[Federal Register Volume 64, Number 101 (Wednesday, May 26, 1999)]
[Rules and Regulations]
[Pages 28564-28672]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 99-8939]
[[Page 28563]]
_______________________________________________________________________
Part II
Environmental Protection Agency
_______________________________________________________________________
40 CFR Parts 72 and 75
Acid Rain Program; Continuous Emission Monitoring Rule Revisions; Final
Rule
Federal Register / Vol. 64, No. 101 / Wednesday, May 26, 1999 / Rules
and Regulations
[[Page 28564]]
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 72 and 75
[FRL-6320-8]
RIN 2060-AG46
Acid Rain Program; Continuous Emission Monitoring Rule Revisions
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: Title IV of the Clean Air Act (CAA or the Act), as amended by
the Clean Air Act Amendments of 1990, authorizes the Environmental
Protection Agency (EPA or Agency) to establish the Acid Rain Program.
The Acid Rain Program and the provisions in this final rule benefit the
environment by ensuring that the sulfur dioxide (SO2),
nitrogen oxides (NOX) and carbon dioxide (CO2)
air pollution emissions to be measured and tracked pursuant to the
provisions of 40 CFR part 75 are accurately monitored and reported.
These provisions also benefit the regulated entities by providing
additional flexibility and improved cost effectiveness to the
monitoring and reporting options available to part 75 subject sources.
On January 11, 1993, the Agency promulgated final rules, including the
final continuous emission monitoring (CEM) rule, under title IV. On May
17, 1995 and November 20, 1996, the Agency revised the CEM rule to make
the implementation simpler. On May 21, 1998, the Agency proposed
additional revisions to the CEM rule, to make implementation easier and
more efficient for both EPA and the facilities affected by the rule, to
improve quality assurance requirements, and to create new alternative
monitoring options. EPA promulgated final rule revisions addressing
some of these additional proposed revisions, based on comments
received, when EPA promulgated a Finding of Significant Contribution
and Rulemaking for Certain States in the Ozone Transport Assessment
Group Region for Purposes of Reducing Regional Transport of Ozone
(NOX SIP call).
In this action, EPA is issuing final rule revisions addressing the
remaining May 21, 1998 proposed revisions to the CEM rule, with certain
changes to the proposal based on the public comments received. Some of
these revisions will be relevant for sources that become subject to
part 75 requirements in response to the NOX SIP call.
DATES: The effective date of this rule is June 25, 1999. The
incorporation by reference of certain publications listed in the
regulations is approved by the Director of the Federal Register as of
June 25, 1999.
ADDRESSES: Docket. Supporting information used in developing the
regulations is contained in Docket No. A-97-35. This docket is
available for public inspection and photocopying between 8:00 a.m. and
5:30 p.m. Monday through Friday, excluding government holidays and is
located at: EPA Air Docket (MC 6102) , Room M-1500, Waterside Mall, 401
M Street, SW, Washington, DC 20460. A reasonable fee may be charged for
photocopying.
FOR FURTHER INFORMATION CONTACT: Monika Chandra, Acid Rain Division
(6204J), U.S. Environmental Protection Agency, 401 M Street, SW,
Washington, DC 20460, (202) 564-9781.
SUPPLEMENTARY INFORMATION: The contents of the preamble are listed in
the following outline:
I. Regulated Entities
II. Background and Summary of Final Rule
III. Summary of Major Comments and Responses
A. Certification/Recertification Procedural Changes
B. Quality Assurance Requirements for Quantifying Stack Gas
Moisture Content
C. Percent Monitor Availability
D. Span and Range Requirements
E. Flow-to-Load Ratio Test Requirements
F. RATA and Bias Test Requirements
1. RATA Load Levels
2. Single Point Reference Method Sampling
G. Data Validation
1. Data Validation During Monitor Certification and
Recertification
2. Data Validation for RATAs and Linearity Checks
H. Appendix D--Sulfur Dioxide Emissions from the Combustion of
Gaseous Fuels
1. Summary of EPA Analysis of Appendix D Gaseous Fuel
SO2 and Heat Input Methodologies
2. Changes to the Definitions of ``Pipeline Natural Gas'' and
``Natural Gas''
3. Changes to the Methodology for Calculating SO2
Emissions Under Appendix D
4. Changes to the Applicability of Appendix D
5. Changes to the Method of Determining the Sulfur Content
Sampling Frequency for Gaseous Fuels
6. Changes to the Method of Determining the GCV Sampling
Frequency for Gaseous Fuels
I. Electronic Transfer of Quarterly Reports
J. Bias, Relative Accuracy and Availability Determinations
K. Appendix I--Proposed Optional Stack Flow Monitoring
Methodology
L. Subpart H--Clarifications to NOX Mass Monitoring
Requirements
IV. Administrative Requirements
A. Public Docket
B. Executive Order 12866
C. Unfunded Mandates Reform Act
D. Executive Order 12875
E. Executive Order 13084
F. Paperwork Reduction Act
G. Regulatory Flexibility
H. Submission to Congress and the General Accounting Office
I. Executive Order 13045
J. National Technology Transfer and Advancement Act
I. Regulated Entities
Entities regulated by this action are fossil fuel-fired boilers and
turbines that serve generators producing electricity, generate steam,
or cogenerate electricity and steam. While part 75 primarily regulates
the electric utility industry, the recent promulgation of 40 CFR part
96 and certain revisions to part 75 (see 63 FR 57356, October 27, 1998)
means that part 75 could potentially affect other industries. The
recent adoption of part 96, together with revisions to part 75, include
nitrogen oxides (NOX) mass provisions for the purpose of
serving as a model which could be adopted by a state, tribal, or
federal NOX mass reduction program covering the electric
utility and other industries. Regulated categories and entities
include:
------------------------------------------------------------------------
Examples of regulated
Category entities
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Industry.................................. Electric service providers,
boilers, turbines and other
process sources where
emissions exhaust through a
stack.
------------------------------------------------------------------------
This table is not intended to be exhaustive, but rather provides 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 the 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 Secs. 72.6, 72.7, 72.8, and part 96 of title 40 of the Code of
Federal Regulations. 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 of this preamble.
II. Background and Summary of Final Rule
Title IV of the Act requires EPA to establish an Acid Rain Program
to reduce the adverse effects of acidic deposition. On January 11,
1993, the
[[Page 28565]]
Agency promulgated final rules implementing the program, including the
CEM rule (58 FR 3590). Notices of direct final rulemaking and of
interim final rulemaking further amending the regulations were
published on May 17, 1995 (60 FR 26510 and 60 FR 26560). Subsequently,
on November 20, 1996, a final rule was published in response to public
comments received on the direct final and interim rules (61 FR 59142).
On May 21, 1998, the Agency published proposed revisions to the part 75
CEM regulations (62 FR 28032). As noted above, EPA recently promulgated
final revisions to part 75 addressing some of the May 21, 1998,
proposed revisions in conjunction with the promulgation of a Model
NOX Trading Rule in part 96 and the NOX SIP call
(see 63 FR 57356).
Today's action adopts final part 75 revisions to address the
remaining May 21, 1998, proposed revisions and to make minor technical
corrections to the part 75 provisions promulgated in conjunction with
part 96 and the NOX SIP Call. The final revisions involve
the following matters: (1) revised definitions of gas-fired, oil-fired,
and peaking unit to allow for changes in unit fuel usage and/or
operation; (2) a minor wording correction to the applicability
provisions in part 72; (3) new quality assurance/quality control (QA/
QC) requirements for quantifying stack gas moisture content; (4)
clarifying changes to the certification and recertification process;
(5) substitute data requirements for carbon dioxide (CO2),
heat input and moisture; (6) clarifying revisions to the petition
provisions for alternatives to part 75 requirements; (7) clarifying
changes to span and range requirements; (8) clarifying revisions to
general QA/QC requirements; (9) calibration error test requirements;
(10) linearity test requirements; (11) a new flow-to-load QA test for
flow monitors; (12) reductions in and/or clarifications to the relative
accuracy test audit (RATA) and bias test requirements; (13) clarifying
revisions to the procedures for CEM data validation; (14) clarifying
revisions to the sulfur dioxide (SO2) emissions data
protocol for gas-fired and oil-fired units (Appendix D); (15)
determination of CO2 emissions under Appendix G; (16)
recordkeeping and reporting changes to reflect the proposed revisions;
(17) a revised traceability protocol for calibration gases (Appendix
H); and (18) NOX mass emission recordkeeping and reporting
provisions, and minor revisions to NOX mass monitoring
requirements.
Many of these changes are minor technical revisions based on
comments received from facilities following the initial implementation
of part 75. Based on experience gained in the early years of the
program, facilities have developed a number of suggestions that will
simplify and streamline the monitoring process without sacrificing data
quality. The Agency has also amended quality assurance requirements
based on gaps identified by EPA during evaluation of the initial
implementation of part 75. Finally, several minor technical changes
have been made in order to maintain uniformity within the rule itself
and to clarify various provisions.
III. Summary of Major Comments and Responses
A. Certification/Recertification Procedural Changes
Background: EPA proposed to revise the recertification application
review period in Sec. 75.20(b)(5) from 60 days to 120 days, which is
the same review period as for the initial certification application.
The Agency believes that this will reduce confusion, simplify
certification/recertification application tracking, and will result in
the more efficient allocation of resources by local, state, and federal
agencies. Therefore, EPA has adopted this change in the final rule with
certain modifications in response to issues raised by commenters.
Discussion: Two states responded positively to the proposed change.
One state commented that the increased review time ``will allow more
effective use of staff resources and provide ample time for a thorough
review of the data submitted in the application'' (see Docket A-97-35,
Item IV-D-6). Another state commenter remarked that extending the
review period ``adds uniformity and consistency to the certification
and recertification process. This change is positive, and it allows the
state agencies the time to resolve minor deficiencies which may
otherwise serve as grounds to recommend disapproval. Based on
experience, the 120 day period is absolutely essential for the review
of certification/recertification applications'' (see Docket A-97-35,
Item IV-D-9).
Several commenters suggested that if EPA disapproved a
recertification application after the 120 day period, data recorded
during the entire 120 day period would become invalid and the use of
substitute data would be required (see Docket A-97-35, Items IV-D-17,
IV-D-20 and IV-D-24). However, as EPA stated in the preamble to the
proposal, ``less than 2 percent of all monitoring system applications
submitted between 1992 and September 1997 were disapproved'' (63 FR
28045, citing Docket A-97-35, Item II-A-4). As experience with the
program increases, the number of disapprovals is expected to decrease
even further. In addition, EPA's position is that the owners or
operators of affected facilities are responsible for initiating,
conducting, evaluating and certifying the results of the required
testing prior to submission to the appropriate regulatory Agencies. The
Agencies' role is to ``certify'' or verify the results. Thus, there is
no reason to expect that the additional time provided to meet the
administrative needs of the program will result in any significant
compliance risk to the regulated sources, except in instances where
insufficient care is taken to ensure proper conduct of the testing.
Two commenters stated that the owner or operator would be in
violation of the requirements of proposed Sec. 75.33(d) and
Sec. 75.10(a) if a recertification application were disapproved after
120 days (see Docket A-97-35, Items IV-D17 and IV-D-23) because the
percent monitor availability would be below 80%. These proposed
penalties have been withdrawn from the final rule in response to
comments received. Today's final rule does not treat a percent monitor
data availability of less than 80% as a violation. Instead, the final
rule provides that if percent monitor data availability is less than
80%, then the appropriate maximum value (e.g., maximum potential
concentration) or, in some cases, the appropriate minimum potential
value will be used to provide substitute data (see Section C of this
preamble for a further discussion of these provisions).
Several commenters suggested that since the review of the initial
certification applications for the Acid Rain Phase I and Phase II units
has been completed, the burden on the states and EPA has been removed .
Therefore, it should not take EPA 120 days to review recertification
applications (see Docket A-97-35, Items IV-D-14, IV-D-20, and IV-D-24).
This argument would be more compelling if the Acid Rain Program were
the only program that the various regulatory agencies are required to
implement. However, EPA and the States are currently responsible for
implementing several other programs that require comprehensive
administrative review of various types of applications and petitions
(e.g., Compliance Assurance Monitoring (CAM), the OTC NOX
Budget Program, the PSD program and Title V permitting). EPA also
anticipates that the NOX SIP call will further increase the
number of certification and recertification applications and
[[Page 28566]]
petitions that need to be reviewed by the regulatory agencies.
Many recertifications require the same tests as for initial
certification. Therefore, recertification applications often take as
much effort to review as certification applications. It is also
sometimes difficult to distinguish a recertification application
package from an initial certification application package, which can
complicate tracking the two types of applications if they have
different review periods. The recertification process usually requires
that a state or local program perform the initial review and forward
the results to the EPA regional office which will then make a
recommendation to EPA headquarters on whether to approve or disapprove
the application. This requires a significant amount of time and does
not allow much time to coordinate with the source to get additional
information, when needed. There is more likelihood of a disapproval
being issued under a short time frame. Finally, EPA notes that it does
not have control over the number of recertification applications that
are submitted. Individual utility choices, changes in rules, market
conditions, and technology all influence the number of
recertifications. Therefore, EPA has concluded that extending the
application review period from 60 to 120 days is both necessary and
appropriate.
B. Quality Assurance Requirements for Quantifying Stack Gas Moisture
Content
Background: Section 75.11(b) of the January 11, 1993 Acid Rain rule
requires the owner or operator to continuously (or on an hourly basis)
account for the moisture content of the stack gas when SO2
concentration is measured on a dry basis. The moisture content is
needed to correct the measured hourly stack gas volumetric flow rates
to a dry basis when calculating SO2 mass emission rates in
lb/hr. Section 75.13(a) of the rule, as amended on May 17, 1995,
contains provisions for CO2 monitoring paralleling the
provisions of Sec. 75.11(b); that is, when CO2 concentration
is measured on a dry basis, a correction for stack gas moisture content
is needed to accurately determine the CO2 mass emissions.
The stack gas moisture content is also needed when a dry-basis
O2 monitor is used to account for CO2 emissions
and, in some instances, when accounting for unit heat input or when
determining NOX emission rate in lb/mmBtu.
As presently codified, part 75 does not specify any quality
assurance requirements for moisture measurement devices. Approximately
5 to 10 percent of the continuous emission monitors in the Acid Rain
Program require moisture corrections to accurately measure
SO2, CO2, or NOX emissions or heat
input (see Docket A-97-35, Item II-I-6 ). The accuracy of the stack gas
moisture measurements directly affects the accuracy of the reported
SO2 mass emission rates, CO2 mass emission rates,
NOX emission rates and heat input values. An error of 1.0
percent H2O in measured moisture content causes a 1.0
percent error in the reported emission rate or heat input value.
Failure to quality assure the moisture data can therefore result in
significant under-reporting of SO2, CO2, and
NOX emissions and heat input.
In the May 21, 1998 proposed rule, EPA set forth quality assurance
procedures that would apply to moisture monitoring systems because the
Agency believes that when moisture corrections must be applied,
continuous, quality assured, direct measurement of the stack gas
moisture content or continuous measurement of surrogate parameters for
moisture, such as wet-and dry-basis oxygen concentrations, is the best
way to ensure the accuracy of the reported emission data. The proposed
rule specified that a moisture monitoring system could consist of
either: (1) a continuous moisture sensor; (2) an oxygen (O2)
analyzer (or analyzers) capable of measuring O2 on both a
wet basis and on a dry basis; or (3) a system consisting of a
temperature sensor and a certified data acquisition and handling system
(DAHS) component capable of determining moisture from a lookup table,
i.e., a psychometric chart (this third option would apply only to
saturated gas streams following wet scrubbers).
The proposed rule included requirements for the initial
certification of moisture monitoring systems. For continuous moisture
sensors, a 7-day calibration error test and a relative accuracy test
audit (RATA) would be required. For moisture monitoring systems
consisting of one or more wet-and dry-basis oxygen analyzers, the
proposed requirements included a 7-day calibration error test, a
linearity test and a cycle time test of each O2 analyzer,
and a RATA of the moisture measurement system. For the lookup table
option (saturated streams, only), the certification requirement would
consist of a DAHS verification. The proposed rule specified that owners
or operators would have to complete all moisture monitoring system
certification tests no later than January 1, 2000.
The proposed rule contained performance specifications for moisture
monitoring systems. These specifications would apply to continuous
moisture sensors and to wet-and dry-basis oxygen analyzers. For
moisture monitoring systems consisting of wet-and dry-basis
O2 analyzers, the proposed span values and performance
specifications for calibration error, linearity, and cycle time would
be the same as the current specifications for O2 monitors.
For moisture sensors, a calibration error specification of 3.0% of span
was proposed. The proposed relative accuracy (RA) specification for all
moisture monitoring systems would be 10.0 percent. An alternative RA
specification was also proposed, i.e., the RA test results would be
considered acceptable if the mean difference of the reference method
measurements and the moisture monitoring system measurements is within
1.0 percent H2O.
On-going QA requirements for moisture monitoring systems were also
proposed. Appendix B would be revised to require daily calibrations of
moisture monitoring systems, quarterly linearity checks of wet-and dry-
basis oxygen analyzer(s), and semiannual RATAs of moisture monitoring
systems. Any moisture monitoring system achieving a relative accuracy
of 7.5 percent or a mean difference between the CEMS and
reference method values within 0.7 percent H2O,
would qualify for an annual, rather than semiannual RATA frequency.
Missing data procedures for moisture were included in the proposed
rule in a new section, Sec. 75.37. Provided that the moisture data
availability is high (90.0 percent), the average of the
``hour before'' and ``hour after'' moisture values would be used for
each hour of the missing data period. When the percent data
availability drops below 90.0 percent, 0.0 percent moisture would be
substituted for each hour of the missing data period.
Finally, the proposed rule specified that records must be kept for
the moisture monitoring systems, including hourly average moisture
readings, percent data availability, and records of all calibration
error tests, linearity tests and relative accuracy test audits.
Today's final rule provides a number of options by which owners or
operators of affected sources may account for the stack gas moisture
content on an hourly basis. The rule also includes quality assurance
provisions for moisture monitoring systems. Today's rule differs from
the proposed rule as follows: (1) the alternate specification in terms
of the mean difference has been increased
[[Page 28567]]
from 1.0 to 1.5% H2O, but the
principal relative accuracy specification for moisture monitoring
systems has been promulgated as proposed, at 10.0 percent; (2) the
daily calibration requirement for continuous moisture sensors has been
withdrawn; (3) the use of the lookup table option has been expanded to
include any demonstrably saturated gas stream, rather than limiting it
to gas streams following wet scrubbers; (4) a site-specific coefficient
or constant (``K'' factor), determined at the time of the RATA, may be
used to calibrate the moisture monitoring system with respect to EPA
Reference Method 4; and (5) in lieu of continuously monitoring the
stack gas moisture content, a conservative, fuel-specific default
moisture percentage may be reported for each unit operating hour (for
coal and wood, only).
Discussion: Two state agencies agreed with EPA that there is a need
for quality assurance of moisture monitoring systems (see Docket A-97-
35, Items IV-D-06 and IV-D-09). A third state agency disagreed with the
proposed QA/QC for the moisture monitors, contending that the proposed
amendments provide no added benefit in terms of data quality (see
Docket A-97-35, Item IV-D-11). That same state agency objected to
quality assuring a ``sub-channel'' parameter such as moisture, claiming
that it is inconsistent with the way EPA quality assures other combined
monitoring systems (such as a NOX-diluent system). The
commenter expressed confidence that existing daily, quarterly,
semiannual and annual QA/QC on the gas and flow rate monitors is
sufficient to ensure data quality, and that if the CEMS moisture value
is significantly in error, RATA limits would probably not be met. EPA
notes, however, that the commenter provided no data to demonstrate that
this is true. The Agency also does not agree with the commenter's
characterization of moisture as a ``sub-channel'' parameter. The
attempt to draw an analogy between moisture monitoring and the
NOX-diluent monitoring system is inappropriate. Under part
75, the moisture measurement system is a separate entity and should be
quality-assured as such. The moisture monitor is not a component of any
``combined'' monitoring system. The only true combined monitoring
systems under part 75 are the NOX-diluent and
SO2-diluent monitoring systems, for which the relative
accuracy is determined on a combined basis, in lb/mmBtu (i.e., the
individual relative accuracies of the pollutant and diluent component
monitors are not determined).
Several commenters indicated that they do not believe that a
moisture monitoring system can meet the proposed relative accuracy (RA)
specifications of 10.0% for a semiannual RATA frequency or 7.5% for an
annual RATA frequency. One commenter expressed the opinion that the RA
for a moisture monitoring system should be 15.0% (see Docket A-97-35,
Item IV-G-04). Another commenter suggested that the principal RA
specification should be 10% 15% for a semiannual RATA
frequency and RA 10% for an annual RATA frequency, and that
the alternate RA specification, in terms of the mean difference, should
be 2.0% H2O for a semiannual frequency and
1.5% for an annual RATA frequency (see Docket A-97-35,
Item IV-D-23). Another commenter noted that even slight drift in
measurements can result in significant errors in the moisture
measurements (see Docket A-97-35, Item IV-D-20). One commenter
requested that EPA consider the following alternatives to the proposed
QA/QC requirements for moisture monitors: (1) eliminate the moisture RA
requirement; (2) for wet and dry oxygen analyzers, allow relative
accuracy testing of the oxygen analyzer(s) rather than requiring a RATA
of the moisture system; (3) allow the use of a default value for
moisture, in lieu of monitoring moisture continuously; or (4) subtract
the absolute value of the average moisture values generated by the
moisture monitoring system from the average reference method value at
the time of a RATA and use the difference to correct all subsequent
moisture data until the next RATA (see Docket A-97-35, Item IV-D-02).
