removing ``D4057-88'' and adding in its place ``D4057-95
(Reapproved 2000)'', in paragraph (a)(33);
0
hh. Removing ``D4177-82 (Reapproved 1990)'' and adding in its place
``D4177-95 (Reapproved 2000)'', in paragraph (a)(34);
0
ii. Removing ``D4239-85'' and adding in its place ``D4239-02'', and
also by removing the phrase ``High Temperature'', and adding in its
place ``High-Temperature'', in paragraph (a)(35);
0
jj. Removing ``D4294-90'' and adding in its place ``D4294-98'', adding
the words ``and Petroleum'' after the word ``Petroleum'', by removing
the word ``X-Ray'' and adding in its place, ``X-ray'', and by removing
the word ``Spectroscopy'' and adding in its place, ``Spectrometry'' in
paragraph (a)(36);
0
kk. Removing the phrase ``(Reapproved 1989)'' and adding in its place
the phrase ``(Reapproved 2006)'', in paragraph (a)(37);
0
ll. Removing ``(reapproved 2004)'', and adding in its place,
``(Reapproved 2004)'', in paragraph (a)(38);
0
mm. Adding the phrase ``(Reapproved 2006)'' after ``D4891-89'', in
paragraph (a)(39);
0
nn. Removing ``D5291-92'' and adding in its place ``D5291-02'', in
paragraph (a)(40);
0
oo. Removing ``D5373-93'', and adding in its place ``D5373-02
(Reapproved 2007)'' and adding the word ``Test'' after the word
``Standard'', in paragraph (a)(41);
0
pp. Removing ``D5504-94'' and adding in its place ``D5504-01'', in
paragraph (a)(42);
0
qq. Adding new paragraphs (a)(45), (a)(46), (a)(47), (a)(48), and
(a)(49);
0
rr. Removing the phrase ``ASME MFC-3M-1989 with September 1990 Errata''
and adding in its place the phrase ``ASME MFC-3M-2004 (Revision of ASME
MFC-3M-1989 (R1995))'', in paragraph (b)(1);
0
ss. Removing the date ``1990'' and adding in its place the date
``1997'' in the parenthetical, in paragraph (b)(2);
0
tt. Adding the phrase ``(Reaffirmed 1994)'' after ``ASME-MFC-5M-
1985,'', in paragraph (b)(3);
0
uu. Removing the phrase ``1987 with June 1987 Errata'' and adding in
its
[[Page 4342]]
place the number ``1998'' at the end of ``MFC-6M-'', and also by
removing ``Flow Meters'' and adding in its place, ``Flowmeters'', in
paragraph (b)(4);
0
vv. Removing the phrase ``with December 1989 Errata'' and adding in its
place the phrase ``(Reaffirmed 2001)'', in paragraph (b)(6);
0
ww. Removing the number ``86'' and adding in its place the number
``96'' at the end of ``GPA Standard 2172-'', in paragraph (d)(1);
0
xx. Removing the number ``90'' and adding in its place the number
``00'' at the end of ``GPA Standard 2261-00'', in paragraph (d)(2);
0
yy. Revising paragraphs (f)(1) and (f)(3); and
0
zz. 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 Liquefied 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 D5865-01a, 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.
(49) ASTM D5453-06, Standard Test Method for Determination of Total
Sulfur in Light Hydrocarbons, Spark Ignition Engine Fuel, Diesel Engine
Fuel, and Engine Oil by Ultraviolet Fluorescence, for appendix D of
this part.
* * * * *
(f) * * *
(1) American Petroleum Institute (API) Manual of Petroleum
Measurement Standards, Chapter 3--Tank Gauging, Section 1A, Standard
Practice for the Manual Gauging of Petroleum and Petroleum Products,
Second Edition, August 2005; Section 1B--Standard Practice for Level
Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic
Tank Gauging, Second Edition June 2001; Section 2--Standard Practice
for Gauging Petroleum and Petroleum Products in Tank Cars, First
Edition, August 1995 (Reaffirmed March 2006); Section 3--Standard
Practice for Level Measurement of Liquid Hydrocarbons in Stationary
Pressurized Storage Tanks by Automatic Tank Gauging, First Edition June
1996; Section 4--Standard Practice for Level Measurement of Liquid
Hydrocarbons on Marine Vessels by Automatic Tank Gauging, First Edition
April 1995 (Reaffirmed, March 2006); and Section 5--Standard Practice
for Level Measurement of Light Hydrocarbon Liquids Onboard Marine
Vessels by Automatic Tank Gauging, First Edition March 1997
(Reaffirmed, March 2003); for Sec. 75.19.
* * * * *
(3) American Petroleum Institute (API) Manual of Petroleum
Measurement Standards, Chapter 4--Proving Systems, Section 2--Pipe
Provers (Provers Accumulating at Least 10,000 Pulses), Second Edition,
March 2001, and Section 5--Master-Meter Provers, Second Edition, May
2000, for appendix D to this part.
(4) American Petroleum Institute (API) Manual of Petroleum
Measurement Standards, Chapter 22--Testing Protocol, Section 2--
Differential Pressure Flow Measurement Devices (First Edition, August
2005), for appendix D to this part.
0
6. Section 75.11 is amended by:
0
a. Revising the heading of the section;
0
b. Adding the phrase ``and 14.0% for natural gas (boilers, only);''
after the word ``wood;'', in paragraph (b)(1);
0
c. Revising paragraph (d)(3);
0
d. Revising paragraphs (e) introductory text and (e)(1);
0
e. Removing and reserving paragraph (e)(2);
0
f. Revising paragraph (e)(3) introductory text;
0
g. Add new paragraph (e)(4); and
0
h. 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 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.
0
7. Section 75.12 is amended by:
0
a. Revising the section heading;
0
b. Removing the word ``and'' before the number ``15.0%'', and by adding
the phrase ``; and 18.0% for natural gas
[[Page 4343]]
(boilers, only)'' after the word ``wood'', in paragraph (b); and
0
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).
* * * * *
0
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).
0
9. Section 75.14 is amended by adding paragraph (e) to read as follows:
Sec. 75.14 Specific provisions for monitoring opacity.
* * * * *
(e) Unit with a certified particulate matter (PM) monitoring
system. If, for a particular affected unit, the owner or operator
installs, certifies, operates, maintains, and quality-assures a
continuous particulate matter (PM) monitoring system in accordance with
Procedure 2 in appendix F to part 60 of this chapter, the unit shall be
exempt from the opacity monitoring requirement of this part.
0
10. Section 75.15 is amended by:
0
a. Removing the reference ``(j)'' and adding the reference ``(l)'' in
its place in the introductory paragraph;
0
b. Revising paragraph (h); and
0
c. Adding paragraph (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 ( 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 1.111.
* * * * *
(l) Whenever the type of sorbent material used by the traps is
changed, the owner or operator shall conduct a diagnostic RATA of the
modified sorbent trap monitoring system within 720 unit or stack
operating hours after the date and hour when the new sorbent material
is first used. If the diagnostic RATA is passed, data from the modified
system may be reported as quality-assured, back to the date and hour
when the new sorbent material was first used. If the RATA is failed,
all data from the modified system shall be invalidated, back to the
date and hour when the new sorbent material was first used, and data
from the system shall remain invalid until a subsequent RATA is passed.
If the required RATA is not completed within 720 unit or stack
operating hours, but is passed on the first attempt, data from the
modified system shall be invalidated beginning with the first operating
hour after the 720 unit or stack operating hour window expires and data
from the system shall remain invalid until the date and hour of
completion of the successful RATA.
0
11. Section 75.16 is amended by:
0
a. Revising paragraph (b)(1)(ii);
0
b. Adding the word ``rate'' after the phrase ``report heat input'' in
the last sentence, in paragraph (e)(1); and
0
c. In the second sentence of paragraphs (e)(3) by removing both
occurrences of the phrase ``steam flow'' and adding in its place 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.
* * * * *
0
12. 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 add-on NOX
emission controls are not bypassed, 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 where the words ``maximum
potential NOX emission rate (MER)'' shall apply instead of
the words ``maximum
[[Page 4344]]
controlled NOX emission rate (MCR)'' and by using the
NOX MEC in the calculations instead of the NOX
MPC.
0
13. Section 75.19 is amended by:
0
a. Revising paragraph (a)(1);
0
b. Revising paragraph (c)(1)(i);
0
c. Revising paragraph (c)(1)(iv)(A)(3);
0
d. Removing the words ``Method 20'' from paragraph (c)(1)(iv)(A)(4);
0
e. Removing the words ``Method 20'' from the definition of
NOX obs in the nomenclature for Equation LM-1a under
paragraph (c)(1)(iv)(A);
0
f. 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);
0
g. Adding paragraphs (c)(1)(iv)(I)(3), (4), (5) and (6);
0
h. Revising paragraph (c)(3)(ii)(B)(2);
0
i. Revising paragraph (c)(3)(ii)(H);
0
j. Removing the words ``from Table LM-1 of this section'' from the
first sentence of paragraph (c)(4)(i)(A);
0
k. Revising the heading for paragraph (c)(4)(ii); and
0
l. 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. Alternatively, the
required oil sampling and associated recordkeeping may be performed
using a consensus standard (e.g., ASTM, API, etc.) that is prescribed
in the unit's Federally-enforceable operating permit, in an applicable
State regulation, or in another applicable Federal regulation. 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.
* * * * *
(iv) * * *
(A) * * *
(3) Do not correct the NOX concentration to 15%
O2.
* * * * *
(I) * * *
(3) The initial appendix E testing may be performed at a single
load, between 75 and 100 percent of the maximum sustainable load
defined in the monitoring plan for the unit, if the average annual
capacity factor of the LME unit, when calculated according to the
definition of ``capacity factor'' in Sec. 72.2 of this chapter, is 2.5
percent or less for the three calendar years immediately preceding the
year of the testing, and that the annual capacity factor does not
exceed 4.0 percent in any of those three years. Similarly, for a LME
unit that reports emissions data on an ozone season-only basis, the
initial appendix E testing may be performed at a single load between 75
and 100 percent of the maximum sustainable load if the 2.5 and 4.0
percent capacity factor requirements are met for the three ozone
seasons immediately preceding the date of the emission testing (see
Sec. 75.74(c)(11)). For a group of identical LME units, any unit(s) in
the group that meet the 2.5 and 4.0 percent capacity factor
requirements may perform the initial appendix E testing at a single
load between 75 and 100 percent of the maximum sustainable load.
(4) The retest of any LME unit may be performed at a single load
between 75 and 100 percent of the maximum sustainable load if, for the
three calendar years immediately preceding the year of the retest (or,
if applicable, the three ozone seasons immediately preceding the date
of the retest), the applicable capacity factor requirements described
in paragraph (c)(1)(iv)(I)(3) of this section are met.
(5) Alternatively, for combustion turbines, the single-load testing
described in paragraphs (c)(1)(iv)(I)(3) and (c)(1)(iv)(I)(4) of this
section may be performed at the highest attainable load level
corresponding to the season of the year in which the testing is
conducted.
(6) In all cases where the alternative single-load testing option
described in paragraphs (c)(1)(iv)(I)(3) through (c)(1)(iv)(I)(5) of
this section is used, the owner or operator shall keep records
documenting that the required capacity factor requirements were met.