Only one set of data was submitted by the commenters for a moisture
monitoring system RATA. The data set indicated that the moisture
monitoring system, which consisted of wet and dry-basis oxygen
analyzers, could achieve an RA of 16.5% (see Docket A-97-35, Item, IV-
D-02). Note, however, that when the moisture monitoring system data and
the reference method data were compared, the moisture monitoring system
consistently indicated a moisture value that was approximately 3%
H2O higher than the reference method, with a confidence
coefficient of 0.507. The low confidence coefficient indicates that the
moisture monitoring system readings were consistently biased high with
respect to the reference method. Therefore, it appears that a suitable
coefficient or constant (``K'' factor) could be applied to the moisture
system readings, to make the moisture monitoring system readings agree
with the reference method. In this case, subtracting 3% moisture from
the average moisture monitoring system values for each run caused the
relative accuracy to drop from 16.5% to 2.4%, which is well below the
proposed 10.0% semiannual and 7.5% annual RA specifications. For the
alternate RA specification, after applying the 3% moisture correction,
the mean difference was essentially zero, which is also well below the
value of 1.0% moisture proposed for a semiannual RATA frequency and the
value of 0.7% moisture proposed for an annual RATA frequency. This
``K'' factor approach, which was suggested by one of the commenters,
has a precedent in the Acid Rain Program. Nearly all flow monitors must
be calibrated to match the EPA reference method (i.e., Method 2), by
using either a constant or a polynomial equation with multiple
coefficients. Section 6.5.7 of Appendix A of today's rule allows such
``K'' factors to be developed for moisture monitoring systems. The
``K'' value, which would be established at the time of the semiannual
or annual RATA, would be programmed into the DAHS and applied to the
subsequent moisture data. Sections 75.56 (a)(5)(ix) and 75.59
(a)(5)(vii) of today's rule require the owner or operator to keep
records on-site, indicating the current value of the coefficient or
``K'' factor and the date on which it began to be used. The rule
further requires a RATA of the moisture monitoring system whenever the
coefficient or ``K'' factor is changed.
Relative accuracy specifications of 10.0% (for semiannual RATA
frequency) and 7.5% (for annual RATA frequency) for moisture monitoring
systems have been promulgated in today's rule, as proposed. The
alternate RA specifications of 1.0% H2O (for
semiannual RATA frequency) and
0.7% H2O (for annual RATA frequency) have been
increased, respectively, to
1.5% H2O and 1.0% H2O.
In view of EPA's decision to allow the use of site-specific ``K''
factors for moisture monitoring systems, the Agency believes that
affected utilities will be able to meet these RA specifications.
The proposed rule set forth a missing data procedure for moisture
monitoring systems. Two commenters expressed concern regarding the
establishment of such a ``conservative'' missing data procedure (see
Docket A-97-35, Items IV-D-11 and IV-D-20). One of these commenters
further stated that there are insufficient data to know what
availability can reasonably be expected from moisture monitoring
systems,
[[Page 28568]]
especially in view of the proposed moisture QA/QC specifications. After
careful consideration, the Agency agrees with the commenter and, in
response, the final rule adopts the missing data procedures in
Sec. 75.37 that are less conservative than the procedures in the
proposed rule and that more closely resemble the standard missing data
procedures for SO2, NOX, and flow, as recommended
by the commenters. The moisture missing data algorithm is modeled after
the standard SO2 missing data algorithm in Sec. 75.33(b).
This is consistent with the provisions in Secs. 75.35 and 75.36 of
today's rule, which adopt this algorithm for CO2 and heat
input missing data. However, in finalizing the moisture missing data
provisions, it became evident that a single mathematical algorithm is
not adequate to cover all of the part 75 emission rate and heat input
equations that require moisture corrections. In most of the equations,
the lower moisture values are more conservative, and an ``inverted''
SO2 missing data algorithm is appropriate (for further
discussion of the ``inverted'' algorithm, see section C of this
preamble, below). However, there are certain emission rate equations
for which the opposite is true (i.e., the higher moisture values are
more conservative and the regular SO2 missing data algorithm
is appropriate). The specific equations for which the regular
SO2 algorithm applies are Equations F-3, F-4 and F-8 in
Method 19 in Appendix A of 40 CFR 60. Provided that all of the
moisture-corrected emission and heat input equations used by an
affected facility employ the same moisture missing data algorithm
(regular or inverted), it is a simple matter to substitute for missing
moisture data. However, when two or more equations require different
moisture algorithms, an alternative way of addressing missing moisture
data is needed. EPA believes that this situation will rarely be
encountered (at present, the Agency's records indicate that there are
only two such affected units in the Acid Rain Program). Therefore,
Sec. 75.37(d) of today's rule requires the owner or operator of such
units to petition the Administrator under Sec. 75.66(l), for an
alternative moisture missing data procedure.
Finally, several commenters requested that EPA allow the use of a
default moisture value in lieu of the required moisture monitoring (see
Docket A-97-35, Items IV-D-11, IV-D-02 and IV-D-23). The Agency has
performed a moisture data analysis for various fuels (see Docket A-97-
35, Item IV-A-2) and, based on the results, has provided fuel-specific
default values for moisture in today's rule (for coal and wood, only),
which may be reported for each unit operating hour, as an alternative
to operating and maintaining a continuous moisture monitoring system.
The default values are found in Secs. 75.11(b)(1) and 75.12(b) of
today's rule. Note that two sets of default values appear in the rule
to address the variability in format among the equations used for
determining pollutant emissions and heat input (as discussed in the
previous paragraph). The lower default values in Sec. 75.11(b)(1) apply
to Equations F-2, F-14b, F-16, F-17 and F-18 in Appendix F of part 75
and to Equations 19-5 and 19-9 in EPA Method 19 in Appendix A of 40 CFR
60. The higher default values in Sec. 75.12(b) apply when Equation 19-
3, 19-4 or 19-8 in EPA Method 19 in Appendix A of 40 CFR 60 is used to
determine the NOX emission rate. The default values were
determined as follows. The moisture percentage values (which included
both ultimate moisture and free moisture) for each fuel type were taken
from the appropriate tables in Docket Item IV-A-2, cited above. The
moisture values were then ranked from the lowest percentage value to
the highest percentage value, and the 10th percentile value was
selected for the ``low'' default value and the 90th percentile value
was selected for the ``high'' default value. Each default moisture
percentage was rounded to the nearest whole number.
C. Percent Monitor Availability
Background: EPA proposed that if the annual monitor data
availability dropped below 80% for SO2, NOX, flow
rate or CO2, this would violate the primary measurement
requirement of Sec. 75.10(a). In response to comments, today's final
rule does not treat a percent monitor data availability of less than
80% as a violation. Instead, the final rule provides that if percent
monitor data availability is less than 80%, then the appropriate
maximum value (i.e., maximum potential concentration (MPC) for
SO2 and CO2, maximum potential emission rate
(MER) for NOX and maximum potential flow rate for flow) will
have to be used as substitute data for any hour for which valid data is
not available. For O2, the minimum potential concentration
will be used to provide substitute data. For moisture, consistent with
the discussion in section B of this preamble, the minimum potential
moisture percentage will be used in most instances to provide
substitute data; however, for certain emission rate equations, the
maximum potential moisture percentage must be used.
Discussion: EPA received one comment that supported making a
percent monitor availability of less than 80% a violation (see Docket
A-97-35, Item IV-D-11) and another commenter favored the provision that
if percent monitor availability is below 80% due to ``unforseen events
beyond our control,'' this would be taken into consideration (see
Docket A-97-35, Item IV-G-9). EPA also received comments objecting to
making a percent monitor data availability of less than 80% a violation
and suggesting that EPA should modify the standard missing data
algorithms for SO2, NOX and flow rate to require
the use of a maximum substitute data value when monitor availability
drops below 80 percent (see Docket A-97-35, Items IV-D-17, IV-D-19, IV-
D-23, IV-D-24). In response to the comments, the final rule does not
make percent monitor availability of less than 80% a violation and
instead provides that if percent monitor data availability at a source
is less than 80%, then the owner or operator of the source will have to
substitute the appropriate maximum value (i.e., MPC for SO2
and CO2, MER for NOX emission rate and maximum
potential flow rate for flow) as suggested by the commenters. Note that
for O2 and, in most cases, for moisture, minimum potential
values will be substituted rather than maximum values, since the lower
values of these parameters are more conservative. However, if Equation
19-3, 19-4 or 19-8 in EPA Method 19 in Appendix A of 40 CFR 60 is used
to determine NOX emission rate, higher moisture values are
more conservative and the maximum potential moisture percentage will be
used to provide substitute data.
The missing data approach set forth in today's rule to address low
monitor data availability retains the basic design of the part 75
program and appropriately addresses the need for accountability from
sources that are inadequately maintaining their monitoring systems. The
Agency maintains that this provides a strong incentive to achieve at
least 80% monitor availability. Unlike the proposed approach of
considering sources to be in violation, the substitute data approach
adopted today creates this incentive while rendering unnecessary the
task of determining and evaluating the reason(s) for low monitor data
availability.
D. Span and Range Requirements
Background: The span of a CEMS provides an estimate of the highest
expected value for the parameter being
[[Page 28569]]
measured by the CEMS. For instance, the span value of an SO2
monitor is an approximation of the highest SO2 concentration
likely to be recorded by the CEMS during operation of the affected
unit. The range of a CEMS is the full-scale setting of the instrument.
Under part 75, the range of a monitor must be equal to or greater than
the span value. Section 2.1 of Appendix A further specifies that the
range must be chosen such that the majority of the readings during
normal operation fall between 25.0 and 75.0 percent of full-scale. The
span value is important because the reference gas concentrations and
signals used for daily calibration of the CEMS are expressed as
percentages of the span value. The allowable daily calibration error
for a CEMS is also expressed as a percentage of span.
Sections 2.1.1 through 2.1.4 of Appendix A of the January 11, 1993
rule specified procedures for determining the span values for
SO2, NOX, diluent gas (O2 or
CO2), and volumetric flow rate. For SO2, the
``maximum potential concentration'' (MPC) was first calculated based on
fuel sampling. The MPC values for NOX were specified in the
rule and were based on the type of fuel being combusted. The
SO2 and NOX span values were then determined by
multiplying the MPC by 1.25. For CO2 and O2, a
span value of 20.0 percent CO2 or O2 was required
for all diluent monitors. For flow rate, the ``maximum potential
velocity'' (MPV) was first determined. Then, the span value was
obtained by multiplying the MPV by 1.25 and rounding off the result.
In the January 11, 1993 rule, the SO2 or NOX
monitor range derived from the MPC was referred to as the ``high-
scale.'' The rule further specified that whenever the majority of the
readings during normal operation were expected to be less than 25.0
percent of the high full-scale range value (e.g., if a scrubber is used
to reduce SO2 emissions), a second, ``low-scale'' span and
range would be required. The low scale span value of the CEMS would be
defined as 1.25 times the ``maximum expected concentration'' (MEC).
In the first two years of Acid Rain Program implementation, it
became clear that the span and range provisions of part 75 lacked
sufficient flexibility and clarity. The May 17, 1995 rule revisions
attempted to address these deficiencies. Two alternative methods of
determining the MPC or MEC were added, i.e., from historical CEMS data
or from emission test results. For NOX, a comprehensive list
of MPC values was promulgated (Tables 2-1 and 2-2 in Appendix A),
taking into consideration the unit type in addition to the fuel type.
Flexibility was also added to the dual-range requirements for
NOX monitors. For flow rate, a more detailed procedure for
determining the span value was added.
The May 17, 1995 rule also revised the procedures for adjusting the
span and range of SO2, NOX, and flow monitors.
The original rule had specified that span and range adjustments were
required whenever the MPC, the MEC, or the MPV changed significantly
(although a ``significant'' change was undefined). When a significant
change in the MPC, MEC, or MPV occurred, a new range setting was to be
established and a new span value defined, equal to 80.0 percent of the
adjusted range value. The May 17, 1995 rule changed this procedure,
requiring the new span value to be determined first, followed by the
new range. The May 17, 1995 rule also added procedures for addressing
full-scale exceedances, specifying that the full-scale value is to be
reported for an exceedance of one hour and that a range adjustment is
required for an exceedance greater than one hour.
After promulgation of the May 17, 1995 rule, EPA continued to
receive questions and comments about the span and range sections of
part 75. Apparently, the span and range sections of the rule were still
not sufficiently clear, flexible, or detailed and were in need of
further revision. Therefore, on May 21, 1998, further revisions to the
span and range provisions were proposed.
The proposed rule provided an alternative procedure for determining
the MPC of SO2 or NOX, requiring the MPC to be
based upon a minimum of 720 quality assured monitor operating hours,
rather than 30 unit operating days. A specific requirement to calculate
the maximum potential NOX emission rate (MER) was also
proposed. The owner or operator could use the diluent cap value of 5.0
percent CO2 or 14.0 percent O2 for boilers (or
1.0 percent CO2 or 19.0 percent O2 for turbines)
in the NOX MER calculation.
The proposed rule provided a definition of the MPC for
CO2. The MPC would be 14.0 percent CO2 for
boilers and 6.0 percent CO2 for combustion turbines.
Alternatively, the MPC for CO2 could be based on a minimum
of 720 hours of representative quality assured historical CEM data. A
standardized procedure for calculating the maximum potential flow rate
(MPF) was proposed and a clear distinction between the ``calibration
span value'' of a flow monitor (expressed in the units of measure used
for the daily calibrations) and the ``flow rate span value'' (expressed
in the units used for electronic data reporting) was provided.
The proposed rule set forth changes to the procedures for
determining the maximum expected concentration (MEC) of SO2
and NOX, and to the criteria for determining whether dual
span and range requirements apply. A separate MEC determination would
be required for each type of fuel combusted, except for fuels that are
only used for unit startup or for flame stabilization. To determine
whether a second, low-scale span is required in addition to the high-
scale span based on the MPC, each of the maximum expected concentration
(MEC) values would be compared against the MPC. If any of the MEC
values was <20.0 percent of the MPC, a low-scale span would be
required.
The proposed rule provided additional flexibility in the method of
calculating span values. The SO2, NOX or flow
rate span value could be set anywhere between 1.00 and 1.25 times the
applicable maximum value (i.e., the MPC, MEC or MPF). For
CO2 and O2 monitors, the owner or operator would
be given maximum flexibility in selecting an appropriate span value.
For CO2 monitors installed on boilers, any representative
span value between 14.0 percent and 20.0 percent CO2 would
be acceptable. For combustion turbines, any representative
CO2 span value between 6.0 and 14.0 percent CO2
could be used. For O2 monitors, a span value between 15.0
percent and 25.0 percent O2 could be selected and an
alternative O2 span value of less than 15.0 percent could be
used, if supported by an acceptable technical justification.
The proposed rule expanded and clarified the guideline in section
2.1 of Appendix A for selecting an appropriate full-scale range. The
full-scale range would be selected so that the readings during typical
unit operation fall between 20.0 and 80.0 percent of full-scale, which
represents a slight increase in flexibility from the 25 to 75 percent
of full-scale guideline in the current rule. The proposal also cited
three specific cases in which the guideline in section 2.1 is
inapplicable: (1) during the combustion of very low sulfur fuels
(0.05% sulfur by weight); (2) for SO2 or
NOX readings on the high range for an affected unit with
SO2 or NOX emission controls and two span values;
and (3) when SO2 or NOX readings are less than
20.0 percent of the low measurement range for a dual-span unit with
SO2 or NOX emission controls, provided that the
low readings occur during periods of high control device efficiency.
[[Page 28570]]
The proposed rule specified that the following monitoring
configurations could be used to meet dual span and range requirements:
(1) a single analyzer with two ranges, or (2) two separate analyzers
connected to a common probe and sample interface. The high and low
ranges could be designated in the monitoring plan as two separate,
primary monitoring systems, or as separate components of a single,
primary monitoring system, or the ``normal'' range could be designated
as a primary monitoring system, and the other range as a non-redundant
backup monitoring system.
The proposed rule would allow the owner or operator to use a
``default high-range value'' in lieu of operating, maintaining, and
quality assuring a high-scale monitor range. The default high-range
value would be 200.0 percent of the MPC. This value would be reported
whenever the SO2 or NOX concentration exceeded
the full-scale of the low-range analyzer.
Finally, the proposed rule provided detailed guidelines and
procedures for adjusting the span and range of the CEMS. First, if the
maximum value upon which the high span value is based (i.e., the MPC or
MPF) was exceeded during a calendar quarter, but the span was not
exceeded, the span or range would not have to be adjusted. However, if
any quality assured hourly concentration or flow rate exceeded the MPC
or MPF by 5.0 percent during the quarter, a new MPC or MPF
would have to be defined. Second, if any quality assured reading on the
high measurement range exceeded the span value by 10.0
percent during the quarter but did not exceed the range, a new MPC or
MPF (as applicable) would have to be defined, and the span value (and
range, if necessary) would also have to be changed. Third, for full-
scale exceedances of a high monitor range, corrective action would be
required to adjust the span and range. A value of 200.0 percent of the
current full-scale range would be reported to EPA for each hour of each
full-scale exceedance.
Today's rule finalizes the proposed revisions to the span and range
sections of Appendix A. Most of the provisions have been finalized as
proposed, with only minor changes and clarifications. However, there
are three notable exceptions: (1) the proposed requirement for
mandatory quarterly evaluations of the MPC, MEC and MPF values and the
associated prescriptive criteria for adjusting the spans and ranges
have been withdrawn; (2) the proposed change in methodology for
determining dual span and range requirements (i.e., comparing the MEC
value(s) to the MPC) has been withdrawn; and (3) an additional
monitoring configuration option has been provided for units with dual
span requirements. For units with a dual-range SO2 or
NOX analyzer, the final rule allows the low and high ranges
to be represented as a single component of a primary SO2 or
NOX monitoring system.
Discussion: EPA received supportive comments from a number of
utilities, regarding several of the proposed span and range revisions
(see Docket A-97-35, Items IV-D-20, IV-D-23, IV-D-24, IV-D-25, and IV-
G-01). The commenters generally favored the increased flexibility in
determining SO2, NOX, CO2 and
O2 span values and supported the concept of a ``default high
range value.'' One commenter, however, opposed the use of purified
instrument air for O2 monitor calibrations (see Docket A-97-
35, Item IV-D-11) and, as discussed in greater detail below, two
commenters who supported the ``default high range'' concept took issue
with the proposed default value (see Docket A-97-35, Items IV-D-05 and
IV-D-24). One commenter asked EPA to give guidance as to what type of
technical justification would be required to use an alternative
O2 span value of less than 15 percent (see Docket A-97-35,
Item IV-D-23). The final rule provides an example, in section 2.3.1 of
Appendix A.
Several commenters stated that the proposed procedures for making
span and range adjustments were particularly complicated and burdensome
(see Docket A-97-35, Items IV-D-19, IV-D-20, IV-D-23, IV-D-24 and IV-G-
09). Two commenters stated that the requirement to perform quarterly
evaluations of the MPC, MEC and MPF values is unnecessary and excessive
(see Docket A-97-35, Items IV-D-11 and IV-G-02). One commenter
recommended using the guideline in section 2.1 of Appendix A to
determine whether span and range adjustments are needed (see Docket A-
97-35, Item IV-D-11). Another commenter recommended that EPA allow data
points that are clear ``outliers'' to be excluded from quarterly span
and range evaluations (see Docket A-97-35, Item IV-D-04). After
carefully considering these comments, EPA has decided to withdraw the
prescriptive proposed procedures for making span and range adjustments.
Instead, the final rule requires that span and range adjustments be
made only when the MPC, MEC or MPF changes ``significantly.'' This is
similar to the original guideline in the January 11, 1993 rule, except
that a ``significant'' change was undefined in that rule. In today's
rule, a significant change in the MPC, MEC or MPF means that the
guideline of section 2.1 of Appendix A ( for the majority of the
readings to be between 20 and 80% of the range, with certain allowable
exceptions) cannot be met, as determined either by the owner or
operator or through an audit by a regulatory agency. The Agency has
also reduced the frequency of mandatory evaluations of the MPC, MEC and
MPF values. In the final rule, only an annual evaluation of these
values is required. The results of the annual evaluations must be kept
on-site, in a format suitable for inspection.
Two commenters stated that the proposed requirement to treat the
two ranges of a dual-range monitor as separate monitoring systems or as
two separate components of the same system would cause additional
programming costs and would be technically difficult to implement (see
Docket A-97-35, Items IV-D-4 and IV-G-02). The commenters requested
that EPA continue to allow the low and high ranges to be represented in
the monitoring plan by a single component. After consideration, the
Agency has decided that the commenters' request is reasonable and has
included this option in the final rule. Note, however, that the use of
this option is restricted to dual-range analyzers that use electronic
gain to produce the two ranges. Today's rule requires the use of a
special dual-range component type code when this option is selected.
EPA will provide the necessary type code and reporting guidance in the
electronic data reporting (EDR) instructions for EDR version 2.1.
Two commenters stated that 200% of MPC is too high for the proposed
default high range value in sections 2.1.1.3(f) and 2.1.1.4(e) of
Appendix A, for the case where the owner or operator uses a default
value instead of operating a high-range monitor (see Docket A-97-35,
Items IV-D-05 and IV-D-24). A third commenter objected to the proposed
value of 200% of the range, which is to be reported during full-scale
exceedances (see Docket A-97-35, Item IV-G-05). Without a functional
high range monitor, it is not possible to determine the exact pollutant
concentration when a control device malfunctions or when a full-scale
exceedance occurs. In the preamble to the proposed rule, EPA cited one
instance in which the high SO2 range was exceeded and the
estimated SO2 concentration (based on fuel sampling) was
estimated to be about 150% of the range (see 63 FR 28058). For this
reason, the proposed values of 200% of the range (for full-scale
exceedances) and
[[Page 28571]]
200% of the MPC (for the default high range value) have been retained
in the final rule. EPA maintains that these values must be
conservative, based on a ``worst case'' analysis to ensure that
emissions will not be under-reported. The Agency believes that if spans
and ranges are properly set, full-scale exceedances will be relatively
rare. Also, EPA anticipates that the majority of the units for which
owners or operators will elect to use the default high range option
have reliable emission controls and the default value will rarely, if
ever, have to be used.
One commenter objected to the proposed changes to the method of
calculating MPC and MEC values, expressing concern that the revisions
might require his existing span and range values to be re-calculated
(see Docket A-97-35, Item IV-G-02). Another commenter (mistakenly)
interpreted the proposed definition of the MPC for CO2 in
section 2.3.1 of Appendix A to mean that his existing CO2
span values would have to be re-determined (see Docket A-97-35, Item
IV-D-04). A third commenter asked EPA to ``grandfather'' existing span
and range values (see Docket A-97-35, Item IV-D-20). It is not, and
never has been EPA's intent to require utilities to change their
existing spans and ranges, provided that they meet the guideline of
section 2.1 of Appendix A ( for the majority of the readings to be
between 20 and 80% of full-scale, with certain allowable exceptions).
The Agency does not believe that ``grandfathering'' of any existing
part 75 span and range values is necessary. The final rule simply adds
flexibility to the procedures for determining spans and ranges.
Affected units with previously-determined span and range values that
meet the guideline of section 2.1 of Appendix A do not have to change
their current span or range values. To further alleviate undue concern
about this, the Agency has withdrawn the proposed changes to the method
of determining whether a dual span is required. Rather than comparing
the MEC value(s) to the MPC value(s) (as proposed), today's rule
specifies that the MEC value should be compared to the high range
value. This is essentially the same as the requirement in the current
rule.
Finally, one commenter objected to the proposed requirement to
perform the RATA at the low range of the monitor on units that have
scrubbers. The commenter urged EPA to revert to the original rule and
allow the RATA to be performed at whatever range the CEMS is operating
on at the time of the RATA (see Docket A-97-35, Item IV-G-3). EPA does
not agree with the commenter. For units with SO2 scrubbers,
the vast majority of the data is collected on the low range. Therefore,
the SO2 RATA should be performed on that range. If the
scrubber malfunctions at the time of a scheduled SO2 RATA,
the RATA should either be rescheduled later in the quarter or should be
done during the 720 unit operating hour grace period allowed under
revised section 2.3.3 of Appendix B.
E. Flow-to-Load Ratio Test Requirements
Background: The quality assurance requirements for flow rate
monitoring systems in Appendices A and B of part 75 include daily
calibration error tests, daily interference checks, quarterly leak
checks (for differential pressure type monitors only), and semiannual
or annual RATAs. Of these required QA tests, only the RATA provides a
true evaluation of a flow monitor's measurement accuracy by direct
comparison against an independent reference method. The daily
calibration error test checks the system's internal electronic
components by means of reference signals. The calibration error test is
useful in that it can diagnose certain types of monitor problems, but
it does not evaluate the system's ability to measure an actual stack
gas flow rate. Because of this limitation, EPA believes that a more
substantive, periodic QA test is needed to ensure that the accuracy of
the reported flow rate data is maintained in the interval between
successive RATAs. The Agency is particularly concerned about the
potential for poor data quality from flow monitors that are not
properly maintained.
In view of this, EPA proposed to add a new flow monitor quality
assurance test, the ``flow-to-load ratio test,'' to part 75 in section
7.7 of Appendix A and section 2.2.5 of Appendix B. A similar test was
first suggested to the Agency by a flow monitor manufacturer (see
Docket A-97-35, Item II-D-69). The flow-to-load ratio test, which would
be performed quarterly, would be required beginning in the second
quarter of the year 2000. The basic premise of the flow-to-load ratio
test is that a meaningful correlation exists between the stack gas
volumetric flow rate and unit load. In general, for a single unit
discharging to a single stack, as the load increases, the flow rate
increases proportionally, and the flow rate at a given load should
remain relatively constant if the same type of fuel is burned. Common
stacks are somewhat less predictable, because the same combined unit
load can be produced in a number of ways by using different
combinations of boilers. Despite this, if the diluent gas concentration
is properly taken into account, the flow-to-load characteristics of
common stacks often become more normalized. The flow-to-load ratio, or
a normalized ratio, such as the gross heat rate (GHR) can thus serve as
a quantitative indicator of flow monitor accuracy from quarter to
quarter until the next RATA is performed.
The proposed rule provided a calculation methodology for the
quarterly flow-to-load or GHR evaluation. A ``reference'' flow-to-load
ratio or GHR would be established at the time of each normal-load flow
RATA, using data from the flow rate reference method. Then, in
subsequent quarters, hourly data from the flow monitor would be
compared to the reference ratio or GHR, and an absolute average
percentage difference between the hourly data and the reference ratio
would be calculated. If the percentage difference exceeded certain
limits, the utility would be required to investigate to try to
establish the cause of the test failure. If the investigation indicated
a problem with the flow monitor, the utility could perform corrective
actions, followed by an abbreviated flow-to-load diagnostic test, to
demonstrate that the corrective actions were effective. However, if the
investigation could not establish the cause of the flow-to-load test
failure, a normal load flow RATA would be required.
Today's final rule adopts the flow-to-load ratio test provisions.
The final rule is essentially the same as the proposal except for a few
minor changes in response to comments received.
Discussion: EPA received comments on the proposed quarterly flow-
to-load ratio test from seven utilities, two state agencies, one
utility regulatory response group and one flow monitor vendor. One
state agency was supportive of the test, because it can serve as a
quantitative indicator of flow monitor performance from quarter to
quarter (see Docket A-97-35, Item IV-D-9). The flow monitor vendor also
favored the test, because it will help to ensure that all flow
monitoring technologies perform in a reliable manner (see Docket A-97-
35, Item IV-D-12). Several utility commenters objected to the proposed
test, believing it would be burdensome, time-consuming, expensive to
implement (requiring significant DAHS software modifications), and
difficult to pass (see Docket A-97-35, Items IV-D-16, IV-G-5, IV-G-9,
IV-G-2). One commenter suggested that the test be used as a warning to
take corrective action rather than using it to directly validate or
invalidate flow rate data (see
[[Page 28572]]
Docket A-97-35, Item IV-D-11). Another commenter recommended that for
common stacks, additional hours be exempted from the data analysis,
specifically hours in which the combination of boilers and loads does
not match the combination used during the last normal load flow RATA
(see Docket A-97-35, Item IV-D-17). Two commenters recommended
increasing the threshold to qualify for a less stringent flow-to-load
specification from 50 MW to 60 or 70 MW (see Docket A-97-35, Items IV-
D-11, IV-D-2). Two commenters recommended reducing the frequency of
flow RATAs based on good performance in the flow-to-load test;
specifically, one commenter advocated performing flow RATAs every other
year and the other commenter recommended performing a flow RATA once
every five years (see Docket A-97-35, Items IV-D-22, IV-G-2). One
commenter stated that the proposed flow-to-load methodology does not
adequately address multiple stack configurations where one of the
stacks is a bypass stack, and also recommended that EPA make it clear
that the flow-to-load data analysis only applies to reported data and
not to redundant backup monitor data which are not reported (see Docket
A-97-35, Item IV-G-2). Finally, the utility regulatory response group
found the proposal to be an improvement over the pre-proposal draft
that was circulated in May, 1997, but took issue with the following:
(1) The method of calculating the test results, using the absolute
value of, rather than the arithmetic, percentage of differences between
the hourly flow-to-load ratios and the reference ratio; (2) failure of
the proposal to address units with bypass stacks or other complex stack
configurations; and (3) allowing only one week after the end of the
quarter to investigate and troubleshoot the flow monitor when a flow-
to-load test failure occurs, before a RATA requirement is triggered
(see Docket A-97-35, Item IV-D-20).
Today's rule includes flow-to-load test provisions in section 7.7
of Appendix A and section 2.2.5 of Appendix B. The final rule is
essentially the same as the proposal, except for the following changes,
which have been incorporated in response to the comments received.
First, a new section 7.8 has been added to Appendix A, which allows
owners or operators of units with complex stack configurations to
petition for an exemption from quarterly flow-to-load testing. Any such
petition would have to provide information and data which demonstrate
to the satisfaction of the Administrator that the flow rate through the
complex stack configuration cannot be reasonably correlated to unit
load. Second, for a unit with a multiple stack discharge configuration
consisting of a main stack and a bypass stack (e.g., for a unit with a
wet SO2 scrubber), the flow-to-load test is to be performed
on an individual stack basis and hours in which emissions are
discharged simultaneously through both stacks may be excluded from the
quarterly flow-to-load analysis. Third, the threshold to qualify for a
less stringent flow-to-load specification has been raised from 50 MW to
60 MW. Fourth, when a flow-to-load or GHR test is failed, two weeks,
rather than one, are allowed after the end of the quarter to
investigate the cause of the test failure before triggering a RATA
requirement.
EPA does not agree with the commenters who characterized the
proposed flow-to-load test as time-consuming, burdensome, and difficult
to implement (requiring extensive software revision). The Agency
believes that implementation of the flow-to-load test will not require
any special modification of existing part 75 DAHS systems or software.
All of the information needed to perform the quarterly flow-to-load or
GHR analysis is currently reported in the electronic quarterly report
required under Sec. 75.64. Rather, a PC-based computer program will be
needed, which can extract the essential information from the quarterly
report and analyze it. Once such a computer program is written,
analysis of the quarterly flow rate and load data should become a
routine operation which will be neither burdensome nor time-consuming.
The Agency also disagrees with those commenters who contended that
the flow-to-load test will be difficult to pass. On the contrary, the
flow-to-load test should be relatively easy to pass, provided that the
flow monitor is properly operated and well-maintained. Prior to issuing
the proposed rule, EPA analyzed quarterly flow rate and load data from
the third quarter of 1996 for 21 units and stacks, including 9 single
units, 11 common stacks, and 1 multiple-stack unit. The units chosen
for this analysis were selected as a representative sample of units
that would be affected by this QA test requirement and included various
operational circumstances (e.g., base loaded and peaking units, single
fuel units, and units that burn multiple fuels). The flow-to-load and
GHR test methodologies were applied to each unit or stack, excluding
none of the normal load data from the analysis. The results of the
flow-to-load and GHR data analyses were nearly the same. Only one
failure of the quarterly flow-to-load test was observed in each
analysis (i.e., the failure rate was <5.0 percent). The value of
Ef (the average percentage difference between the hourly
ratios and the reference ratio) was 6.1 percent for the analysis of the
flow-to-load ratios and 6.4 percent for the simulated GHR analysis
(with diluent gas corrections). However, as noted by one of the
commenters, the Agency acknowledges that these data analyses were
performed using the calculation method described in the May, 1997 pre-
proposal draft of the rule revisions, i.e., using the arithmetic
percentage difference between each hourly flow-to-load ratio and the
reference ratio, rather than the absolute percentage difference
prescribed in the proposed rule. To address the commenter's concern,
EPA has re-analyzed the data using the absolute percentage difference.
The results of the data analysis using the absolute percentage
difference were nearly the same as the results using the arithmetic
percentage difference. The failure rate was the same (<5%) and the
value of Ef was 7.3 percent for the analysis of the flow-to-
load ratios and 8.0 percent for the simulated GHR analysis (with
diluent gas corrections), which is still well below the 15.0 percent
tolerance limit (see Docket A-97-35, Item IV-A-3). Thus, it appears to
make very little difference, in terms of ease of passing, whether the
absolute percentage difference or the arithmetic percentage difference
is used in the flow-to-load and GHR calculations. Therefore, the flow-
to-load and GHR calculation methodology has been finalized as proposed
using the absolute percentage difference.
Two commenters suggested that the flow RATA frequency should be
reduced based on good performance on the quarterly flow-to-load test
(see Docket A-97-35, Items IV-D-22 and IV-G-02). The Agency agrees with
the commenters that with the addition of the new QA tests it is
reasonable to lessen the frequency of the annual three load flow RATA.
Therefore, EPA is also adopting the following three provisions reducing
the flow RATA requirements: (1) Routine flow RATAs are changed from
three-load tests to two-load tests; (2) a single-load annual flow RATA
is allowed if the unit operates at one load level for 85
percent of the time since the last annual flow RATA; and (3) a three-
load flow RATA is required only once every five years and whenever the
instrument is re-linearized. EPA has adopted these reduced flow RATA
[[Page 28573]]
requirements principally because of the reasonable assurance of data
quality that will be provided in between RATAs by the new flow-to-load
test. Note, however, that the flow-to-load ratio test, which analyzes a
limited amount of flow rate data at a single load level, does not serve
as a replacement for annual RATA testing. Rather, the flow-to-load
ratio test helps to ensure that the flow monitor remains accurate in
between successive semiannual or annual RATAs.
F. RATA and Bias Test Requirements
1. RATA Load Levels
Background: The previous provisions of part 75 were neither
sufficiently standardized nor clear in defining the appropriate load
levels for RATAs. For example, the previous rule required gas monitor
RATAs to be conducted at normal load and required gas and flow rate
monitor bias adjustment factors to be determined at normal load, but no
definition of normal load was provided. In addition, section 6.5.2 of
Appendix A specified that the ``low'' load audit point for a 3-level
flow RATA can be located anywhere from the minimum safe, stable load to
50.0 percent of the maximum load, and no minimum separation is required
between the audit points at adjacent load levels. If adjacent audit
points are too close together, a multiple load flow evaluation loses
its significance.
EPA proposed revisions to Appendix A of part 75, which would more
clearly define the load levels at which RATAs are done in order to
achieve greater consistency in the way that RATAs are performed. The
proposed methodology, which would become effective as of April 1, 2000,
would require the utility to define the ``range of operation'' for each
affected unit or common stack (except for peaking units). The range of
operation would extend from the minimum safe, stable load to the
maximum achievable load. The ``low'' load level would then be defined
as 0-30% of the range of operation, the ``mid'' load level would be 30-
60% of the range and the ``high'' load level would be 60-100% of the
range. The proposed methodology would require a load frequency
distribution (histogram) to be developed, prior to each annual RATA, to
determine the percentage of time the unit or stack has operated at each
load level in the previous four ``QA operating quarters.'' A summary of
the data used for the load frequency determination would be maintained
on-site in a format suitable for inspection, and the results of the
determination would be included in the electronic quarterly report
under Sec. 75.64. The most frequently used load level would then be
designated as the ``normal'' load. The second most frequently used load
could, at the discretion of the owner or operator, be designated as a
second normal load level. Gas monitor RATAs would be required at the
normal load level. Routine quality assurance RATAs for flow monitors
would be done at the two most frequently used load levels. Today's rule
adopts the proposed changes with certain modifications in response to
comments.
Discussion: The Agency received comments on the proposed method of
determining RATA load levels from three individual utilities and from
two utility regulatory response groups. Only two comments were received
on the proposed definitions of ``range of operation,'' ``low,''
``mid,'' and ``high'' load levels. One commenter supported the effort
to establish load level definitions, but found the proposal to be too
inflexible and complicated and suggested that EPA should permit
overlapping load ranges (see Docket A-97-35, Item IV-D-20). The other
commenter requested that EPA modify the proposed definition of the
``minimum safe, stable load'' for common stacks. The commenter
expressed concern that for base-loaded units which share a common
stack, the proposed definition might require a unit to be shut down to
attain the low load level in a 3-load flow RATA (see Docket A-97-35,
Item IV-D-24). Four commenters opposed the proposed requirement to
develop a historical load frequency distribution to establish the
normal load level(s) for the unit or stack, stating that the load
frequency is too variable (being dependent on unit availability,
operation, and dispatch) and that the new requirement would add another
level of unnecessary data collection and manipulation (see Docket A-97-
35, Items IV-D-20, IV-D-24, IV-D-19, and IV-D-23). Another commenter
suggested that RATA load ranges should be based on the typical load
requirements for the quarter in which the RATA is done, particularly if
the historical data are no longer representative. The commenters
further recommended that EPA should: (1) eliminate the requirement to
use four operating quarters of data; (2) allow extenuating data to be
excluded; (3) allow recent changes to be considered when selecting load
ranges; and (4) allow utilities to consider forecasted usage of a unit
when selecting load ranges (see Docket A-97-35, Item IV-D-20). Finally,
one commenter objected to the proposed requirement to report the
results of the load frequency data analysis electronically, stating
that requiring electronic reporting of the results provides no
advantage over keeping the data analysis on-site and that such
reporting would require DAHS software changes (see Docket A-97-35, Item
IV-G-2).
Today's rule finalizes the proposed definitions of the ``range of
operation,'' and the ``low,'' ``mid,'' and ``high'' load levels in
section 6.5.2.1 of Appendix A and the associated requirement to report
the upper and lower boundaries of the range of operation, with one
minor revision. A provision has been added for frequently-operated
(e.g., base-loaded) units that share a common stack, which allows the
``minimum safe, stable load'' to be determined in a different manner.
For such units, the owner or operator may use the sum of the minimum
safe, stable loads for the individual units as the minimum safe stable
load for the common stack (rather than using the lowest of the minimum
safe, stable load values for the individual units). The Agency believes
that this adequately addresses the commenter's concern that one or more
units might have to be shut down in order to attain the ``low'' load
level during a 3-load flow RATA.
Section 6.5.2.1 of Appendix A of today's rule also finalizes the
proposed methodology for determining normal load and for selecting the
appropriate load levels for the annual 2-load flow RATAs, with
revisions based on comments received. In the final rule, a
determination of the normal load level(s) and the appropriate flow RATA
load levels is still required, but it has been made a one-time
requirement, rather than an annual requirement. The requirement becomes
effective on April 1, 2000, but owners or operators may comply with it
prior to that date. The owner or operator must review historical load
data for the unit or stack, for a minimum of four representative
operating quarters. From these data, the percentage of unit operating
time at each load level (``low,'' ``mid'' or ``high'') will be
determined. The historical load data may be analyzed by any suitable
means; construction of a histogram, per se, is not required. The load
level used the most frequently will be designated normal, and the
second most frequently used load level may, at the discretion of the
owner or operator, be designated as a second normal load. The two most
frequently used load levels are the load levels at which the annual 2-
load flow RATA will be performed. The results of the historical load
data analysis will be reported in the electronic quarterly report as
part of the electronic monitoring plan. EPA
[[Page 28574]]
believes that reporting one additional monitoring plan record will not
prove to be burdensome. A summary of the data used for the load
determinations and the calculated results must be kept on-site, in a
format suitable for inspection.
EPA continues to believe that a review of historical operating load
data is a reasonable way to standardize the determination of the normal
load level(s) and the appropriate flow RATA load levels for a unit or
stack. In order to maintain national consistency and to ensure that a
``level playing field'' is maintained among affected utilities, the
Agency believes that a standardized procedure is necessary. Although
several commenters took issue with the specifics of the proposed
methodology, none of them provided a sufficiently detailed alternative
procedure for serious consideration by the Agency. Requests to ``allow
exclusion of extenuating data'' and ``permit consideration of recent
changes when selecting load ranges'' do not provide a sufficient basis
for the development of appropriate regulatory language. Further, since
the standardized procedure is based on data for four operating
quarters, any unrepresentative data is likely to have minimal effect.
Therefore, EPA did not incorporate most of the commenters' suggestions.
However, to address the concern of several commenters about possible
variability in unit load and manner of unit operation, a provision has
been added to section 6.5.2.1 of Appendix A which requires the
historical load analysis to be repeated if the way in which a unit
operates changes significantly and the previously-determined normal
load level(s) and the two most frequently used load levels change. The
new provision requires a minimum of two representative operating
quarters of historical load data to document that a change in the
manner of unit operation has actually occurred.
2. Single-Point Reference Method Sampling
Background: Section 6.5.6 of Appendix A to part 75 gives the
traverse point location requirements for reference method sampling
during relative accuracy test audits (RATAs) of gas monitoring systems.
The reference method sampling points are to be located along a line, in
accordance with section 3.2 of Performance Specification No. 2 in
Appendix B to 40 CFR part 60. Performance Specification No. 2 requires
three reference method sampling points for each RATA test run. EPA
proposed changes to section 6.5.6 of Appendix A, pertaining to RATA
traverse point selection. Proposed section 6.5.6 would allow single-
point reference method sampling to be used in two specific instances:
(1) for all moisture determinations, a single reference method point,
located at least 1.0 meter from the stack wall, could be used; and (2)
for flue gas sampling, a single reference method measurement point,
located no less than 1.0 meter from the stack wall, could be used at
any test location if a stratification test is performed prior to each
RATA at the location and certain acceptance criteria are met.
In order to implement the second option (single-point gas
sampling), a 12-point stratification test, as described in proposed
section 6.5.6.1, would have to be passed one time at the sampling
location, meeting the acceptance criteria for single-point sampling
given in proposed section 6.5.6.3 of Appendix A. The location would
qualify for single-point gas sampling if the concentration at each
individual traverse point differed by no more than 5.0
percent from the arithmetic average concentration for all traverse
points. The results would also be acceptable if the concentration at
each individual traverse point differed by no more than
3.0 ppm or 0.3 percent CO2 (or O2) from the
arithmetic average concentration for all traverse points. Once a 12-
point stratification test was passed at the candidate sampling
location, either the 12-point test or an abbreviated 3-point or 6-point
stratification test, as described in proposed section 6.5.6.2, would
have to be passed prior to subsequent RATAs at the location.
Today's rule finalizes the provisions for single-point moisture and
gas reference method sampling, with certain modifications in response
to comments received. The criteria in today's rule to qualify for
single-point sampling are more stringent than the criteria in the
proposed rule.