* * * * *
(3) * * *
(ii) * * *
(B) * * *
(2) American Petroleum Institute (API) Manual of Petroleum
Measurement Standards, Chapter 3-Tank Gauging, Section 1A, Standard
Practice for the Manual Gauging of Petroleum and Petroleum Products,
Second Edition, August 2005; Section 1B-Standard Practice for Level
Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic
Tank Gauging, Second Edition June 2001; Section 2-Standard Practice for
Gauging Petroleum and Petroleum Products in Tank Cars, First Edition,
August 1995 (Reaffirmed March 2006); Section 3-Standard Practice for
Level Measurement of Liquid Hydrocarbons in Stationary Pressurized
Storage Tanks by Automatic Tank Gauging, First Edition June 1996
(Reaffirmed, March 2001); Section 4-Standard Practice for Level
Measurement of Liquid Hydrocarbons on Marine Vessels by Automatic Tank
Gauging, First Edition April 1995 (Reaffirmed, September 2000); and
Section 5-Standard Practice for Level Measurement of Light Hydrocarbon
Liquids Onboard Marine Vessels by Automatic Tank Gauging, First Edition
March 1997 (Reaffirmed, March 2003); for Sec. 75.19; Shop Testing of
Automatic Liquid Level Gages, Bulletin 2509 B, December 1961
(Reaffirmed August 1987, October 1992) (all incorporated by reference
under Sec. 75.6 of this part); or
* * * * *
(H) For each low mass emissions unit or each low mass emissions
unit in a
[[Page 4345]]
group of identical units, the owner or operator shall determine the
cumulative quarterly unit load in megawatt hours or thousands of pounds
of steam. The quarterly cumulative unit load shall be the sum of the
hourly unit load values recorded under paragraph (c)(2) of this section
and shall be determined using Equations LM-5 or LM-6. For a unit
subject to the provisions of subpart H of this part, which is not
required to report emission data on a year-round basis and elects to
report only during the ozone season, the quarterly cumulative load for
the second calendar quarter of the year shall include only the unit
loads for the months of May and June.
[GRAPHIC] [TIFF OMITTED] TR24JA08.016
[GRAPHIC] [TIFF OMITTED] TR24JA08.017
Where:
MWqtr = Sum of all unit operating loads recorded during
the quarter by the unit (MWh).
STfuel-qtr = Sum of all hourly steam loads recorded
during the quarter by the unit (klb of steam/hr).
MW = Unit operating load for a particular unit operating hour (MWh).
ST = Unit steam load for a particular unit operating hour (klb of
steam).
* * * * *
(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.
* * * * *
0
14. Section 75.20 is amended by:
0
a. Adding a new sentence after the third sentence of paragraph (b)
introductory text;
0
b. Revising paragraph (c)(1)(v); and
0
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
* * * * *
Sec. 75.21 [Amended]
0
15. Section 75.21 is amended by removing the words ``or (e)(2)'' at the
end of the first sentence of paragraph (a)(4).
0
16. Section 75.22 is amended by:
0
a. Revising paragraph (a) introductory text;
0
b. Revising paragraphs (a)(5), (a)(6), and (a)(7);
0
c. Revising paragraph (b) introductory text;
0
d. Removing the word ``and'' at the end of paragraph (b)(3);
0
e. Revising paragraph (b)(5);
0
f. Adding paragraphs (b)(6), (b)(7), and (b)(8); and
0
g. Revising paragraph (c)(1) introductory text.
The revisions and additions read as follows:
Sec. 75.22 Reference test methods.
(a) The owner or operator shall use the following methods, which
are found in appendix A-4 to part 60 of this chapter or have been
published by ASTM, to conduct the following tests: monitoring system
tests for certification or recertification of continuous emission
monitoring systems and excepted monitoring systems under appendix E to
this part; the emission tests required under Sec. 75.81(c) and (d);
and required quality assurance and quality control tests:
* * * * *
(5) Methods 6, 6A, 6B or 6C, and 7, 7A, 7C, 7D or 7E in appendix A-
4 to part 60 of this chapter, as applicable, are the reference methods
for determining SO2 and NOX pollutant
concentrations. (Methods 6A and 6B in appendix A-4 to part 60 of this
chapter may also be used to determine SO2 emission rate in
lb/mmBtu.) Methods 7, 7A, 7C, 7D, or 7E in appendix A-4 to part 60 of
this chapter 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 sections, exceptions, and options
of method 7E in appendix A-4 to part 60 of this chapter:
(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) The sampling point selection procedures in section 8.1 of the
method, for the emission testing of boilers and combustion turbines
under appendix E to this part. The number and location of the sampling
points for those applications shall be as specified in sections 2.1.2.1
and 2.1.2.2 of appendix E to this part;
(iii) 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;
(iv) 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.
(6) Method 3A in appendix A-2 and method 7E in appendix A-4 to part
60 of this chapter are the reference methods for determining
NOX and diluent emissions from stationary gas turbines for
testing under appendix E to this part.
(7) ASTM D6784-02, Standard Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired
Stationary Sources (Ontario Hydro Method) (incorporated by reference
under Sec. 75.6 of this part) is the reference method for determining
Hg concentration.
(i) 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
[[Page 4346]]
standards and sample analysis in sections 13.4.1.1 through 13.4.1.3
ASTM D6784-02 (incorporated by reference under Sec. 75.6 of this part)
shall be followed instead of the procedures in sections 7.5.33 and
11.1.3 of Method 29 in appendix A-8 to part 60 of this chapter, and the
QA/QC procedures in section 13.4.2 of ASTM D6784-02 (incorporated by
reference under Sec. 75.6 of this part) shall be performed instead of
the procedures in section 9.2.3 of Method 29 in appendix A-8 to part 60
of this chapter. The tester may also opt to use the sample recovery and
preparation procedures in ASTM D6784-02 (incorporated by reference
under Sec. 75.6 of this part) instead of the Method 29 in appendix A-8
to part 60 of this chapter procedures, as follows: sections 8.2.8 and
8.2.9.1 of Method 29 in appendix A-8 to part 60 of this chapter may be
replaced with sections 13.2.9.1 through 13.2.9.3 of ASTM D6784-02
(incorporated by reference under Sec. 75.6 of this part); sections
8.2.9.2 and 8.2.9.3 of Method 29 in appendix A-8 to part 60 of this
chapter may be replaced with sections 13.2.10.1 through 13.2.10.4 of
ASTM D6784-02 (incorporated by reference under Sec. 75.6 of this
part); section 8.3.4 of Method 29 in appendix A-8 to part 60 of this
chapter may be replaced with section 13.3.4 or 13.3.6 of ASTM D6784-02
(as appropriate) (incorporated by reference under Sec. 75.6 of this
part); and section 8.3.5 of Method 29 in appendix A-8 to part 60 of
this chapter may be replaced with section 13.3.5 or 13.3.6 of ASTM
D6784-02 (as appropriate) (incorporated by reference under Sec. 75.6
of this part).
(ii) Whenever ASTM D6784-02 (incorporated by reference under Sec.
75.6 of this part) or Method 29 in appendix A-8 to part 60 of this
chapter is used, paired sampling trains are required. To validate a
RATA run or an emission test 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. The RD results are also acceptable if
the absolute difference between the Hg concentrations measured by the
paired trains does not exceed 0.03 [mu]g/m\3\. If the RD criterion is
met, the run is valid. For each valid run, average the Hg
concentrations measured by the two trains (vapor phase, only).
(iii) Two additional reference methods that may be used to measure
Hg concentration are: Method 30A, ``Determination of Total Vapor Phase
Mercury Emissions from Stationary Sources (Instrumental Analyzer
Procedure)'' and Method 30B, ``Determination of Total Vapor Phase
Mercury Emissions from Coal-Fired Combustion Sources Using Carbon
Sorbent Traps''.
(iv) When Method 29 in appendix A-8 to part 60 of this chapter or
ASTM D6784-02 (incorporated by reference under Sec. 75.6 of this part)
is used for the Hg emission testing required under Sec. Sec. 75.81(c)
and (d), locate the reference method test points according to section
8.1 of Method 30A, and if Hg stratification testing is part of the test
protocol, follow the procedures in sections 8.1.3 through 8.1.3.5 of
Method 30A.
(b) The owner or operator may use any of the following methods,
which are found in appendix A to part 60 of this chapter or have been
published by ASTM, as a reference method backup monitoring system to
provide quality-assured monitor data:
* * * * *
(5) ASTM D6784-02, Standard Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired
Stationary Sources (Ontario Hydro Method) (incorporated by reference
under Sec. 75.6 of this part) for determining Hg concentration;
(6) Method 29 in appendix A-8 to part 60 of this chapter for
determining Hg concentration;
(7) Method 30A for determining Hg concentration; and
(8) Method 30B for determining Hg concentration.
(c)(1) Instrumental EPA Reference Methods 3A, 6C, and 7E in
appendices A-2 and A-4 of part 60 of this chapter shall be conducted
using calibration gases as defined in section 5 of appendix A to this
part. Otherwise, performance tests shall be conducted and data reduced
in accordance with the test methods and procedures of this part unless
the Administrator:
* * * * *
0
17. Section 75.31 is amended by adding a sentence to the end of
paragraph (c)(3) to read as follows:
Sec. 75.31 Initial missing data procedures.
* * * * *
(c) * * *
(3) * * * Alternatively, where a unit with add-on NOX
emission controls can demonstrate that the controls are operating
properly during the hour, as provided in Sec. 75.34(d), the owner or
operator may substitute, as applicable, the maximum controlled
NOX emission rate (MCR) or the maximum expected
NOX concentration (MEC).
* * * * *
0
18. Section 75.32 is amended by revising paragraph (b) to read as
follows:
Sec. 75.32 Determination of monitor data availability for standard
missing data procedures.
* * * * *
(b) The monitor data availability shall be calculated for each hour
during each missing data period. The owner or operator shall record the
percent monitor data availability for each hour of each missing data
period to implement the missing data substitution procedures.
* * * * *
0
19. Section 75.33 is amended by:
0
a. Revising the section heading;
0
b. Removing the word ``Whenever'' and adding in its place the word
``If'', and by removing the words ``each hour of each'' and adding in
its place the words ``that hour of the'', in paragraph (b)(1)
introductory text;
0
c. Removing the word ``Whenever'' and adding in its place the word
``If'', and by removing the words ``each hour of each'' and adding in
its place the words ``that hour of the'', in paragraph (b)(2)
introductory text;
0
d. Removing the word ``Whenever'' and adding in its place the word
``If'', and by removing the word ``each'' and adding in its place the
words ``that hour of the'', in paragraphs (b)(3) and (b)(4);
0
e. Removing the word ``Whenever'' and adding in its place the word
``If'', and by removing the words ``each hour of each'' and adding in
its place the words ``that hour of the'', in paragraphs (c)(1)
introductory text, (c)(2) introductory text, (c)(3), and (c)(4);
0
f. Revising paragraph (c)(8)(iii);
0
g. Revising Tables 1 and 2 in paragraph (c)(8)(iv);
0
h. Removing the word ``Whenever'' and adding in its place the word
``If'', and by removing the words ``each hour of each'' and adding in
its place the words ``that hour of the'', in paragraphs (d)(1)
introductory text, (d)(2) introductory text, (d)(3) introductory text,
and (d)(4) introductory text.
0
i. Revising Table 3 in paragraph (e)(3); and
The revisions and additions read as follows:
Sec. 75.33 Standard missing data procedures for SO2,
NOX, Hg, and flow rate.
* * * * *
(c) * * *
(8) * * *
(iii) For the purposes of providing substitute data under paragraph
(c)(4) of this section, a separate, fuel-specific maximum potential
concentration (MPC), maximum potential NOX emission rate
(MER), or maximum
[[Page 4347]]
potential flow rate (MPF) value (as applicable) shall be determined for
each type of fuel combusted in the unit, in a manner consistent with
Sec. 72.2 of this chapter and with section 2.1.2.1 or 2.1.4.1 of
appendix A to this part. For co-firing, the MPC, MER or MPF value shall
be based on the fuel with the highest emission rate or flow rate (as
applicable). Furthermore, for a unit with add-on NOX
emission controls, a separate fuel-specific maximum controlled
NOX emission rate (MCR) or maximum expected NOX
concentration (MEC) value (as applicable) shall be determined for each
type of fuel combusted in the unit. The exact methodology used to
determine each fuel-specific MPC, MER, MEC, MCR or MPF value shall be
documented in the monitoring plan for the unit or stack.
(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 H2O\X\, 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 H2O\X\, 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 H2O:
< 80 for Hg). **
Maximum value \1\...... 720 hours.*
For O2 and H2O\X\:
Minimum value \1\...... 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 H2O\X\).
----------------------------------------------------------------------------------------------------------------
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 during the missing data period, as provided in Sec. 75.34, the unit may use the maximum controlled
concentration from the previous 720 quality-assured monitor operating hours.
\2\ During unit operating hours.
\3\ Alternatively, where a unit with add-on SO2 or Hg emission controls can demonstrate that the controls are
operating properly during the missing data period, 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-7 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-7 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 Method Lookback period Load ranges
(percent) (hours) \2\
----------------------------------------------------------------------------------------------------------------
95 or more..................... N < = 24.......... Average.......... 2,160 hours *.... Yes.
N > 24........... The greater of:
Average....... HB/HA............ No.
90th 2,160 hours *.... Yes.
percentile.
90 or more, but below 95....... N < = 8........... Average.......... 2,160 hours *.... Yes.
N > 8............ The greater of:
Average....... HB/HA............ No.
95th 2,160 hours *.... Yes.
percentile.
80 or more, but below 90....... N > 0............ Maximum value \1\ 2,160 hours *.... Yes.
[[Page 4348]]
Below 80....................... N > 0............ Maximum potential None............. No.
NOX emission
rate \3\; or
maximum
potential NOX
concentration
\3\; 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
during the missing data period, as provided in Sec. 75.34, the unit may use the maximum controlled NOX
concentration or emission rate from the previous 2,160 quality-assured monitor operating hours. 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 data pools 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 during the missing data period, 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
2,160 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
----------------------------------------------------------------------------------------------------------------
Monitor data availability Duration (N) of CEMS
(percent) outage (hours) \1\ Method Lookback period
----------------------------------------------------------------------------------------------------------------
95 or more........................ N < = 24.............. Average................... 2,160 hours.*
N > 24............... 90th percentile........... 2,160 hours.*
90 or more, but below 95.......... N < = 8............... Average................... 2,160 hours.*
N > 8................ 95th percentile........... 2,160 hours.*
80 or more, but below 90.......... N > 0................ Maximum value \3\......... 2,160 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 2,160 quality-assured
monitor operating hours.
\3\ Where a unit with add-on NOX emission controls can demonstrate that the controls are operating properly
during the missing data period, as provided in Sec. 75.34, the unit may use the maximum controlled NOX
concentration or emission rate from the previous 2,160 quality-assured monitor operating hours. 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 data pools to provide substitute data values, as described in Sec.
75.34(a)(2).
* * * * *
0
20. Section 75.34 is amended by:
0
a. Revising paragraph (a) introductory text;
0
b. In paragraph (a)(2)(ii) by removing the words ``and (c)(3)'' and
adding in its place the words ``, (c)(3) and (c)(5) of this section,
and Sec. 75.38(c),''
0
c. Revising paragraph (a)(3);
0
d. Adding paragraph (a)(5); and
0
e. In paragraph (d) by removing the words ``paragraphs (a)(1) and
(a)(3) of this section,'' and adding in its place the words
``paragraphs (a)(1), (a)(3) and (a)(5) of this section; and Sec. Sec.
75.31(c)(3), 75.38(c), and 75.72(c)(3),''.
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/
[[Page 4349]]
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 controlled hourly 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.
* * * * *
0
20. 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 ( 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.
0
21. Section 75.39 is amended by:
0
a. Revising paragraph (a);
0
b. Revising paragraph (b);
0
c. Revising paragraph (c);
0
d. Revising paragraph (d); and
0
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., 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.
* * * * *
[[Page 4350]]
(f) In cases where the owner or operator elects to use a primary Hg
CEMS and a certified redundant (or non-redundant) backup sorbent trap
monitoring system (or vice-versa), when both the primary and backup
monitoring systems are out-of-service and quality-assured Hg
concentration data from a temporary like-kind replacement analyzer,
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
temporary like-kind replacement analyzer, a reference method, or an
approved alternative monitoring system.
0
22. Section 75.53 is amended by:
0
a. Revising paragraph (a)(1);
0
b. Removing the phrase ``(d) or (f)'' and adding in its place the
phrase ``(f) or (h)'' in the second sentence of paragraph (a)(2);
0
c. Adding paragraph (e)(1)(xiv); and
0
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
be met 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 (ft\2\)
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 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
[[Page 4351]]
(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 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
[[Page 4352]]
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 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;
[[Page 4353]]
(D) A statement that the unit meets the applicability requirements
in 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. 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.
0
23. Section 75.57 is amended by:
0
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);
0
b. Revising Table 4a in paragraph (c)(4)(iv);
0
c. Removing the word ``hundredth'' and adding in its place the word
``tenth'' in paragraph (i)(1)(iv); and
0
d. Removing the words ``, Sec. 75.12(b),'' from paragraphs (i)(2) and
(j)(2).
The revisions 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 estimation
Code 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).
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 CO2 concentration, 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.)
[[Page 4354]]
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 1.111 when
one of the paired traps is invalidated or damaged
(See Appendix K, section 8).
33................ Hourly Hg concentration determined from the trap
resulting in the higher Hg concentration when the
relative deviation criterion for the paired traps
is not met (See Appendix K, section 8).
40................ Fuel specific default value (or prorated default
value) used for the hour.
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.
------------------------------------------------------------------------
* * * * *
0
24. Section 75.58 is amended by:
0
a. Revising paragraph (b)(3) introductory text;
0
b. Removing paragraphs (b)(3)(iii) and (b)(3)(iv);
0
c. Removing the word ``and'' from paragraph (c)(1)(xii);
0
d. Removing the period and adding in its place a semicolon and adding
the word ``and'' to the end of the paragraph, in paragraph
(c)(1)(xiii);
0
e. Adding paragraph (c)(1)(xiv);
0
f. Removing the period and adding in its place a semicolon and adding
the word ``and'' to the end of the paragraph, in paragraph (c)(4)(x);
0
g. Adding paragraph (c)(4)(xi);
0
h. Removing the words ``rounded to the nearest hundredth for diesel
fuel'' and adding in its place the words ``rounded to either the
nearest hundredth, or nearest ten-thousandth for diesel fuels'' in
paragraph (c)(5)(ii);
0
i. Removing the word ``and'' after the semicolon in paragraph
(d)(1)(ix).
0
j. Removing the period and adding in its place a semicolon and adding
the word ``and'' to the end of the paragraph, in paragraph (d)(1)(x);
0
k. Adding paragraph (d)(1)(xi);
0
l. Removing the word ``and'' after the semicolon in paragraph
(d)(2)(ix);
0
m. Removing the period and adding in its place a semicolon and adding
the word ``and'' to the end of the paragraph, in paragraph (d)(2)(x);
0
n. Adding paragraph (d)(2)(xi);
0
o. Revising paragraph (f)(1)(iii);
0
p. Removing the word ``and'' at the end of paragraph (f)(1)(xi);
0
q. Removing the period and adding in its place a semicolon at the end
of paragraph (f)(1)(xii);
0
r. Adding paragraphs (f)(1)(xiii) and (f)(1)(xiv); and
0
s. Removing the word ``Component'' and adding in its place 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.
* * * * *
0
25. Section 75.59 is amended by:
0
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);
0
b. Revising paragraph (a)(1)(viii);
0
c. Removing the phrase ``For the qualifying test for off-line
calibration, the owner or operator shall indicate'' and adding in its
place the phrase ``Indication of'', in paragraph (a)(1)(xi);
0
d. Adding the phrase ``(after January 1, 2009, only the component
identification code is required)'' after the word ``code'', in
paragraph (a)(2)(i);
0
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);
0
f. Adding the phrase ``(only span scale is required on and after
January 1, 2009)'' after the word ``scale'', in paragraph (a)(3)(ii);
0
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);
0
h. Removing the word ``and'' after the semicolon at the end of
paragraph (a)(4)(vi)(L);
0
i. Removing the period and adding in its place a semicolon and adding
the word ``and'' at the end of paragraph (a)(4)(vi)(M);
0
j. Adding paragraph (a)(4)(vi)(N);
0
k. Removing the word ``and'' after the semicolon, at the end of
paragraph (a)(4)(vii)(K);
0
l. Removing the period and adding in its place a semicolon and adding
the word ``and'' at the end of paragraph (a)(4)(vii)(L);
0
m. Adding paragraph (a)(4)(vii)(M);
0
n. Revising paragraph (a)(6) introductory text;
0
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);
0
p. Removing the phrase ``Cycle time result for the entire system'' and
adding in its place the phrase ``Total cycle time'', in paragraph
(a)(6)(ix);
0
q. Revising the heading of reserved paragraph (a)(7)(viii);
0
r. Adding paragraphs (a)(7)(ix) and (a)(7)(x);
0
s. Revising paragraph (a)(8);
[[Page 4355]]
0
t. Removing and reserving paragraph (a)(12)(iii);
0
u. Removing the number ``(2)'' from the paragraph identifier ``Sec.
75.64(a)(2)'' in the second sentence of paragraph (a)(13);
0
v. 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);
0
w. 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);
0
x. Removing the word ``and'' after the semicolon at the end of
paragraph (b)(4)(i)(H);
0
y. Removing the period and adding in its place a semicolon and adding
the word ``and'' at the end of paragraph (b)(4)(i)(I);
0
z. Adding paragraph (b)(4)(i)(J);
0
aa. Revising paragraphs (b)(4)(ii)(A), (b)(4)(ii)(B), and
(b)(4)(ii)(F);
0
bb. Removing the word ``and'' after the semicolon at the end of
paragraph (b)(4)(ii)(L);
0
cc. Removing the period and adding in its place a semicolon and adding
the word ``and'' at the end of paragraph (b)(4)(ii)(M);
0
dd. Adding paragraph (b)(4)(ii)(N);
0
ee. 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);
0
ff. Adding the phrase ``This requirement remains in effect through
December 31, 2008'' after the word ``run;'', in paragraph (b)(5)(i)(H);
0
gg. Adding the phrase ``(as applicable). This requirement remains in
effect through December 31, 2008'' after the word ``level'', in
paragraph (b)(5)(iv)(A);
0
hh. Removing the word ``and'' after the semicolon at the end of
paragraph (b)(5)(iv)(G);
0
ii. Removing the period and adding in its place a semicolon and adding
the word ``and'' at the end of paragraph (b)(5)(iv)(H);
0
jj. Adding paragraph (b)(5)(iv)(I);
0
kk. Removing the word ``and'' after the semicolon at the end of
paragraph (d)(1)(xi);
0
ll. Removing the period and adding in its place a semicolon and adding
the word ``and'' at the end of paragraph (d)(1)(xii);
0
mm. Adding paragraph (d)(1)(xiii);
0
nn. Removing the phrase ``, multiplied by 1.15, if appropriate'' from
paragraph (d)(2)(iii);
0
oo. Removing the word ``and'' after the semicolon at the end of
paragraph (d)(2)(iv);
0
pp. Removing the period and adding in its place a semicolon at the end
of paragraph (d)(2)(v); and
0
qq. 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) * * *
(viii) Data elements for Methods 30A and 30B. [Reserved]
(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 in appendices A-1 and A-2 to
part 60 of this chapter, 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 in appendix A-8 to part 60 of
this chapter 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 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).
* * * * *
[[Page 4356]]
(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).)
* * * * *
0
26. 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.
* * * * *
0
27. Section 75.61 is amended by:
0
a. Revising the first sentence of paragraph (a)(1) introductory text;
0
b. Revising paragraph (a)(3);
0
c. Revising the first sentence of paragraph (a)(5) introductory text;
and
0
d. Adding paragraphs (a)(7) and (a)(8)
The revisions and additions read as follows:
Sec. 75.61 Notifications.
(a) * * *
(1) * * * 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 shut down 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) * * * 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
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 of this chapter.
(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
[[Page 4357]]
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.
* * * * *
0
28. Section 75.62 is amended by:
0
a. Revising paragraph (a)(1); and
0
b. Removing the number ``45'' and adding in its place the number ``21''
before the phrase ``days prior'', in paragraph (a)(2).
The revisions 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.
* * * * *
0
29. Section 75.63 is amended by:
0
a. Removing the phrase ``and a hardcopy certification application form
(EPA form 7610-14)'' from paragraph (a)(1)(i)(A);
0
b. Revising paragraph (a)(1)(ii)(A);
0
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);
0
d. Removing the phrase ``and a hardcopy certification application form
(EPA form 7610-14)'' after the word ``section'', in paragraph
(a)(2)(i);
0
e. Revising paragraph (a)(2)(iii);
0
f. Removing and reserving paragraph (b)(2)(iii);
0
g. Revising paragraph (b)(2)(iv).