Discussion: EPA received comments from two utilities and three
State air regulatory agencies on the proposal to allow single-point
reference method sampling. One of the utility commenters favored
allowing single-point sampling, viewing it as an excellent step to
improve the overall efficiency of RATA testing (see Docket A-97-35,
Item IV-D-21). The other utility commenter also favored the proposal,
believing that it would reduce the manpower requirements for gas RATA
testing (see Docket A-97-35, Item IV-D-22). One State agency commenter
opposed the unrestricted use of single-point moisture sampling, stating
that the moisture results could be biased if gas stratification is
present in the stack. Another State agency commenter viewed the
proposal to allow single-point reference method sampling as
unfavorable, expressing concern that single-point sampling may not
yield valid results, particularly if the sampling point is too near the
stack wall, where air in-leakage can occur (see Docket A-97-35, Item
IV-D-9). The third State agency commenter appeared to take issue with
the use of a 3-point abbreviated stratification test, stating that for
the large-diameter stacks in the Acid Rain Program, a three point test
is not adequate to demonstrate the absence of stratification.
In response to the comments received, the single-point reference
method provisions in section 6.5.6 of Appendix A of today's rule are
more restrictive than the provisions in the proposal. After careful
consideration, EPA has decided to allow single-point reference method
sampling, but to place additional restrictions on its use. The Agency
believes that some of the state agency commenters' concerns about the
proposed single-point sampling methodology are valid. Accordingly,
today's final rule addresses these concerns.
Today's rule allows the unrestricted use of single-point moisture
sampling only in applications where the moisture data are used to
determine the stack gas molecular weight. For all other moisture
measurement applications, i.e., for moisture monitoring system RATAs or
when moisture data are used to correct emission data from a dry basis
to a wet basis (or vice-versa), single-point moisture sampling is only
permitted if a 12-point pollutant or diluent gas stratification test is
performed and passed (at the 5.0 percent specification in section
6.5.6.3 of Appendix A) prior to the RATA. Similarly, for flue gas
sampling, today's rule allows the use of single-point reference method
sampling only if a 12-point gas stratification test is performed and
passed at the 5.0 percent specification prior to the RATA. Use of an
abbreviated (3- or 6-point) stratification test as a means of
qualifying for single-point sampling is not allowed.
Finally, when a test location qualifies for single-point reference
method sampling, today's rule specifies that the measurement point must
be located at least 1.0 meter from the stack wall and must be situated
along one of the measurement lines used in the 12-point stratification
test. EPA believes that these modifications to the proposed single-
point reference method sampling methodology are necessary to ensure
[[Page 28575]]
that representative samples will continue to be obtained.
G. Data Validation
1. Data Validation During Monitor Certification and Recertification
Background: The previous version of part 75 specified that for any
replacement, change, or modification to a monitoring system requiring
recertification of the CEMS, all data from the CEMS are invalid from
the hour of that replacement, change, or modification until the hour of
completion of all required recertification tests. The proposed rule
would have revised Sec. 75.20(b)(3) to conditionally allow emission
data generated by the CEMS during a recertification test period to be
used for part 75 reporting, provided that the required tests are
successfully completed in a timely manner and that certain data
validation rules are followed during the recertification test period.
Proposed sections 6.2, 6.3.1, and 6.5 of Appendix A would have allowed
these new data validation procedures to also be applied to the initial
certification of monitoring systems. The intended purpose of the
proposed revisions is to minimize the number of hours of substitute
data or maximum potential values that must be reported during a monitor
certification or recertification period.
In proposed Sec. 75.20(b)(3), specific rules were provided for data
validation during the recertification test period. The recertification
test period would begin with the first successful calibration error
test (known as a ``probationary calibration error test'') after making
the change to the CEMS and completing all necessary post-change
adjustments (e.g., reprogramming or linearization) of the CEMS. The
post-change activities could include preliminary tests such as trial
RATA runs or a challenge of the monitor with calibration gases. Data
from the CEMS would be considered invalid from the hour in which the
replacement, modification, or change to the system is commenced until
the hour of completion of the probationary calibration error test, at
which point the data status would become ``conditionally valid.''
The conditionally valid status of the CEMS data would continue
throughout the recertification test period, provided that the required
recertification tests were done ``hands-off'' (i.e., with no
adjustments, such as reprogramming or linearization of the CEMS, other
than the calibration adjustments allowed under proposed section 2.1.3
of Appendix B) and provided that the recertification tests and required
daily calibration error tests continued to be passed. If all of the
required recertification tests and calibration error tests were passed
hands-off, with no failures and within the required time period, then
all of the conditionally valid emission data recorded by the CEMS
during the recertification test period would be considered quality
assured and suitable for part 75 reporting. However, if any required
test was failed, the conditionally valid data would, in most cases, be
invalidated and a new recertification test period would have to be
initiated, following corrective actions.
Today's rule finalizes the CEMS validation procedures for
certifications and recertifications, with certain modifications in
response to comments received.
Discussion: EPA received strongly supportive comments on the
proposed revisions to Sec. 75.20(b)(3) from five utilities, one state
air regulatory agency and two utility regulatory response groups.
However, two utilities asked the Agency to modify the proposal to allow
trial gas injections and preliminary RATA runs to be done during the
recertification test period, rather than prior to it. One commenter
stated that preliminary gas injections and RATA runs, which are
considered to be a valuable maintenance tool, should be allowed
following the probationary calibration error test, and, provided that
the results of the trial runs are acceptable, the recertification
should be allowed to proceed (see Docket A-97-35, Item IV-G-3). Another
commenter requested that the proposal be revised to allow a single
challenge with each of the three gases prior to a linearity test and to
allow up to five preliminary trial runs prior to a RATA (see Docket A-
97-35, Item IV-G-5).
Today's rule finalizes the proposed data validation procedures in
Sec. 75.20(b)(3) for monitor certification and recertification, with
the following modifications in response to the comments. First, an
introductory statement of applicability has been added at the beginning
of Sec. 75.20(b)(3), clearly indicating that the provisions of the
section apply both to recertifications and to initial certifications.
The statement of applicability also allows the data validation
procedures to be applied, at the discretion of the owner or operator,
to the routine quality assurance linearity tests and RATAs required
under Appendix B of part 75 (see the section on ``Data Validation for
RATAs and Linearity Checks'' in this preamble, for a further discussion
of this option). Second, proposed paragraph (b)(3)(x) of Sec. 75.20 has
been merged with proposed paragraph (b)(3)(i), for greater clarity;
both paragraphs deal with missing data substitution prior to the
recertification test period. Third, the definition of a ``hands-off''
recertification test in Sec. 75.20(b)(3)(v) has been revised to make it
clear that once a recertification test has begun, only routine
calibration adjustments following daily calibration error tests are
permitted until the test is completed. Fourth, language has been added
to Sec. 75.20(b)(3) to address the case in which a multi-load flow RATA
is passed at one or more load levels and then failed at a subsequent
load level.
Regarding the fourth revision to Sec. 75.20(b)(3) described in the
previous paragraph, 2.3.2(e) of Appendix B of today's rule states that
in such cases, only the RATA at the failed load level needs to be
repeated (unless re-linearization of the monitor is necessary, in which
case a 3-load RATA is required). Because of this new Appendix B
provision, the following corresponding data validation provisions have
been added to Secs. 75.20(b)(3)(vii)(A) and 75.20(b)(3)(vii)(B): (1)
upon failure of the RATA at the particular load level, the length of
the new recertification test period is not 720 unit operating hours,
but is equal to the number of hours remaining in the original
recertification test period at the time of test failure; and (2) data
invalidation is prospective, beginning with the hour of failure of the
RATA at the particular load level; therefore, conditionally valid data
recorded prior to the test failure at the particular load level are not
invalidated. Finally, in response to the comments received, a new
paragraph, (b)(3)(vii)(E), has been added to Sec. 75.20 to address the
issue of trial RATA runs and pre-test gas injections. Section
75.20(b)(3)(vii)(E) allows pre-test trial gas injections and pre-RATA
runs to be done during the recertification period, for the purpose of
optimizing the performance of the monitoring system. A trial run or
injection will not affect the status of previously-recorded
conditionally valid data, provided that: (1) the results of the trial
run are within the Appendix A specifications for a passed linearity
test or RATA (i.e., for a trial gas injection, within 5% or
5 ppm of the reference gas or, for a trial RATA run, if the average
reference method and the average CEMS readings differ by no more than
10% of the reference method value, or 15 ppm,
or 0.02
lb/mmBtu, or 1.5% H2O, as applicable); (2) no
adjustments are made
[[Page 28576]]
to the calibration of the CEMS following the trial run, other than the
adjustments allowed under section 2.1.3 of Appendix B; and (3) the CEMS
is not repaired, re-linearized, or reprogrammed after the trial run. As
long as these conditions continue to be met, the CEMS can be further
optimized without data loss. However, if, for any trial run or
injection the conditions are not met, the trial run or injection is
treated as a failed or aborted linearity check or RATA and the
applicable provisions in Secs. 75.20(b)(3)(vii)(A) and
75.20(b)(3)(vii)(B) pertaining to aborted or failed recertification
tests must be followed.
2. Data Validation for RATAs and Linearity Checks
Background: EPA proposed rules for CEMS data validation prior to
and during the periodic linearity tests and RATAs required by part 75.
These new provisions were found in proposed sections 2.2.3 and 2.3.2 of
Appendix B. According to these provisions, a linearity test or RATA
could not be started if the CEMS were operating ``out-of-control'' with
respect to any of its other daily, semiannual, or annual quality
assurance tests. Prior to the test, both routine and non-routine
calibration adjustments, as defined in proposed section 2.1.3 of
Appendix B, would be permitted. During the linearity or RATA test
period, however, no adjustment of the monitor would be permitted except
for routine daily calibration adjustments following successful daily
calibration error tests. For 2-level and 3-level flow RATAs, no
linearization of the monitor would be permitted between load levels. If
a linearity check or RATA was failed or aborted due to a problem with
the monitor, the monitor would be declared out-of-control as of the
hour in which the test is failed or aborted. Data from the monitor
would remain invalid until the hour of completion of a subsequent
successful test of the same type.
The proposed rule also attempted to clarify the way in which
linearity and RATA test results are to be reported to EPA in the
electronic quarterly report required under Sec. 75.64. Proposed
sections 2.2.3 and 2.3.2 of Appendix B specified that only the results
of completed and partial tests which affect data validation would have
to be reported. That is, all completed passed tests, all completed
failed tests, and all tests aborted due to a problem with the CEMS
would have to be included in the quarterly report. Therefore, aborted
test attempts followed by corrective maintenance, re-linearization of
the monitor, or any other adjustments other than those allowed under
proposed section 2.1.3 of Appendix B would have to be reported.
However, tests which are aborted or invalidated due to problems with
the calibration gases or reference method or due to operational
problems with the affected unit(s) would not need to be reported,
because such runs do not affect the validation status of emission data
recorded by the CEMS. In addition, aborted RATA attempts which are part
of the process of optimizing a monitoring system's performance would
not have to be reported, provided that in the period from the end of
the aborted test to the commencement of the next RATA attempt: (1) no
corrective maintenance or re-linearization of the CEMS was performed,
and (2) no adjustments other than the calibration adjustments allowed
under proposed section 2.1.3 of Appendix B were made. However, such
aborted RATA runs would still have to be documented and kept on-site as
part of the official test log.
Today's rule finalizes the CEMS data validation requirements for
RATAs and linearity checks. The final rule has been modified from the
proposal, based on comments received.
Discussion: EPA received comments on the proposed data validation
procedures for RATAs and linearity checks from one state air regulatory
agency, two utilities and one utility regulatory response group. Two of
the commenters found the proposed rule language defining the allowable
pre-test adjustments to be inconsistent with the preamble language
found at 63 FR 28075. The commenters noted an apparent contradiction
between the preamble statement that there is ``no significant risk in
allowing pre-RATA adjustments provided that the monitor's accuracy
between successive RATAs can be reasonably established'' and the rule
language in section 6.5(a)(1) of Appendix A that ``no adjustments,
linearizations or reprogramming of the CEMS other than the calibration
adjustments described in section 2.1.3 of Appendix B to this part, are
permitted prior to and during the RATA test period.'' Both commenters
expressed concern that this proposed rule language appeared to exclude
important activities such as re-linearization of a flow monitor (see
Docket A-97-35, Items IV-D-20, IV-G-2). Another commenter also objected
to the proposed language in section 6.5(a)(1) of Appendix A, stating
that technicians need to be able to perform evaluations and adjustments
of flow and gas measurement systems prior to conducting a RATA (see
Docket A-97-35, Item IV-G-3). Another commenter took issue with the
provisions in proposed sections 2.2.3 and 2.3.2 of Appendix B which
allow ``non-routine'' adjustments to be made prior to linearity tests
and RATAs. The commenter especially objected to the idea of allowing
adjustments in a direction away from the reference gas tag value,
believing that this compromises the integrity of the audit and sets an
``unfortunate precedent'' (see Docket A-97-35, Item IV-D-11).
Today's rule finalizes the data validation provisions for linearity
checks and RATAs in sections 2.2.3 and 2.3.2 of Appendix B. Based on
the comments received, EPA has made substantive revisions to the
proposed rule in an attempt to clarify the allowable pre-test
adjustments and the rules for validating the CEMS data. Today's rule
specifies that when a linearity check or RATA is due, the owner or
operator has three options. First, the test may be done ``cold,'' with
no pre-test adjustments of any kind. Second, the test may be done after
making only the routine or non-routine calibration adjustments allowed
under section 2.1.3 of Appendix B. Under this second option, trial gas
injections and preliminary RATA runs are allowed, followed by
additional adjustments (if necessary) within the limits of section
2.1.3 of Appendix B, to optimize the monitor's performance. The trial
runs or injections need not be reported, provided that they meet the
acceptance criteria for trial RATA runs and gas injections in
Sec. 75.20(b)(3)(vii)(E) (see the section of this preamble entitled
``Data Validation During Monitor Certification and Recertification''
for further discussion of these acceptance criteria). If the acceptance
criteria are not met, the trial run is counted as a failed or aborted
test. Third, the CEMS may be repaired, re-linearized or reprogrammed
prior to the quality assurance test. In this case, the CEMS may either
be considered out-of-control from the hour of commencement of the
corrective maintenance, re-linearization or reprogramming until
completion of the required quality assurance test or the owner or
operator may follow the data validation procedures in Sec. 75.20(b)(3)
upon completion of the necessary corrective maintenance, re-
linearization, or reprogramming.
EPA believes that the revisions to sections 2.2.3 and 2.3.2 of
Appendix B address the commenters' concerns about pre-test adjustments.
For example, if, at the time of a scheduled flow RATA, the owner or
operator decides to re-linearize the primary flow monitor to optimize
its performance, this would be permissible under the third option
above. However, re-linearization of a flow monitor
[[Page 28577]]
triggers a requirement to perform a 3-load RATA. Therefore, if the
monitor is declared out-of-control from the hour of the re-
linearization until the hour of completion of the 3-load RATA (as would
be required by the proposed rule), this could result in significant
data loss, since a 3-load RATA can take days (or even weeks) to
complete, depending on electrical demand. For this reason, today's rule
allows the owner or operator to use the recertification data validation
procedures in Sec. 75.20(b)(3) to supplement the quality assurance
provisions in Appendix B. In this example, if the owner or operator
opts to use the data validation procedures in Sec. 75.20(b)(3), data
from the flow monitor would be considered conditionally valid upon
completion of a ``probationary calibration error test,'' following the
re-linearization of the monitor. The procedures in
Sec. 75.20(b)(3)(vii)(E) allow for trial runs and further optimization
of the monitor prior to the RATA. If the 3-level flow RATA is then
passed in accordance with the procedures of Sec. 75.20(b)(3) and within
the allotted time frame (indicating that the re-linearization was
successful), the conditionally valid data will become quality assured
and may be used for reporting.
For the following reasons, EPA does not agree with the commenter
who opposed allowing ``non-routine'' calibration adjustments prior to a
quality assurance test. The ``non-routine'' adjustments described in
section 2.1.3 of Appendix B allow adjustments only within the
performance specifications of the instrument. When a monitor is
initially certified, it must pass several quality assurance tests, one
of which is a 7-day calibration error test. The monitor must
demonstrate, for 7 consecutive operating days, that it is capable of
meeting a calibration error specification of 2.5 percent of
the instrument span (3.0 percent for flow monitors). Once a
monitor has been certified, the ``control limits'' for daily
calibration error tests of the monitor are twice the performance
specification value, i.e., 5.0 percent of span for gas
monitors and 6.0 percent for flow monitors. Thus, when the
``non-routine'' adjustments described under section 2.1.3 of Appendix B
are made prior to a linearity test or RATA, the monitor is actually
being held to a tighter specification than is used for daily operation.
The Agency therefore does not agree that keeping the instrument's
calibration within the performance specification ``band'' at the time
of linearity tests or RATAs compromises the integrity of the audits or
sets a bad precedent. On the contrary, it demonstrates that the monitor
continues to perform in a comparable manner to its performance at the
time of initial certification. When the monitor is held to the
calibration error specification required for initial certification, the
monitor is shown to be capable of passing a linearity test or RATA.
H. Appendix D--Sulfur Dioxide Emissions From the Combustion of Gaseous
Fuels
Background: EPA proposed several revisions to the procedures in
Appendix D of part 75 for determining sulfur dioxide emissions from
gas-fired and oil-fired units. Most of the proposed revisions would
provide affected utilities with additional flexibility and sampling
options. These changes were generally supported by the comments
received and have either been finalized as proposed or with minor
revisions and clarifications. However, for gaseous fuels, EPA received
a number of significant comments concerning the proposed changes to the
definition of the term ``pipeline natural gas'' under Sec. 72.2 and
received other comments which have prompted the Agency to re-evaluate
the applicability and use of Appendix D. In response to the significant
comments received, the Agency is adopting the following final revisions
to Appendix D and to Sec. 72.2:
(1) Revised definitions of ``pipeline natural gas,'' ``natural
gas'' and ``gas-fired'' have been promulgated in Sec. 72.2;
(2) The applicability of Appendix D has been expanded to include
gaseous fuels with any sulfur content (previously, Appendix D had been
limited to gaseous fuels with a sulfur content of 20 grains per 100
scf, or less); and
(3) The methodology for determining the frequency of fuel gross
calorific value (GCV) under section 2.3 of Appendix D has been
modified.
In order to put today's revisions in context, it is necessary to
review how the Agency addressed these issues in previous rulemakings.
Section 2.4 of Appendix D of the core rules of the Acid Rain Program
issued on January 11, 1993, allowed units combusting ``natural gas''
(as defined in Sec. 72.2) to calculate SO2 mass emissions
through either: (1) fuel sulfur sampling and measurement of the fuel
flow rate by a certified fuel flowmeter; or (2) the use of a default
SO2 emission rate of 0.0006 lb/mmBtu and heat input
determined using a certified fuel flowmeter and monthly analysis for
fuel GCV. In the preamble to the January 11, 1993 rule, the Agency
stated, ``the definition of ``natural gas'' does not, therefore,
include landfill gas, digester gas, biomass, or gasified coal'' (58 FR
3590 and 3596). The Agency further stated in the preamble that,
``essentially sulfur-free fuels such as natural gas, landfill methane,
or synthetic propane'' should qualify for the use of Appendix D
methodologies. The intent of the Agency in that rulemaking was to allow
the use of a default emission rate for SO2 mass emissions
calculations for natural gas and other fuels which have a similar low
sulfur content, but not for fuels which have higher sulfur content than
natural gas. Appendix D did not effectively address how to determine
SO2 mass emissions for gaseous fuels other than natural gas.
On May 17, 1995 the Agency revised the core Acid Rain rules to add
a new definition for ``pipeline natural gas,'' and revised the
definitions of ``natural gas'' and ``gas-fired.'' The most significant
change in the definition of ``natural gas'' was the addition of the
requirement that ``natural gas'' must contain ``one grain or less
hydrogen sulfide per 100 standard cubic feet and 20 grains or less
total sulfur per 100 standard cubic feet.'' The intent of this
additional language was to clarify which gaseous fuels qualified as
``natural gas.'' The criteria used (1 grain hydrogen sulfide
(H2S) and 20 grains total sulfur) were based on contracts
and tariff sheets for pipeline natural gas regulated by the Federal
Energy Regulatory Commission (FERC). Consistent with this approach, the
Agency defined ``pipeline natural gas'' as natural gas provided by a
supplier through a pipeline. In addition, the Agency modified the
definition of ``gas-fired'' to make it clear that the use of Appendix D
was limited to units combusting ``fuel oil,'' ``natural gas,'' and
``gaseous fuels containing no more sulfur than natural gas.'' The
default SO2 emission rate of 0.0006 lb/mmBtu could only be
used for the combustion of either natural gas or a fuel with a sulfur
content no greater than natural gas. To use the default SO2
emission rate, the owner or operator was required to demonstrate that
the fuel being combusted qualified as natural gas, based on contract or
tariff values which indicate that the gas meets the criteria for
natural gas H2S content and total sulfur content.