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.
* * * * *
(b) * * *
(2) * * *
(iv) Designated representative signature certifying the accuracy of
the submission.
* * * * *
0
30. Section 75.64 is amended by:
0
a. Revising paragraph (a) introductory text;
0
b. Redesignate paragraph (a)(2)(xiv) as paragraph (a)(2)(xiii);
0
c. Revise newly designated paragraph (a)(2)(xiii);
0
d. Removing paragraph (a)(8);
0
e. Redesignating paragraphs (a)(9) through (a)(11) as paragraphs
(a)(13) through (a)(15), and redesignating paragraphs (a)(3) through
(a)(7) as paragraphs (a)(8) through (a)(12);
0
f. Adding new paragraphs (a)(3) through (a)(7); and
0
g. Removing the citation ``Sec. 75.59'', and adding in its place
``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 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) of this section. 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)
[[Page 4358]]
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 in appendices A-1 and A-2 to part 60 of this chapter), 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 in
appendices A-1 and A-2 to part 60 of this chapter 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 in appendices A-1
and A-2 to part 60 of this chapter 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 in appendices A-1 and A-2 to part 60 of this chapter 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 of this
part;
(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 in appendices A-1 and A-2 to part 60 of this chapter),
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 in
appendices A-1 and A-2 to part 60 of this chapter 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 in appendices A-1
and A-2 to part 60 of this chapter 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 in appendices A-1 and A-2 to part 60 of this chapter is used
and a wall effects adjustment factor is applied.
* * * * *
Sec. 75.66 [Amended]
0
31. Section 75.66 is amended by removing and reserving paragraph (f).
0
32. Section 75.71 is amended by:
0
a. Revising the section heading;
0
b. In paragraph (a)(1), by removing the second occurrence of the phrase
``CO2 diluent gas monitor'' and adding in its place the
phrase ``CO2 diluent gas monitoring system'';
0
c. Removing the phrase ``O2 or CO2 diluent gas
monitor'' and adding in its place the phrase ``O2 or
CO2 monitoring system'', in paragraph (a)(2); and
0
d. 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
Sec. 75.19 (c)(4)(ii)(A), and dividing this sum by 2000 lb/ton.
* * * * *
0
33. Section 75.72 is amended by:
0
a. Revising the section heading and the introductory text;
0
b. Revising paragraph (c)(3); and
0
c. 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/
[[Page 4359]]
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.
* * * * *
(c) * * *
(3) Install, certify, operate, and maintain a NOX-
diluent CEMS and a flow monitoring system 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, since only the main stack is monitored. 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 NOX mass
emissions as follows. If the unit heat input is determined using a flow
monitor and a diluent monitor, report NOX mass emissions
using the maximum potential NOX emission rate, the maximum
potential flow rate, and either the maximum potential CO2
concentration or the minimum potential O2 concentration (as
applicable). 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)). If the unit heat input is determined using a
fuel flowmeter, in accordance with appendix D to this part, report
NOX mass emissions as the product of the maximum potential
NOX emission rate and the actual measured hourly heat input
rate. Alternatively, for a unit with NOX add-on emission
controls, for each unit operating hour in which the bypass stack is
used but the add-on NOX emission controls are not bypassed,
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)'' and by using the NOX
MEC in the calculations instead of the NOX MPC.
* * * * *
(f) [Reserved]
* * * * *
0
34. Section 75.73 is amended by:
0
a. Revising paragraph (c)(3);
0
b. Removing the number ``45'' and adding in its place the number ``21''
in paragraphs (e)(1) and (e)(2);
0
c. Revising paragraph (f)(1) introductory text;
0
d. Removing the phrase ``paragraph (a)'' and adding in its place the
phrase ``paragraphs (a) and (b)'' in paragraph (f)(1)(ii) introductory
text; and
0
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. 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) of this section, 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) of this section 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
[[Page 4360]]
2F or 2G in appendices A-1 and A-2 to part 60 of this chapter), 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 in
appendices A-1 and A-2 to part 60 of this chapter 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 in appendices A-1
and A-2 to part 60 of this chapter 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 in appendices A-1 and A-2 to part 60 of this chapter is used
and a wall effects adjustment factor is applied.
* * * * *
0
35. Section 75.74 is amended by:
0
a. Removing the phrase ``In the time period prior 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'', and adding in its place the word ``The'', in paragraph
(c)(2) introductory text;
0
b. Adding the words ``in the second calendar quarter no later than
April 30'' to the end of paragraph (c)(2)(i) introductory text;
0
c. Removing the phrase ``of the current calendar year'' from the first
sentence, and removing the last sentence of paragraph (c)(2)(i)(C);
0
d. Revising paragraph (c)(2)(i)(D);
0
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;
0
f. Removing the words ``of the current calendar year'' from paragraph
(c)(2)(ii)(E);
0
g. Revising paragraph (c)(2)(ii)(F);
0
h. Removing paragraphs (c)(2)(ii)(G) and (c)(2)(ii)(H);
0
i. Revising paragraph (c)(3)(ii);
0
j. Removing and reserving paragraphs (c)(3)(vi) through (viii);
0
k. Removing all occurrences of the words ``Sec. 75.31, Sec. 75.33, or
Sec. 75.37'' and adding in their place the words ``Sec. Sec. 75.31
through 75.37'' in paragraphs (c)(3)(xi), (c)(3)(xii)(A), and
(c)(3)(xii)(B);
0
l. Revising paragraph (c)(6)(iii);
0
m. Removing the words ``October 1 of the previous calendar year'' and
adding in its place the words ``January 1'' in paragraph (c)(6)(v);
0
n. Revising paragraph (c)(7)(iii)(L);
0
o. Revising paragraph (c)(8)(ii); and
0
p. Revising paragraph (c)(11).
The revisions 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 owner or operator may opt to report unit
operating data, daily calibration error test and flow monitor
interference check results, and hourly emission data in the time period
from April 1 through April
[[Page 4361]]
30. However, only the data recorded in the time period from May 1
through September 30 shall be used for NOX mass compliance
determination;
* * * * *
(7) * * *
(iii) * * *
(L) In Sec. 75.34(a)(3) and (a)(5), the phrases ``720 quality-
assured monitor operating hours within the ozone season'' and ``2160
quality-assured monitor operating hours within the ozone season'' apply
instead of ``720 quality-assured monitor operating hours'' and ``2160
quality-assured monitor operating hours'', respectively.
(8) * * *
(ii) For units with add-on emission controls, using the missing
data options in Sec. Sec. 75.34(a)(1) through 75.34(a)(5), the range
of operating parameters for add-on emission controls (as defined in the
quality assurance/quality control program for the unit required by
section 1 in appendix B to this part) and information for verifying
proper operation of the add-on emission controls during missing data
periods, as described in Sec. 75.34(d).
* * * * *
(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''.
Sec. 75.80 [Amended]
0
36. Section 75.80(f)(1)(iii) is amended by removing the words ``or
Sec. 75.12(b),''.
0
37. Section 75.81 is amended by:
0
a. Removing the words ``or Sec. 75.12(b)'' and ``or Sec. 75.12,''
from paragraph (a)(3);
0
b. Revising paragraph (a)(4);
0
c. Revising paragraph (c)(1);
0
d. Revising paragraph (c)(2);
0
e. Removing Eq. 1 from paragraph (d)(1);
0
f. Revising paragraph (d)(2);
0
g. Adding paragraph (d)(4)(iv); and
0
h. 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 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.
(i) 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 shall be representative of the coal
that will be combusted at the start of the Hg mass emissions reduction
program (preferably from the same source(s) of supply).
(ii) The minimum time per run shall be 1 hour if Method 30A is
used. If either Method 29 in appendix A-8 to part 60 of this chapter,
ASTM D6784-02 (the Ontario Hydro method) (incorporated by reference
under Sec. 75.6 of this part), or Method 30B is used, paired samples
are required for each test run and the runs must be long enough to
ensure that sufficient Hg is collected to analyze. When Method 29 in
appendix A-8 to part 60 of this chapter 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 in appendix A-8 to part 60 of
this chapter, Method 30B, or Ontario Hydro method test run, the paired
trains must meet the relative deviation (RD) requirement specified in
Sec. 75.22(a)(7) or Method 30B, as applicable. If the RD specification
is met, the results of the two samples shall be averaged
arithmetically.
(iii) 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).
(iv) If two or more of units of the same type 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 these 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. For the purposes of the required retests under paragraph (d)(4)
of this section, EPA strongly recommends that (to the extent
practicable) the same subset of the units not be tested in two
successive retests, and that every effort be made to ensure that each
unit in the group of identical units is tested in a timely manner.
(2)(i) 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] TR24JA08.018
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
N = Either 8,760 (the number of hours in a year) or the maximum
number of operating hours per year (if less than 8,760) allowed by
the unit's Federally-enforceable operating permit.
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)
(ii) Equation 1 of this section assumes that the unit operates at
its maximum potential flow rate, either year-round or for the maximum
number of hours allowed by the operating permit (if unit operation is
restricted to less than 8,760 hours per year). If the permit restricts
the annual unit heat input but not the number of annual unit operating
hours, the owner or operator may divide the allowable annual heat input
(mmBtu) by the design rated heat input capacity of the unit (mmBtu/hr)
to determine the value of ``N'' in Equation 1. Also, note that if the
highest Hg concentration
[[Page 4362]]
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
coal rank of the primary fuel (e.g., when the primary fuel is switched
from bituminous coal to lignite). Use ASTM D388-99 (incorporated by
reference under Sec. 75.6 of this part) to determine the coal rank.
The four principal coal ranks are anthracitic, bituminous,
subbituminous, and lignitic. The ranks of anthracite coal refuse (culm)
and bituminous coal refuse (gob) shall be anthracitic and bituminous,
respectively. 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 coal rank of the primary fuel. 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 the units' combined potential to emit does not
exceed 464 ounces of Hg per year times the number of units sharing the
stack, in accordance with paragraphs (c) and (d) of this section. 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 or 0.50 [mu]g/scm, whichever is
greater.
(i) The initial emission testing required under paragraph (c) of
this section may be performed at the common stack if the following
conditions are met. Otherwise, testing of the individual units (or a
subset of the units, if identical, as described in paragraph (c)(1)(iv)
of this section) is required:
(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. The coal combusted in each unit during the testing must be
representative of the coal that will be combusted in that unit at the
start of the Hg mass emission reduction program (preferably from the
same source(s) of supply);
(C) If flue gas desulfurization and/or add-on Hg emission controls
are used to reduce level the emissions exiting from the common stack,
these emission controls must be operating normally during the emission
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);
(D) When calculating E, the estimated maximum potential annual Hg
mass emissions from the stack, substitute 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) into Equation 1;
(E) 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
(F) 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) The retests required under paragraph (d)(4) of this section
may also 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 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. Provided that the required load level is attained and that
all of the units sharing the stack are fed from the same on-site coal
supply during normal operation, it is not necessary for all of the
units sharing the stack to be in operation during a retest. However, if
two or more of the units that share the stack are fed from different
on-site coal supplies (e.g., one unit burns low-sulfur coal for
compliance and the other combusts higher-sulfur coal), then either:
(A) Perform the retest with all units in normal operation; or
(B) If this is not possible, due to circumstances beyond the
control of the owner or operator (e.g., a forced unit outage), perform
the retest with the available units operating and assess the test
results as follows. Use the Hg concentration obtained in the retest for
reporting purposes under this part if the concentration is greater than
or equal to the value obtained in the most recent test. If the retested
value is lower than the Hg concentration from the previous test,
continue using the higher value from the previous test for reporting
purposes and use that same higher Hg concentration value in Equation 1
to determine the due date for the next retest, as described in
paragraph (e)(1)(iii) of this section.
(iii) If testing is done at the common stack, the due date for the
next scheduled retest shall be determined as follows:
(A) Substitute 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) 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.
* * * * *
0
38. Section 75.82 is amended by:
0
a. Adding paragraph (b)(3);
0
b. Removing the word ``or'' at the end of paragraph (c)(2);
[[Page 4363]]
0
c. Removing the period at the end of paragraph (c)(3), and adding in
its place the phrase ``; or'';
0
d. Adding paragraph (c)(4);
0
e. Removing the word ``or'' at the end of paragraph (d)(1);
0
f. Removing the period at the end of paragraph (d)(2), and adding in
its place the phrase ``; or''; and
0
g. Adding paragraph (d)(3).
The revisions and additions 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.
0
39. Section 75.84 is amended by:
0
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)'', in
paragraph (c)(3);
0
b. Removing the number ``45'' and adding in its place the number ``21''
in paragraphs (e)(1) and (e)(2);
0
c. Revising paragraph (f)(1) introductory text;
0
d. Removing ``Sec. 75.64(a)(1)'' and adding in its place ``Sec.
75.64(a)(3)'' in paragraph (f)(1)(i);
0
e. Removing the phrase ``paragraph (a)'' and adding in its place the
phrase ``paragraphs (a) and (b)'' in paragraph (f)(1)(ii) introductory
text; and
0
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. 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 in appendices A-1 and A-2 to part 60 of this chapter),
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 in
appendices A-1 and A-2 to part 60 of this chapter 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 in appendices A-1
and A-2 to part 60 of this chapter 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 in appendices A-1 and A-2 to part 60 of this chapter is used
and a wall effects adjustment factor is applied.
* * * * *
0
40. Appendix A to Part 75 is amended by:
0
a. Revising paragraph (c) of section 2.1.1.1;
0
b. Revising paragraph (b)(2) of section 2.1.1.5;
0
c. Revising paragraph (b)(2) of section 2.1.2.5;
0
d. Adding a new fourth sentence after the third sentence of section
2.1.3;
0
e. Revising paragraph (3) of section 3.2;
0
f. Removing the phrase ``continuous emission monitoring system(s)'' and
adding in its place the phrase ``monitoring component of a continuous
emission monitoring system that is'' in section 3.5;
0
g. Adding the words ``that meet the definition for a NIST Traceable
Reference Material (NTRM) provided in Sec. 72.2.'' after the word
``gases'' in section 5.1.3;
0
h. Revising sections 5.1.4 and 5.1.9;
0
i. Redesignating section 6.1 as section 6.1.1 and adding a new heading
for 6.1;
0
j. Adding section 6.1.2;
0
k. Revising the second and third sentences and adding a new fourth
sentence to section 6.2, introductory text;
0
l. Revising section 6.2(g);
0
m. Adding paragraph (h) to section 6.2;
0
n. Adding a new fourth sentence to section 6.3.1, introductory text;
0
o. Revising the introductory text of section 6.4;
[[Page 4364]]
0
p. Revising paragraph (e) in section 6.5;
0
q. 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;
0
r. 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;
0
s. 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;
0
t. Adding the words ``and LME units'' after the words ``For peaking
units'' in the third sentence in paragraph (d)(1) of section 6.5.2.1;
0
u. Revising paragraph (e) of section 6.5.2.1;
0
v. Revising paragraph (c) in section 6.5.6;
0
w. Removing all occurrences of the words ``section 3.2'' and adding in
its place 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;
0
x. Revising section 6.5.10;
0
y. Adding two sentences at the end of section 7.6.1;
0
z. Revising the terms Rref and Lavg, in paragraph
(a) of section 7.7;
0
aa. Revising the terms (GHR)ref and Lavg, in
paragraph (c) of section 7.7; and
0
bb. Removing Figure 6 and adding in its place Figures 6a and 6b and
revising A through F and adding G at the end of appendix A.
The revisions and additions read as follows:
Appendix A to Part 75--Specifications and Procedures
* * * * *
2. Equipment Specifications
2.1.1.1 Maximum Potential Concentration
* * * * *
(c) When performing fuel sampling to determine the MPC, use ASTM
Methods: ASTM D3177-02 (Reapproved 2007), 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 and Petroleum
Products by Energy-Dispersive X-ray Fluorescence Spectrometry; 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 Wavelength
Dispersive X-ray Fluorescence Spectrometry, for sulfur content of
solid or liquid fuels; ASTM D3176-89 (Reapproved 2002), Standard
Practice for Ultimate Analysis of Coal and Coke; ASTM D240-00,
Standard Test Method for Heat of Combustion of Liquid Hydrocarbon
Fuels by Bomb Calorimeter; or ASTM D5865-01a, Standard Test Method
for Gross Calorific Value of Coal and Coke (all incorporated by
reference under Sec. 75.6 of this part).
* * * * *
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. 75.20(c)(1)(ii) and (c)(1)(vi), the measurement error shall
not exceed 10.0 percent of the reference 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 reference 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.,
[verbar]R-A[verbar] in Equation A-4 of this appendix, does not
exceed 0.8 [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
* * * * *
5.1.4 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.
(c) On and after January 1, 2009, 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 not
participating in the PGVP may not certify a calibration gas as an
EPA Protocol Gas, 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.html.
* * * * *
5.1.9 Mercury Standards
For 7-day calibration error tests of Hg concentration monitors
and for daily calibration error tests of Hg monitors, either NIST-
traceable elemental Hg standards (as defined in Sec. 72.2 of this
chapter) or a NIST-traceable source of oxidized Hg (as defined in
Sec. 72.2 of this chapter) may be used. For linearity checks, NIST-
traceable 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.
[[Page 4365]]
Alternatively, other NIST-traceable standards may be used for the
required checks, subject to the approval of the Administrator.
Notwithstanding these requirements, Hg calibration standards that
are not NIST-traceable may be used for the tests described in this
section until December 31, 2009. However, on and after January 1,
2010, only NIST-traceable calibration standards shall be used for
these tests.
* * * * *
6.1 General Requirements
* * * * *
6.1.2 Requirements for Air Emission Testing Bodies
(a) On and after January 1, 2009, 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 (incorporated by reference under Sec.
75.6 of this part). 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 (incorporated by reference under
Sec. 75.6 of this part). 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 (incorporated by
reference under Sec. 75.6 of this part). 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, for initial certification, recertification, 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, 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, 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. Use a zero-level
and a high-level calibration gas (as defined in section 5.2 of this
appendix) alternately. For Hg monitors, the calibration gas used for
this test may either be the elemental or oxidized form of Hg. To
determine the downscale cycle time, measure the concentration of the
flue gas emissions until the response stabilizes. Record the stable
emissions value. 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 time of the
zero gas injection, using the data acquisition and handling system
(DAHS). Next, allow the monitor to measure the concentration of the
zero gas until the response stabilizes. Record the stable ending
calibration gas reading. Determine the downscale cycle time as the
time it takes for 95.0 percent of the step change to be achieved
between the stable stack emissions value and the stable ending zero
gas reading. Then repeat the procedure, starting with stable stack
emissions and injecting the high-level gas, to determine the upscale
cycle time, which is the time it takes for 95.0 percent of the step
change to be achieved between the stable stack emissions value and
the stable ending high-level gas reading. Use the following criteria
to assess when a stable reading of stack emissions or calibration
gas concentration has been attained. 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, 0.5 [mu]g/m\3\ (for Hg), 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. Refer to Figures 6a
and 6b in this appendix for example calculations of upscale and
downscale cycle times. Report the slower of the two cycle times
(upscale or downscale) as the cycle time for the analyzer. 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 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 for each range separately. 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 * * *
(e) Complete each single-load relative accuracy test audit
within a period of 168 consecutive unit operating hours, as defined
in Sec. 72.2 of this chapter (or, for CEMS installed on common
stacks or bypass stacks, 168 consecutive stack operating hours, as
defined in Sec. 72.2 of this chapter). Notwithstanding this
requirement, up to 336 consecutive unit or stack operating hours may
be taken to complete the RATA of a Hg monitoring system, when ASTM
6784-02 (incorporated by reference under Sec. 75.6 of this part) or
Method 29 in appendix A-8 to part 60 of this chapter is used as the
reference method. For 2-level and 3-level flow monitor RATAs,
complete all of the RATAs at all levels, to the extent practicable,
within a period of 168 consecutive unit (or stack) operating hours;
however, if this is not possible, up to 720 consecutive unit (or
stack) operating hours may be taken to complete a multiple-load flow
RATA.
* * * * *
6.5.2.1 * * *
(e) The owner or operator shall report the upper and lower
boundaries of the range of operation for each unit (or combination
of units, for common stacks), in units of megawatts or thousands of
lb/hr or mmBtu/hr of steam production or ft/sec (as applicable), in
the electronic monitoring plan required under Sec. 75.53. Except
for peaking units and LME units, the owner or operator shall
indicate, in the electronic monitoring plan, the load level (or
levels) designated as normal under this section and shall also
indicate the two most frequently used load levels.
* * * * *
[[Page 4366]]
6.5.6 * * *
(c) For Hg monitoring systems, use the same basic approach for
traverse point selection that is used for the other gas monitoring
system RATAs, except that the stratification test provisions in
sections 8.1.3 through 8.1.3.5 of Method 30A shall apply, rather
than the provisions of sections 6.5.6.1 through 6.5.6.3 of this
appendix.
6.5.10 Reference Methods
The following methods are from appendix A to part 60 of this
chapter or have been published by ASTM, and are the reference
methods for performing relative accuracy test audits under this
part: Method 1 or 1A in appendix A-1 to part 60 of this chapter for
siting; Method 2 in appendices A-1 and A-2 to part 60 of this
chapter or its allowable alternatives in appendix A to part 60 of
this chapter (except for Methods 2B and 2E in appendix A-1 to part
60 of this chapter) for stack gas velocity and volumetric flow rate;
Methods 3, 3A or 3B in appendix A-2 to part 60 of this chapter for
O2 and CO2; Method 4 in appendix A-3 to part
60 of this chapter for moisture; Methods 6, 6A or 6C in appendix A-4
to part 60 of this chapter for SO2; Methods 7, 7A, 7C, 7D
or 7E in appendix A-4 to part 60 of this chapter for NOX,
excluding the exceptions of Method 7E in appendix A-4 to part 60 of
this chapter identified in Sec. 75.22(a)(5); and for Hg, either
ASTM D6784-02 (the Ontario Hydro Method) (incorporated by reference
under Sec. 75.6 of this part), Method 29 in appendix A-8 to part 60
of this chapter, Method 30A, or Method 30B When using Method 7E in
appendix A-4 to part 60 of this chapter for measuring NOX
concentration, total NOX, both NO and NO2,
must be measured.
* * * * *
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/m\3\) from the
paired Ontario Hydro or Method 29 in appendix A-8 to part 60 of this
chapter 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''.
* * * * *
7.7 * * *
(a) * * *
Rref = Reference value of the flow-to-load ratio, from
the most recent normal-load flow RATA, scfh/megawatts, scfh/1000 lb/
hr of steam, or scfh/(mmBtu/hr of steam output).
* * * * *
Lavg = Average unit load during the normal-load flow
RATA, megawatts, 1000 lb/hr of steam, or mmBtu/hr of thermal output.
* * * * *
(c) * * *
(GHR)ref = Reference value of the gross heat rate at the
time of the most recent normal-load flow RATA, Btu/kwh, Btu/lb steam
load, or Btu heat input/mmBtu steam output.
* * * * *
Lavg = Average unit load during the normal-load flow
RATA, megawatts, 1000 lb/hr of steam, or mmBtu/hr thermal output.
[GRAPHIC] [TIFF OMITTED] TR24JA08.000
[[Page 4367]]
[GRAPHIC] [TIFF OMITTED] TR24JA08.001
A. To determine the upscale cycle time (Figure 6a), measure the
flue gas emissions until the response stabilizes. Record the
stabilized value (see section 6.4 of this appendix for the stability
criteria).
B. Inject a high-level calibration gas into the port leading to
the calibration cell or thimble (Point B). Allow the analyzer to
stabilize. Record the stabilized value.