As noted in the preamble of the proposed rule, the May 12, 1995
revisions apparently did not eliminate confusion concerning the use of
the default SO2 emission rate. The SO2 default
emission rate of 0.0006 lb/mmBtu is equivalent to approximately 0.2
grains hydrogen sulfide per 100
[[Page 28578]]
standard cubic feet (scf) of gas, when hydrogen sulfide is the sole
source of total sulfur in the gas (as is the case for refined natural
gas), or 0.2 grains total sulfur per 100 scf of gas. The Agency did not
intend that fuels with average sulfur content much higher than 0.2
grains per 100 scf should be allowed to use the default value. In this
context, the current definition of ``natural gas'' under Sec. 72.2,
which includes the term ``20 grains of total sulfur,'' is somewhat
confusing. Further, use of the 0.0006 lb/mmBtu default emission rate
for ``natural gas'' with one grain of H2S per 100 scf would
result in an approximately five-fold underestimation of SO2
emissions. Therefore, in the proposed rule, the Agency modified the
definition of pipeline natural gas to include only natural gas with a
hydrogen sulfide content less than or equal to 0.3 grains hydrogen
sulfide per 100 scf, thereby clarifying that the default emission rate
of 0.0006 lb/mmBtu could only be used for natural gas with an
appropriately low hydrogen sulfide content.
The proposed rule required documentation of the hydrogen sulfide
content of the natural gas either through quality characteristics
specified by a purchase contract or pipeline transportation contract,
through certification of the gas vendor, based on routine vendor
sampling and analysis, or through at least one year's worth of
analytical data on the fuel hydrogen sulfide content from samples taken
at least monthly, demonstrating that all samples contain 0.3 grains or
less of hydrogen sulfide per 100 standard cubic feet. For a fuel to be
classified as ``pipeline natural gas'' the fuel would, of course, first
have to meet the current definition of ``natural gas'' in Sec. 72.2,
which states, ``Natural gas means a naturally occurring fluid mixture
of hydrocarbons (e.g., methane, ethane, or propane) containing 1 grain
or less hydrogen sulfide per 100 standard cubic feet, and 20 grains or
less total sulfur per 100 standard cubic feet), produced in geological
formations beneath the Earth's surface, and maintaining a gaseous state
at standard atmospheric temperature and pressure under ordinary
conditions.''
Discussion: Several comments were received on the proposed changes
to the definition of ``pipeline natural gas,'' and comments were also
received on the current definition of ``natural gas.'' In responding to
the comments, the Agency is revising both the definition of ``pipeline
natural gas'' and ``natural gas,'' as well as making various
corresponding changes to wording in part 75 to ensure consistency
within the rule.
Two commenters were opposed to the change to the definition of
pipeline natural gas (see Docket A-97-35, Items IV-D-23 and IV-D-24).
Both commenters suggested that the requirement to document that a
gaseous fuel has 0.3 gr/100 scf of H2S, as
opposed to the previous requirement to document an H2S
content 1.0 gr/100 scf, would either disqualify some sources
currently using the default emission rate of 0.0006 lb/mmBtu or force
those sources to use means other than the contract or tariff provisions
to demonstrate that the hydrogen sulfide content of the gas is less
than 0.3 gr./100 scf. Under the proposed Appendix D revisions, any
sources disqualified from the use of the default SO2
emission rate would either be required to begin daily gas sampling of
the fuel sulfur content or would have to install an SO2
CEMS.
Two other commenters suggested that the use of two sulfur content
criteria in the natural gas definition (the dual criteria of 1 grain
H2S and 20 grains total sulfur per 100 scf) was confusing
and could lead to misinterpretation of which fuels could be classified
as either ``pipeline natural gas'' or ``natural gas'' under Sec. 72.2
(see Docket A-97-35, Items IV-G-3 and IV-G-10). One of these commenters
suggested that the definition of natural gas should be changed to
incorporate only the requirement of 20 grains or less of total sulfur
per 100 scf. If this suggestion were followed, a source with 20 grains
total sulfur per 100 scf could use an SO2 emission rate of
0.0006 lb/mmBtu, thereby underestimating SO2 emissions 100-
fold. This would clearly be unacceptable and contrary to the Agency's
intent since the initial adoption of Appendix D.
One commenter suggested that the requirement to determine the fuel
GCV on the same frequency as sulfur sampling be removed from Appendix D
and that monthly GCV sampling be allowed in all cases (see Docket A-97-
35, Item IV-D-20). The commenter claimed that the variability of fuel
GCV is not necessarily the same as the variability of the sulfur
content of a fuel.
1. Summary of EPA Analysis of Appendix D Gaseous Fuel SO2
and Heat Input Methodologies
In responding to the comments received, the Agency first attempted
to quantify the SO2 emissions from the combustion of gaseous
fuels under the current Acid Rain rules. A data analysis was performed,
assuming that the vast majority of SO2 emissions from the
combustion of gaseous fuel are from affected units reporting gas as the
primary fuel. The data analysis (which was limited to 1997 emission
data) indicates the following: (1) there are 582 units that list gas as
the primary fuel (representing about 30% of the units in the program);
(2) these 582 units accounted for approximately 10% of the total heat
input reported for all Acid Rain-affected units; (3) the total amount
of SO2 emitted by these 582 units was 14,728 tons in 1997 or
0.1% of the total SO2 mass emissions in the program; and (4)
of the 14,728 tons of SO2 emitted by the 582 units, 12,844
tons were from only 17 units and the remaining 1,884 tons were from the
remaining 565 units (see Docket A-97-35, Item IV-A-4). Thus it appears
that gas-fired units account for a significant portion of the total
heat input and electrical generation under the Acid Rain Program, but
contribute only a fraction of one percent of the total SO2
emissions. Note, however, that even though emissions from the
individual gas-fired units are very small, the cumulative emissions
from all 582 units are roughly equivalent to the typical SO2
emissions from a coal-fired unit. For this reason, the method of
calculating the SO2 emissions from the gas-fired units must
be sufficiently accurate to prevent significant underestimation of
emissions. The methodology in the current rule allows the default
SO2 emission rate of 0.0006 lb/mmBtu to be used for all
types of natural gas. As previously noted, the default emission rate
corresponds to 0.2 grains of H2S per 100 scf, but the
definition of natural gas allows fuels with up to 1.0 grain of
H2S and 20 grains of total sulfur to be classified as
``natural gas.'' In view of this, it is possible that the reported
cumulative SO2 emissions reported in 1997 for the 582 gas-
fired units may be inaccurate by several orders of magnitude. This
level of uncertainty in reported emissions is unacceptable in an
allowance trading program such as the Acid Rain Program. Consequently,
a more representative method is needed to characterize the actual
sulfur content of the gaseous fuels combusted by Acid Rain-affected
units.
The Agency also performed an analysis of all available gaseous fuel
GCV sampling data from all Acid Rain sources reporting such data in
1997. Gaseous fuels were analyzed in two categories, pipeline natural
gas and ``other'' gas. Only 14 Acid Rain sources reported sampling and
analysis of ``other'' gases in 1997. The data analysis showed that for
275,669 pipeline natural gas analyses, the average fuel GCV was 1023
Btu/ft3 and the 95th
[[Page 28579]]
percentile value was 1051 Btu/ft3, a difference of only
2.6%. For the ``other'' gaseous fuels, the average GCV from 14,282
analyses was 819 Btu/ft3 and the 95th percentile value was
1118 Btu/ft3, a difference of approximately 26%. This
demonstrates the consistency of the GCV of pipeline natural gas and the
high variability of the few ``other'' gaseous fuels for which Appendix
D is currently being used (see Docket A-97-35, Item IV--A-1).
In finalizing today's rule, the Agency also considered the
potential impact of the revisions to Appendix D on the new Subpart H of
part 75 (which establishes the requirements for monitoring of
NOX mass emissions). Currently, the provisions of Subpart H
are being used by the Ozone Transport Commission (OTC) NOX
Budget Program and, in the future, Subpart H may be adopted as part of
an implementation plan as a means of complying with the NOX
SIP Call (see 63 FR 57356). Subpart H of part 75 allows heat input
determined by the procedures of Appendix D to be used in determining
NOX mass emissions from gas-fired units. In the process of
implementing part 75 and the OTC NOX Budget Program, the
Agency has encountered an increasing number of sources that combust
gaseous fuels which neither qualify as ``pipeline natural gas'' or
``natural gas.'' These fuels include refinery gas, landfill gas,
digester gas, coke oven gas, process gas, propane liquified gas,
liquified petroleum gas, blast furnace gas and coal-derived gas. Under
the previous version of part 75 units combusting these fuels would
either be required to install SO2 and stack flow monitoring
systems or would have to petition the Agency to use Appendix D. It is
likely that under the OTC NOX Budget Program and under the
SIP call, the number of sources combusting these ``other'' gaseous
fuels and required to monitor heat input using part 75 methods will
increase significantly. The Agency anticipates that the owners or
operators of the majority of these sources would petition to use the
procedures of Appendix D to determine heat input used for
NOX mass calculations, in lieu of installing CEMS. However,
the current Appendix D does not address how to determine hourly heat
input for gaseous fuels with variable GCV. The Agency also notes that
any error in hourly heat input determined under Appendix D would result
in a corresponding and equal error in the reported NOX mass
emissions. It is therefore particularly important to establish
consistent and easily implementable heat input monitoring criteria for
all types of gaseous fuels under Appendix D. Clear, flexible and
reasonable requirements for gaseous fuel GCV sampling and analysis are
needed.
Based on the comments received and the data analyses described
above, the Agency has concluded that:
The use of the default SO2 emission rate of
0.0006 lb/mmBtu is only appropriate for natural gas with a
documented contractual or tariff limit of 0.3 grains hydrogen
sulfide per hundred standard cubic feet or for fuels which are
demonstrated to have a similar low total sulfur content.
For natural gas with a contract or tariff hydrogen
sulfide limit up to 1.0 grain of hydrogen sulfide per 100 standard
cubic feet, or for fuels which are demonstrated to have a similar
low total sulfur content, a site-specific default SO2
emission rate should be allowed, which more closely represents the
potential SO2 emission rate for that fuel.
The applicability of Appendix D should be expanded to
include any gaseous fuel (rather than limiting it to fuels with a
total sulfur content 20 grains per 100 scf. For gaseous
fuels with highly variable sulfur content, hourly sampling using
advanced monitoring such as on-line gas chromatography should be
required. The frequency of determination of the GCV of a gaseous
fuel should be independent of the requirements for sulfur sampling
and should be based solely on the variability of the GCV.
2. Changes to the Definitions of ``Pipeline Natural Gas'' and ``Natural
Gas''
As previously stated, the Agency is revising the definitions of
``pipeline natural gas'' and ``natural gas'' in Sec. 72.2. Since the
definition of ``pipeline natural gas'' necessarily includes the
definition of ``natural gas'', and the definitions therefore involve
similar issues, EPA is addressing both definitions in today's final
rule. In particular, ``pipeline natural gas'' is defined in such a way
that only fuels with the appropriate sulfur content can meet the
definition and can use the default emission rate of 0.0006 lb/mmBtu.
Under the revised definition, pipeline natural gas must contain less
than 0.3 grains of hydrogen sulfide per 100 scf. Consistent with this
approach, the definition of ``natural gas'' is revised so that only the
requirement for the hydrogen sulfide content to be less than one grain
per 100 scf remains, and the requirement for the total sulfur content
to be 20 grains per 100 scf is deleted. Further, EPA is
adding to both definitions a requirement that hydrogen sulfide content
must account for at least 50% (by weight) of the total sulfur in the
fuel. This ensures that a fuel with a high total sulfur content, but a
relatively small hydrogen sulfide content, cannot qualify to use a
default SO2 emission rate. The Agency believes that in
general, any ``natural gas'' with 1.0 grain of
H2S/100 scf will also meet the requirement that hydrogen
sulfide must account for 50% of the total sulfur in the
fuel. However, the Agency reserves the right to request that the owner
or operator provide data to demonstrate compliance with this latter
requirement. Finally, EPA is adding a requirement to the ``natural
gas'' definition that the gas must have either a methane content of at
least 70% or the same GCV as methane (950 to 1100 Btu/scf). This
requirement ensures that the gas will have a stable GCV, consistent
with the Appendix D provisions which allow monthly GCV sampling for
either pipeline natural gas or natural gas. In today's rule, the
requirements for documenting that a fuel qualifies as ``pipeline
natural gas'' or ``natural gas'' are essentially the same as the
proposed rule. The three principal ways of providing the necessary
documentation are: (1) gas quality characteristics specified in a
purchase contract or pipeline transportation contract; (2)
certification by the gas vendor, based on routine sampling and analysis
for at least one year; and (3) at least one year of analytical data on
the fuel characteristics, derived from monthly (or more frequent)
samples. In addition, sections 2.3.5 and 2.3.6 of Appendix D of today's
rule allow the owner or operator to conduct a 720 hour demonstration of
the fuel's sulfur and GCV characteristics (see Items 5 and 6 in this
section, below).
EPA believes that the revised definitions of ``pipeline natural
gas'' and ``natural gas'' will: (1) apply to the low sulfur fuel
combusted by the vast majority of the sources in the Acid Rain Program;
(2) be documentable, in most cases, based on contract or tariff
provisions without other types of demonstrations; and (3) allow most
sources currently using 0.0006 lb/mmBtu as a default to continue using
that default value or to use an alternative, site-specific default
value that will not underestimate SO2 emissions.
3. Changes to the Methodology for Calculating SO2 Emissions
Under Appendix D
Today's rule adopts a two-tiered approach to the use of default
SO2 emission rates, depending on whether a fuel qualifies as
``pipeline natural gas'' or as ``natural gas.'' First, if the owner or
operator can demonstrate that the fuel combusted at a unit has
0.3 grains of hydrogen sulfide per 100 scf, the default
SO2 emission rate of 0.0006 lb/mmBtu may be used. Second,
the rule allows units combusting gaseous fuels
[[Page 28580]]
with >0.3 grains, but 1.0 grain of hydrogen sulfide per 100
scf to calculate a site-specific default SO2 emission rate,
as suggested by two of the commenters (see Docket A-97-35, Items IV-D-
23 and IV-D-24). The method of calculating the default value is based
on the actual conversion of hydrogen sulfide in natural gas to
SO2 and utilizes a realistic fuel GCV value of 1023 Btu/scf
(from the previously-discussed data analysis, above). The result is a
simple equation which converts hydrogen sulfide in natural gas to an
SO2 emission rate in lb/mmBtu.
4. Changes to the Applicability of Appendix D
In the process of considering comment on the definitions of
``pipeline natural gas'' and ``natural gas'' the Agency also re-
evaluated the appropriateness of limiting the applicability of Appendix
D to gaseous fuels with 20 grains of total sulfur per 100
scf. While EPA does not believe that a gaseous fuel with 20 or more
grains of total sulfur per 100 scf should be allowed to use a default
SO2 emission rate, neither does the Agency believe that
units combusting such fuel should be excluded from using Appendix D.
Currently, technologies such as on-line gas chromatography allow
accurate fuel sulfur analysis to be performed over intervals as short
as one hour. This ability to perform hourly sampling is comparable to a
CEMS in accuracy, precision and timeliness. Therefore, today's rule
removes the 20 grains of sulfur per 100 scf restriction on the use of
Appendix D for gaseous fuels.
5. Changes to the Method of Determining the Sulfur Content Sampling
Frequency for Gaseous Fuels
Section 2.3.6 of Appendix D of today's rule also includes a general
procedure for determining the appropriate frequency of sulfur content
sampling for any gaseous fuel which is transmitted by a pipeline. The
procedure consists of a 720 hour demonstration, similar to the one in
section 2.3.3.4 of Appendix D in the proposed rule. The results of the
720 hour demonstration may first be used to determine first if a fuel
qualifies as either ``pipeline natural gas'' or ``natural gas'' or as
``other'' gaseous fuel, and then to determine the appropriate total
sulfur sampling frequency for the fuel. If a fuel qualifies as pipeline
natural gas, the default SO2 emission rate of 0.0006 lb/
mmBtu could be used in lieu of fuel sampling. If the fuel qualifies as
``natural gas'' (but not pipeline natural gas), a site-specific default
SO2 emission rate may be used, based on the highest hourly
hydrogen sulfide concentration recorded during the 720 hour
demonstration. After a fuel qualifies as ``natural gas,'' the owner or
operator is required to sample the H2S content at least once
monthly for a year following the 720 hour demonstration. The default
emission rate for the demonstration may continue to be used, provided
that none of the samples taken during the year exceeds 1.0 grain/100
scf of H2S. All ``other'' gaseous fuels would require either
daily or hourly sampling of the total sulfur content, depending on the
fuel sulfur variability.
6. Changes to the Method of Determining the GCV Sampling Frequency for
Gaseous Fuels
Accurate determinations of heat input are important for the
calculation of SO2, NOX and CO2 mass
emissions under Appendices D, E, G and Subpart H of part 75. EPA has
found that fuels such as refinery gas, digester gas, landfill gas, coke
oven gas, process gas, propane liquified gas, liquified petroleum gas,
blast furnace gas, and coal derived gas can have highly variable GCV
(see Docket A-97-35, Item IV-A-4). For these fuels a standardized test
for determining the appropriate GCV sampling and analysis frequency is
essential. One commenter on the proposed rule noted that in many cases
the GCV of a fuel is relatively stable over a period of time, and
sampling each month for fuel heat content is adequate (see Docket A-97-
35, Item IV-D-20). The Agency agrees that this is true in many cases
(e.g., for natural gas), but not often for the fuels listed above. The
Agency also notes that the emissions data determined under Appendix D
must be as reliable, precise, timely and accessible as data from a
CEMS.
In view of this, the Agency is revising the criteria for
determining the frequency of GCV sampling for gaseous fuels. For any
fuel which meets the revised definition of either ``pipeline natural
gas'' or ``natural gas,'' this ensures that the fuel will have a stable
heat content and therefore monthly sampling is appropriate. For fuels
which do not qualify as either pipeline natural gas or natural gas and
for which ``as-delivered'' fuel sampling and analysis is not performed,
the same 720 hour demonstration described in item 5 in this section,
above, for fuel sulfur sampling will also be used to determine the
appropriate GCV sampling and analysis frequency. The heat content of
the fuel will be determined for each hour in the 720 hour period. For
units that switch fuels seasonally or when process changes occur (such
as refinery fuel gas combustion units) the 720 hour demonstration
period must also include data which characterizes the variability of
the fuel during the seasonal or process changes. The results of the 720
hour demonstration will be used to determine the average heat content
of the fuel and the standard deviation. As explained in section 2.3.5
of Appendix D in today's rule, depending on the results of the
demonstration, the owner or operator will perform either daily or
hourly sampling of the fuel GCV.
I. Electronic Transfer of Quarterly Reports
Background: For the reasons discussed in the preamble to the
proposed rule revisions (63 FR 57356, May 21, 1998), EPA proposed
changes to Sec. 75.64(f) concerning the method of submitting quarterly
reports. The proposal provided that all quarterly reports would have to
be submitted to EPA by direct computer-to-computer electronic transfer
via modem and EPA-provided software, unless otherwise approved by the
Administrator. This requirement was to begin with the quarterly report
for the first quarter of the year 2000.
Discussion: EPA received one comment (see Docket A-97-35, Item IV-
D-20) which opposed the proposed requirement based on difficulty in
receiving electronic transfer of quarterly reports due to technical
difficulties with EPA computers which may arise due to year 2000
conversion difficulties or other technical problems relative to
electronic transfer of quarterly reports at times when EPA computers
may not be accessible. Concern was expressed regarding the requirement
for utilities to provide proof that they attempted to transfer their
reports on time but were unsuccessful due to the inability to gain
access to the EPA computer system.
Based on the comment received, EPA has decided to change the
electronic reporting requirement in Sec. 75.64(f) so that beginning
with the quarterly report for the first quarter of the year 2001, all
quarterly reports must be submitted to EPA by direct computer-to-
computer electronic transfer via modem and EPA-provided software,
unless otherwise approved by the Administrator. This will ensure
adequate time for all parties to address the year 2000 concerns. EPA
notes that its system has already undergone testing and changes to
accommodate year 2000 concerns.
J. Bias, Relative Accuracy and Availability Determinations
Background: The preamble to the proposed rule described the
findings of studies performed to evaluate the
[[Page 28581]]
provisions for the bias test, relative accuracy, and monitor
availability trigger conditions as required by Secs. 75.7 and 75.8.
Issues concerning the bias relative accuracy, and monitor availability
provisions in the core Acid Rain rules had been raised in litigation
(Environmental Defense Fund v. Carol M. Browner, No. 93-120; et al.
D.C. Cir., 1993). The purpose of these studies was to address these
issues (see 63 FR 28197). The preamble of the proposed rule explained
how these findings led to the Agency's proposed determinations to
retain the current rule provisions concerning these matters. There were
no comments objecting to the substance of the proposed determinations.
Therefore, for the reasons set forth in the preamble to the proposed
rule, EPA is adopting the proposed rule revisions as final, with the
result that Secs. 75.7 and 75.8 are removed and reserved. Moreover,
since none of the issues raised concerning the bias, relative accuracy,
and monitor availability provisions in the core Acid Rain rules were
raised in any comments on the studies, EPA maintains that those
litigation issues have been resolved.
Discussion: Two comments were received. One (see Docket A-97-56,
Item IV-D-01) supported the proposed determinations. The second comment
(see Docket A-97-56, Item IV-D-02) expressed concern that the bias test
studies performed in response to Sec. 75.7 did not evaluate
overestimation in flow measurements. The commenter urged EPA to
complete its ongoing work as quickly as possible on a separate
rulemaking to resolve the commenter's flow overestimation concerns. The
Agency is pursuing the separate rulemaking recommended by the
commenter.
K. Appendix I--Proposed Optional Stack Flow Monitoring Methodology
Background: EPA proposed to add an F-factor/fuel flow method in
Appendix I to part 75 as an excepted method to measure volumetric flow
directly with a flow monitor. The Agency proposed this method based on
information provided by affected utilities, and based on the assumption
that the new excepted method would be used by a significant number of
units as a cost-effective option to a volumetric flow monitor. This
method would allow fuel flow measurement with a gas or oil flowmeter,
fuel sampling data, CO2 (or O2) CEMS data, and F-
factors to determine the flow rate of the stack gas rather than a
volumetric flow monitor. The F-factor/fuel flow method would be
available for use by oil-fired and gas-fired units, as defined under
Sec. 72.2, provided that they only burn natural gas and/or fuel oil.