C. Determine the step change. The step change is equal to the
difference between the final stable calibration gas value (Point D)
and the stabilized stack emissions value (Point A).
D. Take 95% of the step change value and add the result to the
stabilized stack emissions value (Point A). Determine the time at
which 95% of the step change occurred (Point C).
E. Calculate the upscale cycle time by subtracting the time at
which the calibration gas was injected (Point B) from the time at
which 95% of the step change occurred (Point C). In this example,
upscale cycle time = (11-5) = 6 minutes.
F. To determine the downscale cycle time (Figure 6b) repeat the
procedures above, except that a zero gas is injected when the flue
gas emissions have stabilized, and 95% of the step change in
concentration is subtracted from the stabilized stack emissions
value.
G. Compare the upscale and downscale cycle time values. The
longer of these two times is the cycle time for the analyzer.
0
41. Appendix B to Part 75 is amended by:
0
a. Adding section 1.1.4;
0
b. Revising section 2.1.1;
0
c. Revising paragraph (2) of section 2.1.1.2;
0
d. Revising paragraph (2) of section 2.1.5.1;
0
e. Adding paragraph (3) to section 2.1.5.1;
0
f. Adding a new fourth sentence to paragraph (e) of section 2.2.3;
0
g. Revising the terms ``Rh'' and ``Lh'' in
paragraph (a) of section 2.2.5;
0
h. Revising the terms ``(GHR)h'' and ``Lh'' in
paragraph (a)(2) of section 2.2.5;
0
i. Removing the word ``five'' and adding in its place the word
``twenty'', and by removing the word ``years'' and adding in its place
the word ``quarters'', in paragraph (c)(4) of section 2.3.1.3;
0
j. Revising paragraphs (d) and (g) of section 2.3.2;
0
k. Revising paragraphs (a)(2) and (c) of section 2.3.3;
0
l. Adding paragraph (d) to section 2.3.3;
0
m. Revising section 2.6;
0
n. Revising Figure 1; and
0
o. Revising 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 Hg emission tests described in Sec. Sec.
75.81(c) and 75.81(d)(4).
* * * * *
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.
* * * * *
[[Page 4368]]
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, a combination of on-line and off-line calibration
error tests may be used to validate data from the monitor, as
follows. For a particular unit (or stack) operating hour, data from
a monitor may be validated using a successful off-line calibration
error test if: (a) An on-line calibration error test has been passed
within the previous 26 unit (or stack) operating hours; and (b) the
26 clock hour data validation window for the off-line calibration
error test has not expired. If either of these conditions is not
met, then the data from the monitor are invalid with respect to the
daily calibration error test requirement. Data from the monitor
shall remain invalid until the appropriate on-line or off-line
calibration error test is successfully completed so that both
conditions (a) and (b) are met.
(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 was passed but 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. * * *
* * * * *
2.2.5 * * *
(a) * * *
Rh = Hourly value of the flow-to-load ratio, scfh/
megawatts, scfh/1000 lb/hr of steam, or scfh/(mmBtu/hr thermal
output).
* * * * *
Lh = Hourly unit load, megawatts, 1000 lb/hr of steam, or
mmBtu/hr thermal output; must be within + 10.0 percent of
Lavg during the most recent normal-load flow RATA.
* * * * *
(2) * * *
(GHR)h = Hourly value of the gross heat rate, Btu/kwh,
Btu/lb steam load, or 1000 mmBtu heat input/mmBtu thermal output.
* * * * *
Lh = Hourly unit load, megawatts, 1000 lb/hr of
steam, or mmBtu/hr thermal output; must be within + 10.0 percent of
Lavg during the most recent normal-load flow RATA.
* * * * *
2.3.2 * * *
(d) For single-load (or single-level) RATAs, if a daily
calibration error test is failed during a RATA test period, prior to
completing the test, the RATA must be repeated. Data from the
monitor are invalidated prospectively from the hour of the failed
calibration error test until the hour of completion of a subsequent
successful calibration error test. The subsequent RATA shall not be
commenced until the monitor has successfully passed a calibration
error test in accordance with section 2.1.3 of this appendix.
Notwithstanding these requirements, when ASTM D6784-02 (incorporated
by reference under Sec. 75.6 of this part) or Method 29 in appendix
A-8 to part 60 of this chapter is used as the reference method for
the RATA of a Hg CEMS, if a calibration error test of the CEMS is
failed during a RATA test period, any test run(s) completed prior to
the failed calibration error test need not be repeated; however, the
RATA may not continue until a subsequent calibration error test of
the Hg CEMS has been passed. For multiple-load (or multiple-level)
flow RATAs, each load level (or operating level) is treated as a
separate RATA (i.e., when a calibration error test is failed prior
to completing the RATA at a particular load level (or operating
level), only the RATA at that load level (or operating level) must
be repeated; the results of any previously-passed RATA(s) at the
other load level(s) (or operating level(s)) are unaffected, unless
re-linearization of the monitor is required to correct the problem
that caused the calibration failure, in which case a subsequent 3-
load (or 3-level) RATA is required), except as otherwise provided in
section 2.3.1.3(c)(5) of this appendix.
* * * * *
(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 CO2 (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 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. 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.
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.
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. 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 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.
* * * * *
[[Page 4369]]
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.
* * * * *
Figure 1 to Appendix B of Part 75.--Quality Assurance Test Requirements
--------------------------------------------------------------------------------------------------------------------------------------------------------
Basic QA test frequency requirements *
Test --------------------------------------------------------------------------------------------------------------------
Daily * Weekly Quarterly * Semiannual * Annual
--------------------------------------------------------------------------------------------------------------------------------------------------------
Calibration Error Test (2 pt.)..... ............... ...................... ..................... ..................... .....................
Interference Check (flow).......... ............... ...................... ..................... ..................... .....................
Flow-to-Load Ratio................. ...................... ...................... .............. ..................... .....................
Leak Check (DP flow monitors)...... ...................... ...................... .............. ..................... .....................
Linearity Check or System Integrity ...................... ...................... .............. ..................... .....................
Check ** (3 pt.).
Single-point System Integrity Check ...................... ............... ..................... ..................... .....................
**.
RATA (SO2, NOX, CO2, O2, H2O) \1\.. ...................... ...................... ..................... .............. .....................
RATA (All Hg monitoring systems)... ...................... ...................... ..................... .....................
RATA (flow) 1 2.................... ...................... ...................... ..................... .............. .....................
--------------------------------------------------------------------------------------------------------------------------------------------------------
* ``Daily'' means operating days, only. ``Weekly'' means once every 168 unit or stack operating hours. ``Quarterly'' means once every QA operating
quarter. ``Semiannual'' means once every two QA operating quarters. ``Annual'' means once every four QA operating quarters.
** The system integrity check applies only to Hg monitors with converters. The single-point weekly system integrity check is not required if daily
calibrations are performed using a NIST-traceable source of oxidized Hg. The 3-point quarterly system integrity check is not required if a linearity
check is performed.
\1\ Conduct RATA annually (i.e., once every four QA operating quarters), if monitor meets accuracy requirements to qualify for less frequent testing.
\2\ For flow monitors installed on peaking units, bypass stacks, or units that qualify for single-level RATA testing under section 6.5.2(e) of this
part, conduct all RATAs at a single, normal load (or operating level). For other flow monitors, conduct annual RATAs at two load levels (or operating
levels). Alternating single-load and 2-load (or single-level and 2-level) RATAs may be done if a monitor is on a semiannual frequency. A single-load
(or single-level) RATA may be done in lieu of a 2-load (or 2-level) RATA if, since the last annual flow RATA, the unit has operated at one load level
(or operating level) for >=85.0 percent of the time. A 3-level RATA is required at least once every five calendar years and whenever a flow monitor is
re-linearized, except for flow monitors exempted from 3-level RATA testing under section 6.5.2(b) or 6.5.2(e) of appendix A to this part.
Figure 2 to Appendix B of Part 75.--Relative Accuracy Test Frequency
Incentive System
------------------------------------------------------------------------
Semiannual W
RATA (percent) Annual W
------------------------------------------------------------------------
SO2 or NOXY................. 7.5% < RA < =10.0% or RA < = 7.5% or < plus-
15.0 minus>12.0 ppm X.
ppm X.
SO2-diluent................. 7.5% < RA < =10.0% or RA < =7.5% or < plus-
0.030 minus>0.025 lb/
lb/mmBtu X. mmBtu =G5X.
NOX-diluent................. 7.5% < RA < =10.0% or RA < = 7.5% or < plus-
0.020 minus>0. 015 lb/
lb/mmBtu X. mmBtu X.
Flow........................ 7.5% < RA < = 10.0% RA < = 7.5% or < plus-
or 2.0 minus>1.5 fps X.
fps X.
CO2 or O2................... 7.5% < RA < = 10.0% RA < = 7.5% or < plus-
or 1.0% minus>0.7% CO2/O2X.
CO2/O2 X.
Hg X........................ N/A................. RA < 20.0% or < plus-
minus> 1.0 [mu]g/
scm X.
Moisture.................... 7.5% < RA < =10.0% or RA < =7.5% or < plus-
1.5% minus>1.0% H2O X.
H2O X.
------------------------------------------------------------------------
W The deadline for the next RATA is the end of the second (if
semiannual) or fourth (if annual) successive QA operating quarter
following the quarter in which the CEMS was last tested. Exclude
calendar quarters with fewer than 168 unit operating hours (or, for
common stacks and bypass stacks, exclude quarters with fewer than 168
stack operating hours) in determining the RATA deadline. For SO2
monitors, QA operating quarters in which only very low sulfur fuel as
defined in Sec. 72.2, is combusted may also be excluded. However,
the exclusion of calendar quarters is limited as follows: the deadline
for the next RATA shall be no more than 8 calendar quarters after the
quarter in which a RATA was last performed.
X The difference between monitor and reference method mean values
applies to moisture monitors, CO2, and O2 monitors, low emitters of
SO2, NOX, or Hg, or and low flow, only. The specifications for Hg
monitors also apply to sorbent trap monitoring systems.
Y A NOX concentration monitoring system used to determine NOX mass
emissions under Sec. 75.71.
0
42. Appendix D to Part 75 is amended by:
0
a. Revising section 2.1.5.1;
0
b. Removing all ``'' symbols from paragraph (c) of section
2.1.6.1;
0
c. Revising the Rbase and Lavg variable
definitions in paragraph (a) of section 2.1.7.1;
0
d. Revising the terms ``(GHR) base'' and ``Lavg''
in paragraph (c) of section 2.1.7.1;
0
e. Revising the terms ``Rh'' and ``Lh'' in
paragraph (a) of section 2.1.7.2;
0
f. Revising the terms ``(GHR) h'' and ``Lh'' in
paragraph (c) of section 2.1.7.2;
0
g. Removing ``D4177-82 (Reapproved 1990)'' and adding in its place
``D4177-95 (Reapproved 2000)'', in the first sentence of section 2.2.3;
0
h. Removing ``D4057-88 `Standard Practice for Manual Sampling of
Petroleum and Petroleum Products' (incorporated by reference under
Sec. 75.6)'' and adding in its place, ``ASTM D4057-95 (Reapproved
2000), Standard Practice for Manual Sampling of Petroleum and Petroleum
Products
[[Page 4370]]
(incorporated by reference under Sec. 75.6 of this part)'', in
sections 2.2.4.1 and 2.2.4.2, and in paragraph (c) of section 2.2.4.3;
0
i. Revising sections 2.2.5, 2.2.6, and 2.2.7;
0
j. Revising paragraphs (a)(2) and (e) of section 2.3.1.4;
0
k. Revising section 2.3.3.1.2;
0
l. Revising section 2.3.4;
0
m. Adding two sentences at the end of section 2.3.4.1;
0
n. Revising paragraphs (b)(2) and (c) of section 2.3.7;
0
o. Revising section 3.2.2; and
0
p. Revising section 3.5.1.