For these units, EPA believes that the proposed method would provide
acceptably accurate measurements of volumetric flow. However, adoption
of the proposed method would require the Agency to develop regulations
imposing additional reporting and recordkeeping requirements for those
units that used this option. This would also place a burden on software
vendors to develop software to allow for electronic data reporting of
the required data elements.
Discussion: A few commenters stated generally that they supported
the Appendix I option, while two other commenters stated generally that
the method should be allowed for other types of units or simplified
(see Docket A-97-56, Items IV-D-9, 23, and 24, and IV-G-2 and -8).
However, utilities have submitted late comments that suggest that the
utilities (including those originally interested in an F-factor/fuel
flow method) are in fact unlikely to use the Appendix I option at this
time (see Docket A-97-56, Item IV-G-13). Based on a review of Acid Rain
program databases, only about 150 units affected by the Acid Rain
Program could potentially take advantage of this option. In contrast,
there are a significant number of units that implement the other
generally available excepted methods under Appendices D and E to Part
75 (currently, approximately 540 different units report using one or
both of these methods).
As discussed above there would be substantial effort involved for
EPA, utilities and software vendors to implement a new generally
available option such as proposed Appendix I. As discussed in the
preamble to the proposed rule, the annual savings on a per unit basis
for Appendix I units are at most $10-15,000 over the measurement of
volumetric flow directly with a flow monitor. The actual cost savings
would be less because other provisions of today's rule revise flow
monitor quality assurance requirements and significantly reduce the
costs of using a flow monitor. Given the relatively small amount of
savings on a per unit basis, the indication that no units would use the
option at this time, and the significant burden on all interested
parties in implementing a generally available option in Appendix I, the
Agency has determined not to adopt Appendix I.
However, if the owner or operator of a unit decides at some time in
the future to use this type of procedure for measuring flow, the
designated representative of the unit may petition the Agency under
Sec. 75.66 to use this type of procedure on a case-by-case basis. In
such a petition, the designated representative can reference the
information used to support the proposed Appendix I procedure (see 63
FR 28113-28115, May 21, 1998, for further details on the information
used to develop proposed Appendix I). The Agency will evaluate the
petition on the merits at that time.
L. Subpart H--Clarifications to NOX Mass Monitoring
Requirements
Background: By notice of proposed rulemaking (NPR, proposal, or
``proposed SIP call'') (62 FR 60318, November 7, 1997) and by
supplemental notice (SNPR or supplemental proposal) (63 FR 25902, May
11, 1998), EPA proposed to find that NOX emissions from
sources in 22 states and the District of Columbia, will significantly
contribute to nonattainment of the 1-hour and 8-hour ozone National
Ambient Air Quality Standards (NAAQS), or will interfere with
maintenance of the 8-hour NAAQS, in one or more downwind states
throughout the eastern United States.
In October, 1998 (63 FR 57356, October 27, 1998), EPA finalized the
proposed SIP call rulemaking. The final rule specified dates by which:
(1) the affected states must submit State Implementation Plan revisions
to reduce NOX emissions to eliminate the amounts of
NOX emissions that contribute significantly to
nonattainment, or that interfere with maintenance, downwind; and (2)
the affected sources must implement the measures chosen by the states
to achieve the required NOX emission reductions.
The provisions of the October 27, 1998 final rule allow each state
to determine the best way to achieve the necessary NOX
emission reductions. Consistent with the Ozone Transport Assessment
Group's recommendation to achieve NOX emissions decreases
primarily from large stationary sources in a trading program, EPA
promulgated a model rule for the implementation of such a trading
program as 40 CFR part 96 (``Part 96'') in the October 27, 1998
rulemaking.
If the states should choose to create a NOX mass trading
program and to adopt the provisions of the Part 96 model rule,
Sec. 96.70 requires the monitoring and reporting of NOX mass
emissions to be done in accordance with either: (1) Subpart H of 40 CFR
part 75, the Acid Rain CEM Rule (``Part 75''); or (2) for qualifying
low mass-emission units, Sec. 75.19 of Part 75. However, even if a
state should choose not to participate in such a trading program, the
October 27, 1998 rule still requires the monitoring provisions of
Subpart H to be used by
[[Page 28582]]
a core group of sources (large industrial boilers and turbines, and
large boilers and turbines used for the generation of electricity for
sale) if the NOX mass emission reduction program for that
state includes requirements to control such sources. To support these
NOX mass emission reduction programs and rulemakings, EPA
promulgated both Subpart H of Part 75 and the low mass emission unit
provisions in Sec. 75.19 of Part 75 as part of the October 27, 1998
rulemaking.
In the November 7, 1997 proposed SIP Call rule, EPA would have
required the affected units in a Federal or state NOX mass
emission reduction program to report NOX emissions on a
year-round basis and also to quality assure the NOX emission
data in accordance with the provisions of Part 75 on a year-round
basis. However, in response to comments on the proposed rule, EPA
modified Subpart H of Part 75 so that states could choose to allow
sources that were not subject to the requirements of Title IV of the
Clean Air Act (the Acid Rain Program) to monitor and report either on a
year round basis or on an ozone season only basis. Therefore, the
October 27, 1998 final rule provides for the monitoring and reporting
of NOX mass emissions either on an annual basis or during
the ozone season, when this is allowed by the governing state or
Federal rule.
If a state or Federal NOX mass emission reduction
program were to allow ``ozone season only'' monitoring and reporting,
there would be an issue related to data quality at the start of each
ozone season. To address this issue, in the October 27, 1998 final
rule, EPA included a provision in Sec. 75.74(c) of Subpart H, which
requires the continuous emission monitoring systems used to provide the
NOX mass emission data to be recertified prior to the start
of each ozone season.
Although Subpart H was proposed on May 21, 1998 as part of the Acid
Rain CEM Rule revisions, it was finalized several months ahead of
today's rulemaking, in order to support the SIP call. In the preamble
to the October 27, 1998 final rule (63 FR 57467), EPA explained its
intention to, where possible, make the provisions of Subpart H
consistent with any other changes that EPA promulgated as a result of
the May 21, 1998 proposed revisions to Part 75. EPA has re-examined the
provisions of Subpart H within the context of today's final rulemaking.
The Agency has found that a few minor clarifications of the regulatory
language in Subpart H and the addition of one new paragraph are needed
for consistency with today's final rule. The textual clarifications
affect Secs. 75.70(f)(1)(iv), 75.71(b) and 75.71(d)(2). The new
paragraph is found at Sec. 75.70(g)(6). In addition to these minor
corrections, EPA has found that certain provisions in Sec. 75.74(c),
pertaining to sources that monitor and report data only in the ozone
season, are substantially inconsistent with sections of today's final
rule (particularly the new CEM data validation provisions). The Agency
has also found an instance in which the text of Sec. 75.74(c) is
internally inconsistent and a second instance in which a statement in
the October 27, 1998 preamble does not agree with the regulatory
language in Sec. 75.74(c). In view of these considerations, today's
rulemaking revises Sec. 75.74(c), in order to make Subpart H more
consistent with the rest of Part 75 and to resolve the apparent
discrepancies and inconsistencies in the text of Sec. 75.74(c).
Discussion of Changes: As previously stated, Subpart H requires
owners or operators of sources that monitor and report only during the
ozone season to recertify their CEM systems prior to each ozone season.
EPA put this requirement in Subpart H because the Agency believes that
for sources which are not required to monitor and report on a year-
round basis, substantial quality assurance testing of the CEMS prior to
the ozone season is essential to validate the emission data at the
beginning of the ozone season. However, in the light of today's
rulemaking, the use of the word ``recertification'' in Sec. 75.74(c) of
Subpart H is regarded as inaccurate and inappropriate and does not
properly communicate the Agency's intent. In Sec. 75.20(b) of today's
final rule, the term ``recertification'' has been carefully defined, so
that it is limited to major changes to a CEMS which may affect its
ability to accurately measure emissions. Since in most instances
sources will be testing existing CEMS that have not undergone major
changes, EPA believes that this is more consistent with either
diagnostic testing or on-going quality assurance testing rather than
recertification. Therefore, in today's final rule, all of the
references in Sec. 75.74 to ``recertification testing'' of CEMS prior
to the ozone season have been replaced with terms such as ``diagnostic
testing'' or ``quality assurance testing,'' which properly convey the
Agency's intent and de-couple this testing from the formal
administrative process associated with recertification events. Since
the required pre-ozone season testing is considered to be quality
assurance (QA) or diagnostic testing rather than a recertification, the
Agency must specify which QA tests are to be performed. Section
75.74(c) therefore lists the specific quality assurance tests that are
required prior to the ozone season. For all CEM systems, a relative
accuracy test audit (RATA) is required and for all gas monitors, a
linearity check is also required. After a required linearity check or
RATA is passed, Sec. 75.74(c) requires that daily calibration error
tests and (if applicable) flow monitor interference checks begin to be
performed. These daily assessments must then continue to be performed
until the end of the ozone season.
Section 75.74(c)(5) of Subpart H, as promulgated on October 27,
1998, requires both the recording and reporting of hourly emission data
prior to the current ozone season in the time interval from the date
and hour that ``recertification'' testing of the CEM systems is
completed through the end of the ozone season. EPA believes that most
sources that choose this option would do the testing as close to the
ozone season as possible. However, there may be some instances in which
it would be difficult for a source to perform all of the testing in the
second quarter before the beginning of the ozone season. This means
that some sources for which the NOX emission data count for
compliance only during the ozone season would be required to submit
additional electronic quarterly reports outside the ozone season, if
they completed the pre-ozone season testing in the first or fourth
calendar quarter. In view of this, EPA has reconsidered the
implications of this extra reporting requirement and has concluded that
it will complicate program implementation. The Agency believes that
this complication is unnecessary. Therefore, in Sec. 75.74(c)(6) of
today's final rule, the Subpart H reporting provision for these sources
has been revised, so that only reporting of emission data in the ozone
season, from May 1 through September 30, is required. This means that
in the time period from the date and hour of completion of the required
pre-ozone season quality assurance testing of the CEM systems through
April 30 of the current year, the owner or operator is only required to
record and keep records of the hourly emission data on-site. The only
pre-ozone season data that must be reported are the results of daily
calibration error checks and flow monitor interference checks performed
in the time period from April 1 through April 30 and the results of any
linearity checks, RATAs, fuel flow meter tests and fuel sampling
performed outside of the ozone season for purposes of
[[Page 28583]]
compliance with Subpart H. This will provide the regulatory agencies
with added assurance that the CEMS data are quality-assured at the
start of the ozone season and will enable the agencies to have a
limited pre-ozone season electronic auditing capability. The
requirement to report the results of the daily assessments for the
month of April is not considered burdensome because April is in the
second calendar quarter, which is one of the two reporting quarters for
the affected sources. In fact, some affected sources may prefer to
report data for April, because it may be easier to generate an
electronic quarterly report for the entire second calendar quarter,
rather than just for the months of May and June. Therefore,
Sec. 75.74(c)(6) of today's final rule gives the owner or operator the
option to report unit operating data and emission data for the month of
April.
In reviewing the missing data provisions of Subpart H, EPA found a
discrepancy between the Agency's stated intent in the preamble to the
October 27, 1998 final rule and the regulatory language in
Sec. 75.74(c)(6)(i). The preamble states that ``[h]istorical lookback
periods for missing data only need to include data from the ozone
season'' (63 FR 57483, October 27, 1998). However, the rule language in
Sec. 75.74(c)(6)(i) does not state this explicitly, and could be
misinterpreted. The rule language states that all ``quality assured
data, in accordance with paragraph (c)(2) or (c)(3) of this section''
are to be used for missing data purposes. This could be interpreted as
meaning that the data recorded outside the ozone season, in the time
period between completion of the pre-ozone season quality assurance
testing of the CEM systems and May 1, are to be included in the missing
data lookback periods. This is not what EPA intends; rather, the
statement cited above from the October 27, 1998 preamble accurately
reflects the Agency's position. Therefore, Sec. 75.74(c)(7) of today's
rule clearly states that for purposes of missing data substitution,
only data recorded during the ozone season will be used for the
historical missing data lookback periods.
Finally, EPA has examined the quality assurance provisions of
Subpart H in view of the many substantial changes to the quality
assurance and data validation provisions of Part 75 in today's
rulemaking. The Agency has concluded that, in light of the many changes
that have been made to Part 75, the general references in Subpart H to
the quality assurance provisions in Sec. 75.21 and appendix B to Part
75 and references to the data validation procedures in Sec. 75.20 could
be clarified to make the requirements easier to understand,
particularly for sources that report data only during the ozone season.
There are several reasons for this.
First, sections 2.2.4 and 2.3.3 in appendix B of today's final rule
provide ``grace periods'' in which late or missed QA tests can be
completed. For linearity checks, the grace period is 168 unit operating
hours after the end of the quarter in which the test is due. For RATAs,
the grace period is 720 unit operating hours after the end of the
quarter in which the RATA is due. Because the grace periods in Part 75
are in terms of unit operating hours, they can sometimes extend for
more than one calendar quarter beyond the quarter in which the QA test
was due (particularly for infrequently-operated or seasonally-operated
units). Consequently, the Part 75 grace period provisions in appendix B
are considered to be inappropriate for sources that report emissions
data only during the ozone season. Without a complete record of unit
operation for each year, the regulatory agency will be unable to
determine whether the required QA tests have been completed within the
allotted grace period.
Second, Sec. 75.20(b)(3) of today's final rule provides
``conditional'' data validation procedures for CEMS recertifications.
These provisions allow a probationary period following a
recertification event, during which data from a CEMS are assigned a
``conditionally valid'' status. Provided that all recertification tests
are passed within the probationary period, with no test failures,
Sec. 75.20(b)(3) allows the conditionally valid data to be reported as
quality-assured. Today's rule also allows these data validation
procedures to be used for routine linearity checks and RATAs, in cases
where significant repair, adjustment or reprogramming of the CEMS is
done prior to the QA test. The maximum allowable length of the
probationary period is 168 unit operating hours for a linearity check
and 720 unit operating hours for a RATA. Once again, because these
probationary periods are in terms of unit operating hours, they can
extend outside the current calendar quarter, into the next quarter and
possibly beyond the next quarter. Therefore, for sources that report
only during the ozone season, some restrictions must be placed on the
use of the conditional data validation procedures in Sec. 75.20(b)(3).
In view of the above considerations, EPA has revised Subpart H to
make it clear which of the Part 75 QA and data validation provisions
are applicable to sources that report only in the ozone season and
which provisions are inapplicable. The Agency has replaced the general
references in Subpart H to the quality assurance provisions of
Sec. 75.21 and appendix B and the references to the provisions of
Sec. 75.20 with specific language that delineates the exact QA tests
required during each ozone season. Section 75.74(c)(3) of today's rule
also contains specific data validation provisions for sources that
report only during the ozone season. To the extent possible, these QA
and data validation provisions have been made the same as or similar to
the requirements for sources that report data on a year-round basis.
However, as necessary, special provisions have been added to
Sec. 75.74(c) to address the differences between year-round reporters
and sources that report only during the ozone season. EPA believes that
these revisions to Subpart H will help to achieve consistency in the
implementation of state and Federal NOX mass emission
reduction programs and will help to ensure the quality of the reported
data.
IV. Administrative Requirements
A. Public Docket
EPA has established Docket A-97-35 for the regulations. The docket
is an organized and complete file of all the information submitted to,
or otherwise considered by, EPA in the development of today's final
rule. The principal purposes of the docket are: (1) to allow interested
parties a means to identify and locate documents so that they can
effectively participate in the rulemaking process; and (2) to serve as
the record in case of judicial review. The docket is available for
public inspection at EPA's Air Docket, which is listed under the
ADDRESSES section of this notice.
B. Executive Order 12866
Under Executive Order 12866 (58 FR 51735, October 4, 1993), the
Administrator must determine whether the regulatory action is
``significant'' and therefore subject to Office of Management and
Budget (OMB) review and the requirements of the Executive Order. The
Order defines ``significant regulatory action'' as one that is likely
to result in a rule that may:
(1) Have an annual effect on the economy of $100 million or more
or adversely affect in a material way the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, local or tribal governments or
communities;
(2) Create a serious inconsistency or otherwise interfere with
an action taken or planned by another agency;
[[Page 28584]]
(3) Materially alter the budgetary impact of entitlements,
grants, user fees, or loan programs or the rights and obligations of
recipients thereof; or
(4) Raise novel legal or policy issues arising out of legal
mandates, the President's priorities, or the principles set forth in
the Executive Order.
This rule is not expected to have an annual effect on the economy
of $100 million or more.
Pursuant to the terms of Executive Order 12866, it has been
determined that this rule is a ``significant regulatory action'' due to
its policy implications. Therefore, the rule was submitted to OMB for
review. Any written comments from OMB and any EPA response to those
comments are included in the public docket for this proposal. The
docket is available for public inspection at EPA's Air Docket Section,
which is listed in the ADDRESSES portion of this preamble.
C. 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. Section 205 of the UMRA generally requires that, before
promulgating rules for which a written statement is needed, EPA must
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.
This rule is not expected to result in expenditures of more than
$100 million in any one year and therefore is not subject to section
202 of the UMRA. Although the rule is not expected to significantly or
uniquely affect small governments, the Agency notified all potentially
affected small governments that own or operate units potentially
affected by the rule in order to assure that they had the opportunity
to have meaningful and timely input on the rule. EPA will continue to
use its outreach efforts related to part 75 implementation, including a
policy manual that is generally updated on a quarterly basis, to
inform, educate, and advise all potentially impacted small governments
about compliance with part 75.
EPA is not directly establishing any regulatory requirements that
may significantly or uniquely affect small governments, including
tribal governments. Thus, EPA is not obligated to develop under section
203 of the UMRA a small government agency plan.
D. Executive Order 12875
Under Executive Order 12875, EPA may not issue a regulation that is
not required by statute and that creates a mandate upon a State, local
or tribal government, unless the Federal government provides the funds
necessary to pay the direct compliance costs incurred by those
governments, or EPA consults with those governments. If EPA complies by
consulting, Executive Order 12875 requires EPA to provide to the Office
of Management and Budget a description of the extent of EPA's prior
consultation with representatives of affected State, local and tribal
governments, the nature of their concerns, copies of any written
communications from the governments, and a statement supporting the
need to issue the regulation. In addition, Executive Order 12875
requires EPA to develop an effective process permitting elected
officials and other representatives of State, local and tribal
governments ``to provide meaningful and timely input in the development
of regulatory proposals containing significant unfunded mandates.''
EPA has concluded that this rule will create a mandate on local and
tribal governments and that the Federal government will not provide the
funds necessary to pay the direct costs incurred by the local and
tribal governments in complying with the mandate. In developing this
rule, EPA consulted with local and tribal governments to enable them to
provide meaningful and timely input in the development of this rule.
Only local or tribal governments that own sources affected by Acid Rain
would be affected by this rulemaking. The governments that own an Acid
Rain affected source were contacted when the proposed rule was signed
and informed of their right to comment on the proposal. EPA received a
few comment letters from municipal utilities; these letters contained
support for many elements of the rule, as well as concerns with certain
provisions. The Agency has attempted to include changes to the proposed
rule revisions based on these and other comments wherever possible
consistent with the purpose and intent of the rule revisions, and to
the extent justified by the commenters. See section III of this
preamble and the response to comments document included in the docket
for this rulemaking for the Agency's responses to the specific comments
raised. EPA also notes generally that these sources already have to
comply with part 75. Today's rule adds more compliance flexibility and
may reduce the compliance costs for some of the sources owned by local
and tribal governments.
E. Executive Order 13084
Under Executive Order 13084, EPA may not issue a regulation that is
not required by statute, that significantly or uniquely affects the
communities of Indian tribal governments, and that imposes substantial
direct compliance costs on those communities, unless the Federal
government provides the funds necessary to pay the direct compliance
costs incurred by the tribal governments, or EPA consults with those
governments. If EPA complies by consulting, Executive Order 13084
requires EPA to provide the Office of Management and Budget, in a
separately identified section of the preamble to the rule, a
description of the extent of EPA's prior consultation with
representatives of affected tribal governments, a summary of the nature
of their concerns, and a statement supporting the need to issue the
regulation. In addition, Executive Order 13084 requires EPA to develop
an effective process permitting elected officials and other
representatives of Indian tribal governments ``to provide meaningful
and timely input in the development of regulatory policies on matters
that significantly or uniquely affect their communities.''
[[Page 28585]]
Today's rule does not significantly or uniquely affect the
communities of Indian tribal governments. Only tribal governments that
own sources affected by the Acid Rain Program are affected by this
rulemaking. As noted above in section IV.D. of this preamble, today's
rule adds compliance flexibility and may reduce compliance costs for
any tribal governments that own or operate affected sources.
Accordingly, the requirements of section 3(b) of Executive Order 13084
do not apply to this rule.
F. Paperwork Reduction Act
The information collection requirements in this rule have been
submitted for approval to the OMB under the Paperwork Reduction Act, 44
U.S.C. 3501, et seq. An Information Collection Request (ICR) document
has been prepared by EPA (ICR No. 1633.12), and a copy may be obtained
from Sandy Farmer, OPPE Regulatory Information Division; U.S.
Environmental Protection Agency (2137); 401 M Street, SW, Washington,
DC 20460, by calling (202) 260-2740, or via the Internet at
www.epa.gov/icr. The information requirements are not effective until
OMB approves them.
Currently, all affected facilities are required to keep records and
submit electronic quarterly reports under the provisions of part 75.