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-2004, Measurement of Fluid Flow in Pipes
Using Orifice, Nozzle, and Venturi; ASME MFC-4M-1986 (Reaffirmed
1997), 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-MFC-5M-1985, (Reaffirmed 1994), Measurement of
Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic
Flowmeters; ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes
Using Vortex Flowmeters; ASME MFC-7M-1987 (Reaffirmed 1992),
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 Petroleum Measurement Standards,
Chapter 4--Proving Systems, Section 2--Pipe Provers (Provers
Accumulating at Least 10,000 Pulses), Second Edition, March 2001,
and Section 5--Master-Meter Provers, Second Edition, May 2000;
American Petroleum Institute (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
(all incorporated by reference under Sec. 75.6 of this part). 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.
* * * * *
(c) * * *
Where:
(GHR)base = Baseline value of the gross heat rate during
the baseline period, Btu/kwh, Btu/lb steam load, or 1000mmBtu heat
input/mmBtu thermal output.
* * * * *
Lavg = Average (mean) unit load during the baseline
period, megawatts, 1000 lb/hr of steam, or mmBtu/hr thermal output.
* * * * *
2.1.7.2
(a) * * *
Where:
Rh = Hourly value of the fuel flow rate-to-load ratio;
100 scfh/MWe, (lb/hr)/MWe, 100 scfh/1000 lb/hr of steam load, (lb/
hr)/1000 lb/hr of steam load, 100 scfh/(mmBtu/hr of steam load), or
(lb/hr)/(mmBtu/hr thermal output).
* * * * *
Lh = Hourly unit load, megawatts, 1000 lb/hr of steam, or
mmBtu/hr thermal output.
* * * * *
(c) * * *
Where:
(GHR)h = Hourly value of the gross heat rate, Btu/kwh,
Btu/lb steam load, or mmBtu heat input/mmBtu thermal output.
* * * * *
Lh = Hourly unit load, 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 Wavelength
Dispersive X-ray Fluorescence Spectrometry, ASTM D4294-98, Standard
Test Method for Sulfur in Petroleum and Petroleum Products by
Energy-Dispersive X-ray Fluorescence Spectrometry, or ASTM D5453-06,
Standard Test Method for Determination of Total Sulfur in Light
Hydrocarbons, Spark Ignition Engine Fuel, Diesel Engine Fuel, and
Engine Oil by Ultraviolet Fluorescence (all incorporated by
reference under Sec. 75.6 of this part). Alternatively, the oil
samples may be analyzed for percent sulfur by any consensus standard
method prescribed for the affected unit under part 60 of this
chapter.
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
(Reapproved 2000), Standard Test Method for API Gravity of Crude
Petroleum and Petroleum Products (Hydrometer Method), ASTM D1217-93
(Reapproved 1998), Standard Test Method for Density and Relative
Density (Specific Gravity) of Liquids by Bingham Pycnometer, ASTM
D1481-93 (Reapproved 1997), Standard Test Method for Density and
Relative Density (Specific Gravity) of Viscous Materials by Lipkin
Bicapillary Pycnometer, ASTM D1480-93 (Reapproved 1997), Standard
Test Method for Density and Relative Density (Specific Gravity) of
Viscous Materials by Bingham Pycnometer, ASTM D1298-99, Standard
Test Method for Density, Relative Density (Specific Gravity), or API
Gravity of Crude Petroleum and Liquid Petroleum Products by
Hydrometer Method, or ASTM D4052-96 (Reapproved 2002), Standard Test
Method for Density and Relative Density of Liquids by Digital
Density Meter (all incorporated by reference under Sec. 75.6 of
this part). Alternatively, the oil samples may be analyzed for
density or specific gravity by any consensus standard method
prescribed for the affected unit under part 60 of this chapter.
2.2.7 Analyze oil samples to determine the heat content of the
fuel. Determine oil heat content in accordance with ASTM D240-00,
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 D5865-01a, Standard Test Method for
Gross Calorific Value of Coal and Coke (all incorporated by
reference under Sec. 75.6 of this part) or any other procedures
listed in section 5.5 of appendix F of this part. Alternatively,
[[Page 4371]]
the oil samples may be analyzed for heat content by any consensus
standard method prescribed for the affected unit under part 60 of
this chapter.
* * * * *
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 opt to 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 [gteqt] 98 percent of the 100 (or more) samples have a total
sulfur content of 0.5 grains/100 scf or less and if the GCV or
percent methane requirement is also met; 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 as follows 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 analysis of the
100 (or more) total sulfur samples since the last annual assessment
shows that [gteqt] 98 percent of the samples have a total sulfur
content of 0.5 grains/100 scf or less and if the GCV or percent
methane requirement is also met. 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 D1072-06, Standard Test Method
for Total Sulfur in Fuel Gases by Combustion and Barium Chloride
Titration, ASTM D4468-85 (Reapproved 2006), Standard Test Method for
Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric
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 Liquefied Petroleum Gases by Ultraviolet
Fluorescence, or ASTM D3246-96, Standard Test Method for Sulfur in
Petroleum Gas by Oxidative Microcoulometry, (all incorporated by
reference under Sec. 75.6 of this part). Alternatively, the gas
samples may be analyzed for percent sulfur by any consensus standard
method prescribed for the affected unit under part 60 of this
chapter.
* * * * *
2.3.4 Gross Calorific Values for Gaseous Fuels
Determine the GCV of each gaseous fuel at the frequency
specified in this section, using one of the following methods: ASTM
D1826-94 (Reapproved 1998), ASTM D3588-98, ASTM D4891-89 (Reapproved
2006), GPA Standard 2172-96, Calculation of Gross Heating Value,
Relative Density and Compressibility Factor for Natural Gas Mixtures
from Compositional Analysis, or GPA Standard 2261-00, Analysis for
Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (all
incorporated by reference under Sec. 75.6 of this part). Use the
appropriate GCV value, as specified in section 2.3.4.1, 2.3.4.2, or
2.3.4.3 of this appendix, in the calculation of unit hourly heat
input rates. Alternatively, the gas samples may be analyzed for heat
content by any consensus standard method prescribed for the affected
unit under part 60 of this chapter.
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, apply the monthly
average GCV value as described in paragraph (c) in section 2.3.7 of
this appendix.
* * * * *
2.3.7 * * *
(b) * * *
(2) For natural gas, if only one sample is taken, apply the
results beginning at the date on which the sample was taken. If
multiple samples are taken and averaged, apply the results beginning
at the date on which the last sample used in the annual assessment
was taken;
* * * * *
(c) For monthly samples of the fuel GCV:
(1) If the actual monthly value is to be used in the
calculations and only one sample is taken, apply the results
starting from the date on which the sample was taken. If multiple
samples are taken and averaged, apply the monthly average GCV value
to the entire month; or
(2) If an assumed value (contract maximum or highest value from
previous year's samples) is to be used in the calculations, apply
the assumed value to all hours in each month of the quarter unless a
higher value is obtained in a monthly GCV sample (or, if multiple
samples are taken and averaged, if the monthly average exceeds the
assumed value). In that case, if only one monthly sample is taken,
use the sampled value, starting from the date on which the sample
was taken. If multiple samples are taken and averaged, use the
average value for the entire month in which the assumed value was
exceeded. Consider the sample (or, if applicable, monthly average)
results to be the new assumed value. Continue using the new assumed
value unless and until one of the following occurs (as applicable to
the reporting option selected): The assumed value is superseded by a
higher value from a subsequent monthly sample (or by a higher
monthly average); or the assumed value is superseded by a new
contract in which case the new contract value becomes the assumed
value at the time the fuel specified under the new contract begins
to be combusted in the unit; or both the calendar year in which the
new sampled value (or monthly average) exceeded the assumed value
and the subsequent calendar year have elapsed.
* * * * *
3.2.2 Convert density, specific gravity, or API gravity of the
oil sample to density of the oil sample at the sampling location's
temperature using ASTM D1250-07, Standard Guide for Use of the
Petroleum Measurement Tables (incorporated by reference under (Sec.
75.6 of this part).
* * * * *
3.5.1 Hourly SO2 Mass Emissions from the Combustion
of all Fuels. Determine the total mass emissions for each hour from
the combustion of all fuels using Equation D-12 (On and after
January 1, 2009, determine the total mass emission rate (in lbs/hr)
for each hour from the combustion of all fuels by dividing Equation
D-12 by the actual unit operating time for the hour):
[GRAPHIC] [TIFF OMITTED] TR24JA08.019
Where:
MSO2-hr = Total mass of SO2 emissions from all
fuels combusted during the hour, lb.
SO2 rate-I = SO2 mass emission rate for each
type of gas or oil fuel combusted during the hour, lb/hr.
ti = Time each gas or oil fuel was combusted for the hour (fuel
usage time), fraction of an hour (in equal increments that can
[[Page 4372]]
range from one hundredth to one quarter of an hour, at the option of
the owner or operator).
* * * * *
0
43. Appendix E to part 75 is amended by:
0
a. Adding a new sentence to the end of section 2.1;
0
b. Revising the seventh sentence of section 2.1.2.1;
0
c. Revising sections 2.1.2.2 and 2.1.2.3;
0
d. Removing the phrase ``(MWge or steam load in 1000 lb/hr)'' and
adding in its place the phrase ``(MWge or steam load in 1000 lb/hr, or
mmBtu/hr thermal output)'', in section 2.4.1;
0
e. Revising section 2.5.2; and
0
f. 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.
* * * * *
2.1.2.1 * * * Use a minimum of 12 sample points, located
according to Method 1 in appendix A-1 to part 60 of this chapter.
* * * * *
2.1.2.2 For stationary gas turbines, sample at a minimum of 12
points per run at each load level. Locate the sample points
according to Method 1 in appendix A-1 to part 60 of this chapter.
For each fuel or consistent combination of fuels (and, optionally,
for each combination of fuels), measure the NOX and
O2 concentrations at each sampling point using methods 7E
and 3A in appendices A-4 and A-2 to part 60 of this chapter. For
diesel or dual fuel reciprocating engines, select the sampling site
to be as close as practicable to the exhaust of the engine.
2.1.2.3 Allow the unit to stabilize for a minimum of 15 minutes
(or longer if needed for the NOX and O2
readings to stabilize) prior to commencing NOX,
O2, and heat input measurements. Determine the
measurement system response time according to sections 8.2.5 and
8.2.6 of method 7E in appendix A-4 to part 60 of this chapter. When
inserting the probe into the flue gas for the first sampling point
in each traverse, sample for at least one minute plus twice the
measurement system response time (or longer, if necessary to obtain
a stable reading). For all other sampling points in each traverse,
sample for at least one minute plus the measurement system response
time (or longer, if necessary to obtain a stable reading). Perform
three test runs at each load condition and obtain an arithmetic
average of the runs for each load condition. During each test run on
a boiler, record the boiler excess oxygen level at 5 minute
intervals.
* * * * *
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 appendix.
* * * * *
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.
* * * * *
0
44. Appendix F to Part 75 is amended by:
0
a. Removing the second and third sentences from the introductory text
of section 2;
0
b. Removing the phrase ``method 19 in appendix A of part 60 of this
chapter'' and adding in its place 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;
0
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;
0
d. Removing the second and third sentences from section 3.3.4;
0
e. Adding sections 3.3.4.1 and 3.3.4.2;
0
f. Revising Table 1;
0
g. Revising the text preceding Equation F-7a, in section 3.3.6;
0
h. Revising section 3.3.6.1;
0
i. Revising section 3.3.6.2;
0
j. Revising sections 3.3.6.3 and 3.3.6.4;
0
k. Adding section 3.3.6.5;
0
l. 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;
0
m. Revising section 4.4.1;
0
n. Removing the second and third sentences from the %CO2w
variable definition in 5.2.1;
0
o. Removing the second and third sentences from the %CO2d
variable definition in 5.2.2;
0
p. 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;
0
q. Removing the second and third sentences from the %O2d
variable definition, in section 5.2.4;
0
r. Revising the definition of ``GCVo'' in paragraph (a) of
section 5.5.1;
0
s. Revising the definition of ``GCVg'' in section 5.5.2;
0
t. Revising section 5.5.3.1;
0
u. Revising section 5.5.3.2;
0
v. Removing the phrase ``as measured by ASTM D3176-89, D1989-92, D3286-
91a, or D2015-91, Btu/lb'' and adding in its place the phrase ``as
measured by ASTM D3176-89 (Reapproved 2002), or ASTM D5865-01a, Btu/lb.
(incorporated by reference under Sec. 75.6 of this part).'' in the
definition of the GCVc variable in Equation F-21;
0
w. Removing the word ``lb/hr'' and adding in its place the phrase ``lb/
hr, or mmBtu/hr'' in the definition of the SF variable in Equation F-
21b;
0
x. Revising the heading and text of section 7;
0
y. 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;
0
z. Revising sections 8.1 and 8.1.1;
0
aa. Revising section 8.2;
0
bb. Adding sections 8.2.1 and 8.2.2;
0
cc. Revising section 8.3;
0
dd. Revising section 8.4; and
0
ee. 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.
[[Page 4373]]
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.
* * * * *
Table 1.--F- and Fc-Factors \1\
------------------------------------------------------------------------
F-factor (dscf/ FC-factor (scf
Fuel mmBtu) CO2/mmBtu)
------------------------------------------------------------------------
Coal (as defined by ASTM D388-99
\2\):
Anthracite.................... 10,100 1,970
Bituminous.................... 9,780 1,800
Subbituminous................. 9,820 1,840
Lignite....................... 9,860 1,910
Petroleum Coke.................... 9,830 1,850
Tire Derived Fuel................. 10,260 1,800
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.
\2\ Incorporated by reference under Sec. 75.6 of this part.
* * * * *
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).
* * * * *
3.3.6.1 H, C, S, N, and O are content by weight of hydrogen,
carbon, sulfur, nitrogen, and oxygen (expressed as percent),
respectively, as determined on the same basis as the gross calorific
value (GCV) by ultimate analysis of the fuel combusted using ASTM
D3176-89 (Reapproved 2002), Standard Practice for Ultimate Analysis
of Coal and Coke, (solid fuels), ASTM D5291-02, Standard Test
Methods for Instrumental Determination of Carbon, Hydrogen, and
Nitrogen in Petroleum Products and Lubricants, (liquid fuels) or
computed from results using ASTM D1945-96 (Reapproved 2001),
Standard Test Method for Analysis of Natural Gas by Gas
Chromatography, or ASTM D1946-90 (Reapproved 2006), Standard
Practice for Analysis of Reformed Gas by Gas Chromatography,
(gaseous fuels) as applicable. (All of these methods are
incorporated by reference under Sec. 75.6 of this part.)
3.3.6.2 GCV is the gross calorific value (Btu/lb) of the fuel
combusted determined by ASTM D5865-01a, 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
of Gaseous Fuels, ASTM D4891-89 (Reapproved 2006), Standard Test
Method for Heating Value of Gases in Natural Gas Range by
Stoichiometric Combustion, GPA Standard 2172-96 Calculation of Gross
Heating Value, Relative Density and Compressibility Factor for
Natural Gas Mixtures from Compositional Analysis, GPA Standard 2261-
00 Analysis for Natural Gas and Similar Gaseous Mixtures by Gas
Chromatography, or ASTM D1826-94 (Reapproved 1998), Standard Test
Method for Calorific (Heating) Value of Gases in Natural Gas Range
by Continuous Recording Calorimeter, for gaseous fuels, as
applicable. (All of these methods are incorporated by reference
under Sec. 75.6 of this part).
3.3.6.3 For affected units that combust a combination of a fuel
(or fuels) listed in Table 1 in section 3.3.5 of this appendix with
any fuel(s) not listed in Table 1, the F or Fc value is
subject to the Administrator's approval under Sec. 75.66.
3.3.6.4 For affected units that combust combinations of fuels
listed in Table 1 in section 3.3.5 of this appendix, prorate the F
or Fc factors determined by section 3.3.5 or 3.3.6 of
this appendix in accordance with the applicable formula as follows:
[GRAPHIC] [TIFF OMITTED] TR24JA08.020
Where,
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.
Fi or (Fc)i = Applicable F or Fc
factor for each fuel type determined in accordance with Section
3.3.5 or 3.3.6 of this appendix.
n = Number of fuels being combusted in combination.
3.3.6.5 As an alternative to prorating the F or Fc factor as
described in section 3.3.6.4 of this appendix, a ``worst-case'' F or
Fc factor may be reported for any unit operating hour.
[[Page 4374]]
The worst-case F or Fc factor shall be the highest F or
Fc value for any of the fuels combusted in the unit.
* * * * *
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] TR24JA08.021
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] TR24JA08.022
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.
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-14a or 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 operating hour where Equation F-17 results
in an hourly heat input rate that is < = 0.0 mmBtu/hr, 1.0 mmBtu/hr
shall be recorded and reported as the heat input rate for that hour.
* * * * *
5.5.1 (a) * * *
GCVo = Gross calorific value of oil, as measured by
ASTM D240-00, ASTM D5865-01a, or ASTM D4809-00 for each oil sample
under section 2.2 of appendix D to this part, Btu/unit mass (all
incorporated by reference under (Sec. 75.6 of this part).
* * * * *
5.5.2 * * *
GCVg = Gross calorific value of gaseous fuel, as
determined by sampling (for each delivery for gaseous fuel in lots,
for each daily gas sample for gaseous fuel delivered by pipeline,
for each hourly average for gas measured hourly with a gas
chromatograph, or for each monthly sample of pipeline natural gas,
or as verified by the contractual supplier at least once every month
pipeline natural gas is combusted, as specified in section 2.3 of
appendix D to this part) using ASTM D1826-94 (Reapproved 1998), ASTM
D3588-98, ASTM D4891-89 (Reapproved 2006), GPA Standard 2172-96
Calculation of Gross Heating Value, Relative Density and
Compressibility Factor for Natural Gas Mixtures from Compositional
Analysis, or GPA Standard 2261-00 Analysis for Natural Gas and
Similar Gaseous Mixtures by Gas Chromatography, Btu/100 scf (all
incorporated by reference under Sec. 75.6 of this part).
* * * * *
5.5.3.1 Perform coal sampling daily according to section 5.3.2.2
in Method 19 in appendix A to part 60 of this chapter and use ASTM
D2234-00, Standard Practice for Collection of a Gross Sample of
Coal, (incorporated by reference under Sec. 75.6 of this part) Type
I, Conditions A, B, or C and systematic spacing for sampling. (When
performing coal sampling solely for the purposes of the missing data
procedures in Sec. 75.36, use of ASTM D2234-00 is optional, and
coal samples may be taken weekly.)
5.5.3.2 All ASTM methods are incorporated by reference under
Sec. 75.6 of this part. Use ASTM D2013-01, Standard Practice for
Preparing Coal Samples for Analysis, for preparation of a daily coal
sample and analyze each daily coal sample for gross calorific value
using ASTM D5865-01a, Standard Test Method for Gross Calorific Value
of Coal and Coke. 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] TR24JA08.023
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 own 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] TR24JA08.024
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 in
[[Page 4375]]
appendix A-7 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] TR24JA08.025
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 in appendix A-7 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] TR24JA08.026
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] TR24JA08.027
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.
%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] TR24JA08.028
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] TR24JA08.029
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] TR24JA08.030
[[Page 4376]]
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] TR24JA08.031
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
0
45. Appendix G to Part 75 is amended by:
0
a. Revising section 2.1.2;
0
b. Removing ``D3174-89 `Standard Test Method for Ash in the Analysis
Sample of Coal and Coke From Coal' '' and by adding in its place,
``D3174-00, Standard Test Method for Ash in the Analysis Sample of Coal
and Coke from Coal'' in section 2.2.1; and
0
c. Removing ``D3178-89 (1997), `Standard Test Methods for Carbon and
Hydrogen in the Analysis Sample of Coal and Coke' '' and adding in its
place ``D5373-02 (Reapproved 2007), Standard Test Methods for
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
Laboratory Samples of Coal and Coke'' in section 2.2.2.
The revisions 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 (Reapproved 2002) or ASTM
D5373-02 (Reapproved 2007) for coal; ASTM D5291-02, 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 (Reapproved 2000) and
either ASTM D2502-92 (Reapproved 1996) or ASTM D2503-92 (Reapproved
1997) for oil; and computations based on ASTM D1945-96 (Reapproved
2001) or ASTM D1946-90 (Reapproved 2006) for gas (all incorporated
by reference under Sec. 75.6 of this part).
* * * * *
0
46. Appendix K to Part 75 is amended by:
0
a. Removing the words ``(see Sec. Sec. 75.11(b) and 75.12(b))'' and
adding in its place the words ``(see Sec. 75.11(b))'' in section 5;
0
b. Adding a sentence to the end of section 7.2.3;
0
c. Removing the words ``or Sec. 75.12(b)'' and ``or Sec. 75.12,''
from section 7.2.4;
0
d. Revising Table K-1 of section 8; and
0
e. Adding the words ``or in Table K-1'' following the words ``Sec.
75.15(h)'' in the second sentence of section 11.8.
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.
* * * * *
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 leak
check is passed.
Post-test leak check............. < =4% of average sampling After sampling.......... ** See Note, below.
rate.
Ratio of stack gas flow rate to No more than 5% of the Every hour throughout ** See Note, below.
sample flow rate. hourly ratios or 5 data collection period.
hourly ratios (whichever
is less restrictive) may
deviate from the
reference ratio by more
than 25%.
Sorbent trap section 2 break- < =5% of Section 1 Hg mass Every sample............ ** See Note, below.
through.
Paired sorbent trap agreement.... < =10% Relative Deviation Every sample............ Either invalidate the
(RD) if the average data from the paired
concentration is > 1.0 traps or report the
[mu]g/m\3\. results from the trap
< = 20% RD if the average with the higher Hg
concentration is < = 1.0 concentration.
[mu]g/m\3\.
Results are also
acceptable if absolute
difference between
concentrations from
paired traps is < = 0.03
[mu]g/m\3\.
Spike Recovery Study............. Average recovery between Prior to analyzing field Field samples shall not
85% and 115% for each of samples and prior to be analyzed until the
the 3 spike use of new sorbent percent recovery
concentration levels. media. criteria has been met
Multipoint analyzer calibration.. Each analyzer reading On the day of analysis, Recalibrate until
within 10% before analyzing any successful.
of true value and r\2\ samples.
>= 0.99.
[[Page 4377]]
Analysis of independent Within 10% Following daily Recalibrate and repeat
calibration standard. of true value. calibration, prior to independent standard
analyzing field samples. analysis until
successful.
Spike recovery from section 3 of 75-125% of spike amount.. Every sample............ ** See Note, below.
sorbent trap.
RATA............................. RA < = 20.0% or Mean For initial Data from the system are
difference < = 1.0 [mu]g/ certification and invalidated until a
dscm for low emitters. annually thereafter. RATA is passed.
Gas flow meter calibration....... Calibration factor (Y) At three settings prior Recalibrate the meter at
within 5% to initial use and at three orifice settings
of average value from least quarterly at one to determine a new
the most recent 3-point setting thereafter. For value of Y.
calibration. mass flow meters,
initial calibration
with stack gas is
required.
Temperature sensor calibration... Absolute temperature Prior to initial use and Recalibrate. Sensor may
measured by sensor at least quarterly not be used until
within 1.5% thereafter. specification is met.
of a reference sensor.
Barometer calibration............ Absolute pressure Prior to initial use and Recalibrate. Instrument
measured by instrument at least quarterly may not be used until
within 10 thereafter. specification is met.
mm Hg of reading with a
mercury barometer.
----------------------------------------------------------------------------------------------------------------
** Note: If both traps fail to meet the acceptance criteria, the data from the pair of traps are invalidated.
However, if only one of the paired traps fails to meet this particular acceptance criterion and the other
sample meets all of the applicable QA criteria, the results of the valid trap may be used for reporting under
this part, provided that the measured Hg concentration is multiplied by a factor of 1.111. When the data from
both traps are invalidated and quality-assured data from a certified backup monitoring system, reference
method, or approved alternative monitoring system are unavailable, missing data substitution must be used.
* * * * *
[FR Doc. E7-25071 Filed 1-23-08; 8:45 am]
BILLING CODE 6560-50-P