The revisions to the rule include several new options for compliance
with part 75 which have been requested by owners or operators of
affected facilities. To implement these options, EPA will have to
modify the existing recordkeeping and reporting requirements. In some
circumstances, these changes will result in significant reductions in
the reporting and recordkeeping burdens or costs for some units (such
as low mass emissions units). However, these changes will require
modifications to the software used to generate electronic reports. In
addition, there will be some increased burden or costs for certain
units to fulfill the new quality assurance procedures contained in this
rule. Finally, several other technical revisions to the existing
reporting and recordkeeping requirements have been adopted to clarify
existing provisions or to facilitate reporting for other regulatory
programs in the context of Acid Rain Program reporting. Although these
one-time software changes will increase the short-term burdens on
sources under the Acid Rain Program, the changes should reduce a
source's overall long-term burden by streamlining the source's
reporting obligations under both the Acid Rain Program and other parts
of the Act.
The average annual projected hour burden is 1,225,633, which is
based on an estimated average burden of approximately 421 hours per
response, quarterly reporting frequency, and an estimated 728 likely
respondents (on a per facility basis). The projected annual cost burden
resulting from the collection of information is $192,483,642, which
includes a total projected capital and start-up average annualized cost
of $92,131,857 (for monitoring equipment/software), total projected
fuel sampling and analysis average annual cost of $581,100, and a total
projected operation and maintenance average annual cost (which includes
purchase of testing contractor services) of $41,398,000. Burden means
the total time, effort, or financial resources expended by persons to
generate, maintain, retain, 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
purposes of collecting, validating, and verifying information,
processing and maintaining information, and disclosing and providing
information; adjust the existing ways to comply with any previously
applicable instructions and requirements; train personnel to be able to
respond to a collection of information; search data sources; complete
and review the collection of information; and transmit or otherwise
disclose the information.
An agency may not conduct or sponsor and a person is not required
to respond to a collection of information, unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations are listed in 40 CFR part 9 and 48 CFR chapter 15.
G. Regulatory Flexibility
The Regulatory Flexibility Act (RFA), 5 U.S.C. 601, et seq.,
generally requires an agency to conduct a regulatory flexibility
analysis of any rule subject to notice and comment rulemaking
requirements 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 not-for-profit
enterprises, and governmental jurisdictions. This rule will not have a
significant impact on a substantial number of small entities.
Today's revisions to part 75 result in a net cost reduction to
facilities affected by the Acid Rain Program, including small entities.
Most importantly, the changes to Appendix D will significantly reduce
the cost of complying with part 75 for oil-and gas-fired units, many of
which are owned or operated by small entities.
Accordingly, considering all of the above information, EPA
concludes that this rule will not have a significant economic impact on
a substantial number of small entities.
H. Submission to Congress and the General Accounting Office
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 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 General Accounting
Office prior to publication of the rule in today's Federal Register.
This rule is not a ``major rule'' as defined by U.S.C. 804(2).
I. Executive Order 13045
This final rule is not subject to Executive Order 13045, entitled
``Protection of Children from Environmental Health Risks and Safety
Risks'' (62 FR 19885, April 23, 1997), because it does not involve
decisions on environmental health risks or safety risks that may
disproportionately affect children.
J. National Technology Transfer and Advancement Act
Section 12(d) of National Technology Transfer and Advancement Act
of 1995 (``NTTAA''), Pub L. 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, business practices, etc.) that are developed or
adopted by voluntary consensus standards bodies. The NTTAA requires EPA
to provide Congress, through OMB, explanations when the Agency decides
not to use available and applicable voluntary consensus standards.
Part 75 already incorporates a number of voluntary consensus
standards. In addition, today's rule includes incorporation on two
voluntary consensus standards, in response to comments submitted on the
proposed part 75 rulemaking. First, ASTM D5373-93 ``Standard Methods
for
[[Page 28586]]
Instrumental Determination of Carbon, Hydrogen and Nitrogen in
laboratory samples of Coal and Coke.'' This standard is incorporated by
reference for use under section 2.1 of Appendix G to part 75. Second,
API Sections 2, 3 and 5 from Chapter 4 of the Manual of Petroleum
Standards, October 1988 edition. This standard is incorporated by
reference for use under section 2.1.5.1 of Appendix D to part 75.
Consistent with the Agency's Performance Based Measurement System,
part 75 sets forth performance criteria that allow the use of
alternative methods to the ones set forth in part 75. The PBMS approach
is intended to be more flexible and cost effective for the regulated
community; it is also intended to encourage innovation in analytical
technology and improved data quality. The EPA is not precluding the use
of any method, whether it constitutes a voluntary consensus standard or
not, as long as it meets the performance criteria specified, however
any alternative methods must be approved in advance before they may be
used under part 75.
List of Subjects
40 CFR Part 72
Environmental protection, Acid rain, Air pollution control,
Electric utilities, Nitrogen oxides, Sulfur oxides.
40 CFR Part 75
Environmental protection, Air pollution control, Carbon dioxide,
Continuous emission monitoring, Electric utilities, Incorporation by
reference, Nitrogen oxides, Reporting and recordkeeping, Sulfur
dioxide.
Dated: April 1, 1999.
Carol M. Browner,
Administrator.
For the reasons set out in the preamble, title 40 chapter I of the
Code of Federal Regulations is amended as follows:
PART 72--PERMITS REGULATION
1. The authority for part 72 continues to read as follows:
Authority: 42 U.S.C. 7601 and 7651, et seq.
2. Section 72.2 is amended by correcting the definition of ``diesel
fuel;'' by revising the definitions of ``calibration gas,'' ``coal-
fired'' (introductory text only), ``gas-fired,'' ``natural gas,''
``pipeline natural gas,'' ``span,'' ``stationary gas turbine,'' and
``zero air material;'' by adding, in alphabetical order, new
definitions for ``conditionally valid data,'' ``EPA protocol gas,''
``fuel flowmeter QA operating quarter,'' ``gas manufacturer's
intermediate standard,'' ``probationary calibration error test,'' ``QA
operating quarter,'' ``research gas mixture'' ``stack operating hour,''
``standard reference material-equivalent compressed gas primary
reference material (SRM-equivalent PRM),'' and ``very low sulfur
fuel;'' by revising paragraphs (1) introductory text, (1)(ii) and (2)
of the definition of ``oil-fired'' and paragraph (2) of the definition
of ``peaking unit;'' by adding a paragraph (3) to the definition of
``peaking unit;'' and by removing the definition of ``protocol 1 gas''
and to read as follows:
Sec. 72.2 Definitions.
* * * * *
Calibration gas means:
(1) A standard reference material;
(2) A standard reference material-equivalent compressed gas primary
reference material;
(3) A NIST traceable reference material;
(4) NIST/EPA-approved certified reference materials;
(5) A gas manufacturer's intermediate standard;
(6) An EPA protocol gas;
(7) Zero air material; or
(8) A research gas mixture.
* * * * *
Coal-fired means the combustion of fuel consisting of coal or any
coal-derived fuel (except a coal-derived gaseous fuel that meets the
definition of ``very low sulfur fuel'' in this section), alone or in
combination with any other fuel, where:
* * * * *
Conditionally valid data means data from a continuous monitoring
system that are not quality assured, but which may become quality
assured if certain conditions are met. Examples of data that may
qualify as conditionally valid are: data recorded by an uncertified
monitoring system prior to its initial certification; or data recorded
by a certified monitoring system following a significant change to the
system that may affect its ability to accurately measure and record
emissions. A monitoring system must pass a probationary calibration
error test, in accordance with section 2.1.1 of appendix B to part 75
of this chapter, to initiate the conditionally valid data status. In
order for conditionally valid emission data to become quality assured,
one or more quality assurance tests or diagnostic tests must be passed
within a specified time period in accordance with Sec. 75.20(b)(3).
* * * * *
Diesel fuel means a low sulfur fuel oil of grades 1-D or 2-D, as
defined by the American Society for Testing and Materials standard ASTM
D975-91, ``Standard Specification for Diesel Fuel Oils,'' grades 1-GT
or 2-GT, as defined by ASTM D2880-90a, ``Standard Specification for Gas
Turbine Fuel Oils,'' or grades 1 or 2, as defined by ASTM D396-90a,
``Standard Specification for Fuel Oils'' (incorporated by reference in
Sec. 72.13).
* * * * *
EPA protocol gas means 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.
* * * * *
Fuel flowmeter QA operating quarter means a unit operating quarter
in which the unit combusts the fuel measured by the fuel flowmeter for
at least 168 unit operating hours (as defined in this section) or more.
* * * * *
Gas-fired means:
(1) For all purposes under the Acid Rain Program, except for part
75 of this chapter, the combustion of:
(i) Natural gas or other gaseous fuel (including coal-derived
gaseous fuel), for at least 90.0 percent of the unit's average annual
heat input during the previous three calendar years and for at least
85.0 percent of the annual heat input in each of those calendar years;
and
(ii) Any fuel, except coal or solid or liquid coal-derived fuel,
for the remaining heat input, if any.
(2) For purposes of part 75 of this chapter, the combustion of:
(i) Natural gas or other gaseous fuel (including coal-derived
gaseous fuel) for at least 90.0 percent of the unit's average annual
heat input during the previous three calendar years and for at least
85.0 percent of the annual heat input in each of those calendar years;
and
(ii) Fuel oil, for the remaining heat input, if any.
(3) For purposes of part 75 of this chapter, a unit may initially
qualify as gas-fired if the designated representative demonstrates to
the satisfaction of the Administrator that the requirements of
paragraph (2) of this definition are met, or will in the future be met,
through one of the following submissions:
(i) For a unit for which a monitoring plan has not been submitted
under Sec. 75.62 of this chapter, the designated representative submits
either:
(A) Fuel usage data for the unit for the three calendar years
immediately preceding the date of initial submission of the monitoring
plan for the unit under Sec. 75.62; or
[[Page 28587]]
(B) If a unit does not have fuel usage data for one or more of the
three calendar years immediately preceding the date of initial
submission of the monitoring plan for the unit under Sec. 75.62, the
unit's designated fuel usage; all available fuel usage data (including
the percentage of the unit's heat input derived from the combustion of
gaseous fuels), beginning with the date on which the unit commenced
commercial operation; and the unit's projected fuel usage.
(ii) For a unit for which a monitoring plan has already been
submitted under Sec. 75.62, that has not qualified as gas-fired under
paragraph (3)(i) of this definition, and whose fuel usage changes, the
designated representative submits either:
(A) Three calendar years of data following the change in the unit's
fuel usage, showing that no less than 90.0 percent of the unit's
average annual heat input during the previous three calendar years, and
no less than 85.0 percent of the unit's annual heat input during any
one of the previous three calendar years, is from the combustion of
gaseous fuels and the remaining heat input is from the combustion of
fuel oil; or
(B) A minimum of 720 hours of unit operating data following the
change in the unit's fuel usage, showing that no less than 90.0 percent
of the unit's heat input is from the combustion of gaseous fuels and
the remaining heat input is from the combustion of fuel oil, and a
statement that this changed pattern of fuel usage is considered
permanent and is projected to continue for the foreseeable future.
(iii) If a unit qualifies as gas-fired under paragraph (3)(i) or
(ii) of this definition, the unit is classified as gas-fired as of the
date of the submission under such paragraph.
(4) For purposes of part 75 of this chapter, a unit that initially
qualifies as gas-fired under paragraph (3)(i) or (ii) of this
definition must meet the criteria in paragraph (2) of this definition
each year in order to continue to qualify as gas-fired. If such a unit
combusts only gaseous fuel and fuel oil but fails to meet such criteria
for a given year, the unit no longer qualifies as gas-fired starting
January 1 of the year after the first year for which the criteria are
not met. If such a unit combusts fuel other than gaseous fuel or fuel
oil and fails to meet such criteria in a given year, the unit no longer
qualifies as gas-fired starting the day after the first day for which
the criteria are not met. If a unit failing to meet the criteria in
paragraph (2) of this definition initially qualified as a gas-fired
unit under paragraph (3) of this definition, the unit may qualify as a
gas-fired unit for a subsequent year only if the designated
representative submits the data specified in paragraph (3)(ii)(A) of
this definition.
* * * * *
Gas manufacturer's intermediate standard (GMIS) means a compressed
gas calibration standard that has been assayed and certified by direct
comparison to a standard reference material (SRM), an SRM-equivalent
PRM, a NIST/EPA-approved certified reference material (CRM), or a NIST
traceable reference material (NTRM), in accordance with section 2.1.2.1
of the ``EPA Traceability Protocol for Assay and Certification of
Gaseous Calibration Standards,'' September 1997, EPA-600/R-97/121.
* * * * *
Natural gas means a naturally occurring fluid mixture of
hydrocarbons (e.g., methane, ethane, or propane) produced in geological
formations beneath the Earth's surface that maintains a gaseous state
at standard atmospheric temperature and pressure under ordinary
conditions. Natural gas contains 1.0 grain or less of hydrogen sulfide
per 100 standard cubic feet and the hydrogen sulfide constitutes more
than 50% (by weight) of the total sulfur in the gas fuel. Additionally,
natural gas must meet either be composed of at least 70% methane by
volume or have a gross calorific value between 950 and 1100 Btu per
standard cubic foot. Natural gas does not include the following gaseous
fuels: landfill gas, digester gas, refinery gas, sour gas, blast
furnace gas, coal-derived gas, producer gas, coke oven gas, or any
gaseous fuel produced in a process which might result in highly
variable sulfur content or heating value.
* * * * *
Oil-fired means:
(1) For all purposes under the Acid Rain Program, except part 75 of
this chapter, the combustion of:
(i) * * *
(ii) Any solid, liquid or gaseous fuel (including coal-derived
gaseous fuel), other than coal or any other coal-derived solid or
liquid fuel, for the remaining heat input, if any.
(2) For purposes of part 75 of this chapter, combustion of only
fuel oil and gaseous fuels, provided that the unit involved does not
meet the definition of gas-fired.
* * * * *
Peaking unit means:
* * * * *
(2) For purposes of part 75 of this chapter, a unit may initially
qualify as a peaking unit if the designated representative demonstrates
to the satisfaction of the Administrator that the requirements of
paragraph (1) of this definition are met, or will in the future be met,
through one of the following submissions:
(i) For a unit for which a monitoring plan has not been submitted
under Sec. 75.62, the designated representative submits either:
(A) Capacity factor data for the unit for the three calendar years
immediately preceding the date of initial submission of the monitoring
plan for the unit under Sec. 75.62; or
(B) If a unit does not have capacity factor data for one or more of
the three calendar years immediately preceding the date of initial
submission of the monitoring plan for the unit under Sec. 75.62, all
available capacity factor data, beginning with the date on which the
unit commenced commercial operation; and projected capacity factor
data.
(ii) For a unit for which a monitoring plan has already been
submitted under Sec. 75.62, that has not qualified as a peaking unit
under paragraph (2)(i) of this definition, and where capacity factor
changes, the designated representative submits either:
(A) Three calendar years of data following the change in the unit's
capacity factor showing an average capacity factor of no more than 10.0
percent during the three previous calendar years and a capacity factor
of no more than 20.0 percent in each of those calendar years; or
(B) One calendar year of data following the change in the unit's
capacity factor showing a capacity factor of no more than 10.0 percent
and a statement that this changed pattern of operation resulting in a
capacity factor less than 10.0 percent is considered permanent and is
projected to continue for the foreseeable future.
(3) For purposes of part 75 of this chapter, a unit that initially
qualifies as a peaking unit must meet the criteria in paragraph (1) of
this definition each year in order to continue to qualify as a peaking
unit. If such a unit fails to meet such criteria for a given year, the
unit no longer qualifies as a peaking unit starting January 1 of the
year after the year for which the criteria are not met. If a unit
failing to meet the criteria in paragraph (1) of this definition
initially qualified as a peaking unit under paragraph (2) of this
definition, the unit may qualify as a peaking unit for a subsequent
year only if the designated representative submits the data specified
in paragraph (2)(ii)(A) of this definition.
* * * * *
Pipeline natural gas means natural gas, as defined in this section,
that is
[[Page 28588]]
provided by a supplier through a pipeline and that contains 0.3 grains
or less of hydrogen sulfide per 100 standard cubic feet and the
hydrogen sulfide in content of the gas constitutes at least 50% (by
weight) of the total sulfur in the fuel;
* * * * *
Probationary calibration error test means an on-line calibration
error test performed in accordance with section 2.1.1 of appendix B to
part 75 of this chapter that is used to initiate a conditionally valid
data period.
* * * * *
QA operating quarter means a calendar quarter in which there are at
least 168 unit operating hours (as defined in this section) or, for a
common stack or bypass stack, a calendar quarter in which there are at
least 168 stack operating hours (as defined in this section).
* * * * *
Research gas mixture (RGM) means a calibration gas mixture
developed by agreement of a requestor and NIST that NIST analyzes and
certifies as ``NIST traceable.'' RGMs may have concentrations different
from those of standard reference materials.
* * * * *
Span means the highest pollutant or diluent concentration or flow
rate that a monitor component is required to be capable of measuring
under part 75 of this chapter.
* * * * *
Stack operating hour means any hour (or fraction of an hour) during
which flue gases flow through a common stack or bypass stack.
* * * * *
Standard reference material-equivalent compressed gas primary
reference material (SRM-equivalent PRM) means those gas mixtures listed
in a declaration of equivalence in accordance with section 2.1.2 of the
``EPA Traceability Protocol for Assay and Certification of Gaseous
Calibration Standards,'' September 1997, EPA-600/R-97/121.
* * * * *
Stationary gas turbine means a turbine that is not self-propelled
and that combusts natural gas, other gaseous fuel with a total sulfur
content no greater than the total sulfur content of natural gas, or
fuel oil in order to heat inlet combustion air and thereby turn a
turbine in addition to or instead of producing steam or heating water.
* * * * *
Very low sulfur fuel means either:
(1) A fuel with a total sulfur content no greater than 0.05 percent
sulfur by weight;
(2) Natural gas or pipeline natural gas, as defined in this
section; or
(3) Any gaseous fuel with a total sulfur content no greater than 20
grains of sulfur per 100 standard cubic feet.
* * * * *
Zero air material means either:
(1) A calibration gas certified by the gas vendor not to contain
concentrations of SO2, NOX, or total hydrocarbons
above 0.1 parts per million (ppm), a concentration of CO above 1 ppm,
or a concentration of CO2 above 400 ppm;
(2) Ambient air conditioned and purified by a CEMS for which the
CEMS manufacturer or vendor certifies that the particular CEMS model
produces conditioned gas that does not contain concentrations of
SO2, NOX, or total hydrocarbons above 0.1 ppm, a
concentration of CO above 1 ppm, or a concentration of CO2
above 400 ppm;
(3) For dilution-type CEMS, conditioned and purified ambient air
provided by a conditioning system concurrently supplying dilution air
to the CEMS; or
(4) A multicomponent mixture certified by the supplier of the
mixture that the concentration of the component being zeroed is less
than or equal to the applicable concentration specified in paragraph
(1) of this definition, and that the mixture's other components do not
interfere with the CEM readings.
3. Section 72.3 is amended by adding, in alphabetical order, new
acronyms for CEMS, kacfm, kscfh, NIST and RATA to read as follows:
Sec. 72.3 Measurements, abbreviations, and acronyms.
* * * * *
CEMS--continuous emission monitoring system.
* * * * *
kacfm--thousands of cubic feet per minute at actual conditions.
kscfh--thousands of cubic feet per hour at standard conditions.
* * * * *
NIST--National Institute of Standards and Technology.
* * * * *
RATA--relative accuracy test audit.
* * * * *
Sec. 72.6 [Amended]
4. Section 72.6 is amended by removing from paragraph (b)(1) the
word ``operation'' and adding, in its place, the words ``commercial
operation.''
5. Section 72.90 is amended by revising paragraph (c)(3) to read as
follows:
Sec. 72.90 Annual compliance certification report.
* * * * *
(c) * * *
(3) Whether all the emissions from the unit, or a group of units
(including the unit) using a common stack, were monitored or accounted
for through the missing data procedures and reported in the quarterly
monitoring reports, including whether conditionally valid data, as
defined in Sec. 72.2, were reported in the quarterly report. If
conditionally valid data were reported, the owner or operator shall
indicate whether the status of all conditionally valid data has been
resolved and all necessary quarterly report resubmissions have been
made.
* * * * *
PART 75--CONTINUOUS EMISSION MONITORING
6. The authority citation for part 75 is revised to read as
follows:
Authority: 42 U.S.C. 7601, 7651k, and 7651k note.
Subpart A--General
7. Section 75.4 is amended by revising the last sentence of
paragraph (a) introductory text, revising the first sentence of
paragraph (d) introductory text, revising paragraph (d)(1), adding a
new sentence to the beginning of paragraph (g) introductory text, and
adding a new paragraph (i) to read as follows:
Sec. 75.4 Compliance dates.
(a) * * * In accordance with Sec. 75.20, the owner or operator of
each existing affected unit shall ensure that all monitoring systems
required by this part for monitoring SO2, NOX,
CO2, opacity, moisture and volumetric flow are installed and
that all certification tests are completed no later than the following
dates (except as provided in paragraphs (d) through (i) of this
section):
* * * * *
(d) In accordance with Sec. 75.20, the owner or operator of an
existing unit that is shutdown and is not yet operating by the
applicable dates listed in paragraph (a) of this section, or an
existing unit which has been placed in long-term cold storage after
having previously reported emissions data in accordance with this part,
shall ensure that all monitoring systems required under this part for
monitoring of SO2, NOX, CO2, opacity,
and volumetric flow are installed and all certification tests are
completed no later than the earlier of 45 unit operating days or 180
[[Page 28589]]
calendar days after the date that the unit recommences commercial
operation of the affected unit, notice of which date shall be provided
under subpart G of this part. * * *
(1) The maximum potential concentration of SO2, the
maximum potential NOX emission rate, as defined in section
2.1.2.1 of appendix A to this part, the maximum potential flow rate, as
defined in section 2.1.4.1 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;
* * * * *
(g) The provisions of this paragraph shall apply unless an owner or
operator is exempt from certifying a fuel flowmeter for use during
combustion of emergency fuel under section 2.1.4.3 of appendix D to
this part, in which circumstance the provisions of section 2.1.4.3 of
appendix D shall apply.
* * *
* * * * *
(i) In accordance with Sec. 75.20, the owner or operator of each
affected unit at which SO2 concentration is measured on a
dry basis or at which moisture corrections are required to account for
CO2 emissions, NOX emission rate in lb/mmBtu,
heat input, or NOX mass emissions for units in a
NOX mass reduction program, shall ensure that the continuous
moisture monitoring system required by this part is installed and that
all applicable initial certification tests required under
Sec. 75.20(c)(5), (c)(6), or (c)(7) for the continuous moisture
monitoring system are completed no later than the following dates:
(1) April 1, 2000, for a unit that is existing and has commenced
commercial operation by January 2, 2000; or
(2) For a new affected unit which has not commenced commercial
operation by January 2, 2000, no later than 90 days after the date the
unit commences commercial operation; or
(3) For an existing unit that is shutdown and is not yet operating
by April 1, 2000, no later than the earlier of 45 unit operating days
or 180 calendar days after the date that the unit recommences
commercial operation.
8. Section 75.5 is amended by revising paragraphs (b), (d), and
(f)(2) to read as follows:
Sec. 75.5 Prohibitions.
* * * * *
(b) No owner or operator of an affected unit shall operate the unit
without complying with the requirements of Secs. 75.2 through 75.75 and
appendices A through G to this part.
* * * * *
(d) No owner or operator of an affected unit shall operate the unit
so as to discharge, or allow to be discharged, emissions of
SO2, NOX or CO2 to the atmosphere
without accounting for all such emissions in accordance with the
provisions of Secs. 75.10 through 75.19.
* * * * *
(f) * * *
(2) The owner or operator is monitoring emissions from the unit
with another certified monitoring system or an excepted methodology
approved by the Administrator for use at that unit that provides
emissions data for the same pollutant or parameter as the retired or
discontinued monitoring system; or
* * * * *
9. Section 75.6 is amended by revising paragraphs (a)(13), (a)(31),
(a)(38), (a)(39), (b), (c), (e)(1) and (e)(2); by redesignating
paragraph (a)(40) as paragraph (a)(41); and by adding new paragraphs
(a)(40) and (f)(3) to read as follows:
Sec. 75.6 Incorporation by reference.
* * * * *
(a) * * *
(13) ASTM D1826-88, Standard Test Method for Calorific (Heating)
Value of Gases in Natural Gas Range by Continuous Recording
Calorimeter, for appendices D and F to this part.
* * * * *
(31) ASTM D3588-91, Standard Practice for Calculating Heat Value,
Compressibility Factor, and Relative Density (Specific Gravity) of
Gaseous Fuels, for appendices D and F to this part.
* * * * *
(38) ASTM D4891-89, Standard Test Method for Heating Value of Gases
in Natural Gas Range by Stoichiometric Combustion, for appendices D and
F to this part.
(39) ASTM D5291-92, Standard Test Methods for Instrumental
Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products
and Lubricants, for appendices F and G to this part.
(40) ASTM D5373-93, ``Standard Methods for Instrumental
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples
of Coal and Coke,'' for appendix G to this part.
(41) * * *
(b) The following materials are available for purchase from the
American Society of Mechanical Engineers (ASME), 22 Law Drive, Box
2350, Fairfield, NJ 07007-2350.
(1) ASME MFC-3M-1989 with September 1990 Errata, Measurement of
Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi, for appendix D
of this part.
(2) ASME MFC-4M-1986 (Reaffirmed 1990), Measurement of Gas Flow by
Turbine Meters, for appendix D of this part.
(3) ASME-MFC-5M-1985, Measurement of Liquid Flow in Closed Conduits
Using Transit-Time Ultrasonic Flowmeters, for appendix D of this part.
(4) ASME MFC-6M-1987 with June 1987 Errata, Measurement of Fluid
Flow in Pipes Using Vortex Flow Meters, for appendix D of this part.
(5) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles, for appendix D of this part.
(6) ASME MFC-9M-1988 with December 1989 Errata, Measurement of
Liquid Flow in Closed Conduits by Weighing Method, for appendix D of
this part.
(c) The following materials are available for purchase from the
American National Standards Institute (ANSI), 11 W. 42nd Street, New
York NY 10036: ISO 8316: 1987(E) Measurement of Liquid Flow in Closed
Conduits-Method by Collection of the Liquid in a Volumetric Tank, for
appendices D and E of this part.
* * * * *
(e) * * *
(1) 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), for appendices
D and E of this part.
(2) American Gas Association Transmission Measurement Committee
Report No. 7: Measurement of Gas by Turbine Meters (Second Revision,
April, 1996), for appendix D to this part.
(f) * * *
(3) American Petroleum Institute (API) Section 2, ``Conventional
Pipe Provers,'' Section 3, ``Small Volume Provers,'' and Section 5,
``Master-Meter Provers,'' from Chapter 4 of the Manual of Petroleum
Measurement Standards, October 1988 (Reaffirmed 1993), for appendix D
to this part.
10. Section 75.7 is removed and reserved.
Sec. 75.7 [Removed and Reserved]
11. Section 75.8 is removed and reserved.
Sec. 75.8 [Removed and Reserved]
Subpart B --Monitoring Provisions
12. Section 75.10 is amended by revising paragraphs (d)(3) and (f)
to read as follows:
[[Page 28590]]
Sec. 75.10 General operating requirements.
* * * * *
(d) * * *
(3) Failure of an SO2, CO2, or O2
pollutant concentration monitor, flow monitor, or NOX
continuous emission monitoring system to acquire the minimum number of
data points for calculation of an hourly average in paragraph (d)(1) of
this section shall result in the failure to obtain a valid hour of data
and the loss of such component data for the entire hour. An hourly
average NOX or SO2 emission rate in lb/mmBtu is
valid only if the minimum number of data points is acquired by both the
pollutant concentration monitor (NOX or SO2) and
the diluent monitor (O2 or CO2). For a moisture
monitoring system consisting of one or more oxygen analyzers capable of
measuring O2 on a wet-basis and a dry-basis, an hourly
average percent moisture value is valid only if the minimum number of
data points is acquired for both the wet-and dry-basis measurements.
Except for SO2 emission rate data in lb/mmBtu, if a valid
hour of data is not obtained, the owner or operator shall estimate and
record emissions, moisture, or flow data for the missing hour by means
of the automated data acquisition and handling system, in accordance
with the applicable procedure for missing data substitution in subpart
D of this part.
* * * * *
(f) Minimum measurement capability requirement. The owner or
operator shall ensure that each continuous emission monitoring system
and component thereof is capable of accurately measuring, recording,
and reporting data, and shall not incur an exceedance of the full scale
range, except as provided in sections 2.1.1.5, 2.1.2.5, and 2.1.4.3 of
appendix A to this part.
* * * * *
13. Section 75.11 is amended by revising paragraphs (a), (b),
(d)(1), (d)(2), (e) introductory text, (e)(1), (e)(2), (e)(3)
introductory text, (e)(3)(ii), (e)(3)(iv), and by removing paragraph
(e)(4) to read as follows:
Sec. 75.11 Specific provisions for monitoring SO2 emissions
(SO2 and flow monitors).
(a) Coal-fired units. The owner or operator shall meet the general
operating requirements in Sec. 75.10 for an SO2 continuous
emission monitoring system and a flow monitoring system for each
affected coal-fired unit while the unit is combusting coal and/or any
other fuel, except as provided in paragraph (e) of this section, in
Sec. 75.16, and in subpart E of this part. During hours in which only
gaseous fuel is combusted in the unit, the owner or operator shall
comply with the applicable provisions of paragraph (e)(1), (e)(2), or
(e)(3) of this section.
(b) Moisture correction. Where SO2 concentration is
measured on a dry basis, the owner or operator shall either:
(1) Report the appropriate fuel-specific default moisture value for
each unit operating hour, selected from among the following: 3.0%, for
anthracite coal; 6.0% for bituminous coal; 8.0% for sub-bituminous
coal; 11.0% for lignite coal; 13.0% for wood; or
(2) Install, operate, maintain, and quality assure a continuous
moisture monitoring system for measuring and recording the moisture
content of the flue gases, in order to correct the measured hourly
volumetric flow rates for moisture when calculating SO2 mass
emissions (in lb/hr) using the procedures in appendix F to this part.
The following continuous moisture monitoring systems are acceptable: a
continuous moisture sensor; an oxygen analyzer (or analyzers) capable
of measuring O2 both on a wet basis and on a dry basis; or a
stack temperature sensor and a moisture look-up table, i.e., a
psychometric chart (for saturated gas streams following wet scrubbers
or other demonstrably saturated gas streams, only). The moisture
monitoring system shall include as a component the automated data
acquisition and handling system (DAHS) for recording and reporting both
the raw data (e.g., hourly average wet-and dry-basis O2
values) and the hourly average values of the stack gas moisture content
derived from those data. When a moisture look-up table is used, the
moisture monitoring system shall be represented as a single component,
the certified DAHS, in the monitoring plan for the unit or common
stack.
* * * * *
(d) * * *
(1) By meeting the general operating requirements in Sec. 75.10 for
an SO2 continuous emission monitoring system and flow
monitoring system. If this option is selected, the owner or operator
shall comply with the applicable provisions in paragraph (e)(1),
(e)(2), or (e)(3) of this section during hours in which the unit
combusts only gaseous fuel;
(2) By providing other information satisfactory to the
Administrator using the applicable procedures specified in appendix D
to this part for estimating hourly SO2 mass emissions; or
* * * * *
(e) Units with SO2 continuous emission monitoring
systems during the combustion of gaseous fuel. The owner or operator of
an affected unit with an SO2 continuous emission monitoring
system shall, during any hour in which the unit combusts only gaseous
fuel, determine SO2 emissions in accordance with paragraph
(e)(1), (e)(2) or (e)(3) of this section, as applicable.
(1) If the gaseous fuel meets the definition of ``pipeline natural
gas'' or ``natural gas'' in Sec. 72.2 of this chapter, the owner or
operator may, in lieu of operating and recording data from the
SO2 monitoring system, 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 a certified flow
monitoring system and a certified diluent monitor, in conjunction with
the appropriate default SO2 emission rate from section
2.3.1.1 or 2.3.2.1.1 of appendix D to this part, and Equation D-5 in
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.
(2) The owner or operator may, in lieu of operating and recording
data from the SO2 monitoring system, determine
SO2 emissions by certifying an excepted monitoring system in
accordance with Sec. 75.20 and appendix D to this part, following the
applicable fuel sampling and analysis procedures in section 2.3 of
appendix D to this part, meeting the recordkeeping requirements of
Sec. 75.55 or Sec. 75.58, as applicable, and meeting all quality
control and quality assurance requirements for fuel flowmeters in
appendix D to this part. If this compliance option is selected, the
hourly unit heat input reported under Sec. 75.54(b)(5) or
Sec. 75.57(b)(5), as applicable, shall be determined using a certified
flow monitoring system and a certified diluent monitor, in accordance
with the procedures in section 5.2 of appendix F to this part. The flow
monitor and diluent monitor shall meet all of the applicable quality
control and quality assurance requirements of appendix B to this part.
(3) The owner or operator may determine SO2 mass
emissions by using a certified SO2 continuous monitoring
system, in conjunction with a certified flow rate monitoring system.
However, if the unit burns any gaseous fuel that is very low sulfur
fuel (as defined in Sec. 72.2 of this chapter), then on and after April
1, 2000, the SO2 monitoring
[[Page 28591]]
system shall be subject to the following quality assurance provisions
when the very low sulfur fuel is combusted. Prior to April 1, 2000, the
owner or operator may comply with these provisions.
* * * * *
(ii) EPA recommends that the calibration response of the
SO2 monitoring system be adjusted, either automatically or
manually, in accordance with the procedures for routine calibration
adjustments in section 2.1.3 of appendix B to this part, whenever the
zero-level calibration response during a required daily calibration
error test exceeds the applicable performance specification of the
instrument in section 3.1 of appendix A to this part (i.e.,
2.5 percent of the span value or 5 ppm,
whichever is less restrictive).
* * * * *
(iv) In accordance with the requirements of section 2.1.1.2 of
appendix A to this part, for units that sometimes burn gaseous fuel
that is very low sulfur fuel (as defined in Sec. 72.2 of this chapter)
and at other times burn higher sulfur fuel(s) such as coal or oil, a
second low-scale SO2 measurement range is not required when
the very low sulfur gaseous fuel is combusted. For units that burn only
gaseous fuel that is very low sulfur fuel and burn no other type(s) of
fuel(s), the owner or operator shall set the span of the SO2
monitoring system to a value no greater than 200 ppm.
* * * * *
14. Section 75.12 is amended by revising the first sentence in
paragraph (a); by redesignating existing paragraphs (b), (c), (d) and
(e) as paragraphs (c), (d), (e) and (f), respectively; by adding new
paragraph (b); and by revising the newly designated paragraph (c) to
read as follows:
Sec. 75.12 Specific provisions for monitoring NOX emission
rate (NOX and diluent gas monitors).
(a) Coal-fired units, gas-fired nonpeaking units or oil-fired
nonpeaking units. The owner or operator shall meet the general
operating requirements in Sec. 75.10 of this part for a NOX
continuous emission monitoring system for each affected coal-fired
unit, gas-fired nonpeaking unit, or oil-fired nonpeaking unit, except
as provided in paragraph (d) of this section, Sec. 75.17, and subpart E
of this part. * * *
(b) Moisture correction. If a correction for the stack gas moisture
content is needed to properly calculate the NOX emission
rate in lb/mmBtu, e.g., if the NOX pollutant concentration
monitor measures on a different moisture basis from the diluent
monitor, the owner or operator shall either report a fuel-specific
default moisture value for each unit operating hour, as provided in
Sec. 75.11(b)(1), or shall install, operate, maintain, and quality
assure a continuous moisture monitoring system, as defined in
Sec. 75.11(b)(2). Notwithstanding this requirement, if Equation 19-3,
19-4 or 19-8 in Method 19 in appendix A to part 60 of this chapter is
used to measure NOX emission rate, the following fuel-
specific default moisture percentages shall be used in lieu of the
default values specified in Sec. 75.11(b)(1): 5.0%, for anthracite
coal; 8.0% for bituminous coal; 12.0% for sub-bituminous coal; 13.0%
for lignite coal; and 15.0% for wood.
(c) Determination of NOX emission rate. The owner or
operator shall calculate hourly, quarterly, and annual NOX
emission rates (in lb/mmBtu) by combining the NOX
concentration (in ppm), diluent concentration (in percent O2
or CO2), and percent moisture (if applicable) measurements
according to the procedures in appendix F to this part.
* * * * *
15. Section 75.13 is amended by revising paragraphs (a) and (c) to
read as follows:
Sec. 75.13 Specific provisions for monitoring CO2
emissions.
(a) CO2 continuous emission monitoring system. If the
owner or operator chooses to use the continuous emission monitoring
method, then the owner or operator shall meet the general operating
requirements in Sec. 75.10 for a CO2 continuous emission
monitoring system and flow monitoring system for each affected unit.
The owner or operator shall comply with the applicable provisions
specified in Secs. 75.11(a) through (e) or Sec. 75.16, except that the
phrase ``CO2 continuous emission monitoring system'' shall
apply rather than ``SO2 continuous emission monitoring
system,'' the phrase ``CO2 concentration'' shall apply
rather than ``SO2 concentration,'' the term ``maximum
potential concentration of CO2'' shall apply rather than
``maximum potential concentration of SO2,'' and the phrase
``CO2 mass emissions'' shall apply rather than
``SO2 mass emissions.''
* * * * *
(c) Determination of CO2 mass emissions using an O2
monitor according to appendix F to this part. If the owner or operator
chooses to use the appendix F method, then the owner or operator may
determine hourly CO2 concentration and mass emissions with a
flow monitoring system; a continuous O2 concentration
monitor; fuel F and Fc factors; and, where O2
concentration is measured on a dry basis, a continuous moisture
monitoring system, as specified in Sec. 75.11(b)(2), or a fuel-specific
default moisture percentage (if applicable), as defined in
Sec. 75.11(b)(1), and by using the methods and procedures specified in
appendix F to this part. For units using a common stack, multiple
stack, or bypass stack, the owner or operator may use the provisions of
Sec. 75.16, except that the phrase ``CO2 continuous emission
monitoring system'' shall apply rather than ``SO2 continuous
emission monitoring system,'' the term ``maximum potential
concentration of CO2'' shall apply rather than ``maximum
potential concentration of SO2,'' and the phrase
``CO2 mass emissions'' shall apply rather than
``SO2 mass emissions.''
* * * * *
16. Section 75.16 is amended by:
a. Revising paragraphs (b)(2)(ii)(B), (b)(2)(ii)(D), (d)(2), and
(e)(1);
b. Removing paragraphs (e)(2) and (e)(3);
c. Redesignating existing paragraphs (e)(4) and (e)(5) as
paragraphs (e)(2) and (e)(3), respectively;
d. Adding a new sentence to the end of the newly designated
paragraph (e)(3); and
e. Adding a new paragraph (e)(4), to 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) * * *
(2) * * *
(ii) * * *
(B) Install, certify, operate, and maintain an SO2
continuous emission monitoring system and flow monitoring system in the
duct from each nonaffected unit; determine SO2 mass
emissions from the affected units as the difference between
SO2 mass emissions measured in the common stack and
SO2 mass emissions measured in the ducts of the nonaffected
units, not to be reported as an hourly average value less than zero;
combine emissions for the Phase I and Phase II affected units for
recordkeeping and compliance purposes; and calculate and report
SO2 mass emissions from the Phase I and Phase II affected
units, pursuant to an approach approved by the Administrator, such that
these emissions are not underestimated; or
* * * * *
[[Page 28592]]
(D) Petition through the designated representative and provide
information satisfactory to the Administrator on methods for
apportioning SO2 mass emissions measured in the common stack
to each of the units using the common stack and on reporting the
SO2 mass emissions. The Administrator may approve such
demonstrated substitute methods for apportioning and reporting
SO2 mass emissions measured in a common stack whenever the
demonstration ensures that there is a complete and accurate accounting
of all emissions regulated under this part and, in particular, that the
emissions from any affected unit are not underestimated.
* * * * *
(d) * * *
(2) Install, certify, operate, and maintain an SO2
continuous emission monitoring system and flow monitoring system in
each stack. Determine SO2 mass emissions from each affected
unit as the sum of the SO2 mass emissions recorded for each
stack. Notwithstanding the prior sentence, if another unit also
exhausts flue gases to one or more of the stacks, the owner or operator
shall also comply with the applicable common stack requirements of this
section to determine and record SO2 mass emissions from the
units using that stack and shall calculate and report SO2
mass emissions from the affected units and stacks, pursuant to an
approach approved by the Administrator, such that these emissions are
not underestimated.
(e) * * *
(1) The owner or operator of an affected unit using a common stack,
bypass stack, or multiple stack with a diluent monitor and a flow
monitor on each stack may choose to install monitors to determine the
heat input for the affected unit, wherever flow and diluent monitor
measurements are used to determine the heat input, using the procedures
specified in paragraphs (a) through (d) of this section, except that
the term ``heat input'' shall apply rather than ``SO2 mass
emissions'' or ``emissions'' and the phrase ``a diluent monitor and a
flow monitor'' shall apply rather than ``SO2 continuous
emission monitoring system and flow monitoring system.'' The applicable
equation in appendix F to this part shall be used to calculate the heat
input from the hourly flow rate, diluentmonitor measurements, and (if
the equation in appendix F requires a correction for the stack gas
moisture content) hourly moisture measurements. Notwithstanding the
options for combining heat input in paragraphs (a)(1)(ii), (a)(2)(ii),
(b)(1)(ii), and (b)(2)(ii) of this section, the owner or operator of an
affected unit with a diluent monitor and a flow monitor installed on a
common stack to determine the combined heat input at the common stack
shall also determine and report heat input to each individual unit.
* * * * *
(3) * * * If using either of these apportionment methods, the owner
or operator shall apportion according to section 5.6 of appendix F to
this part.
(4) Notwithstanding paragraph (e)(1) of this section, any affected
unit that is using the procedures in this part to meet the monitoring
and reporting requirements of a State or federal NOX mass
emission reduction program must also meet the requirements for
monitoring heat input in Secs. 75.71, 75.72 and 75.75.
17. Section 75.17 is amended by revising paragraph (a)(2)(i)(C) to
read as follows:
Sec. 75.17 Specific provisions for monitoring emissions from common,
by-pass, and multiple stacks for NOX emission rate.
* * * * *
(a) * * *
(2) * * *
(i) * * *
(C) Each unit's compliance with the applicable NOX
emission limit will be determined by a method satisfactory to the
Administrator for apportioning to each of the units the combined
NOX emission rate (in lb/mmBtu) measured in the common stack
and for reporting the NOX emission rate, as provided in a
petition submitted by the designated representative. The Administrator
may approve such demonstrated substitute methods for apportioning and
reporting NOX emission rate measured in a common stack
whenever the demonstration ensures that there is a complete and
accurate estimation of all emissions regulated under this part and, in
particular, that the emissions from any unit with a NOX
emission limitation are not underestimated.
* * * * *
18. Section 75.19 is amended by:
a. Redesignating Tables 1, 2, 3, 4, 5 and 6 as LM-1, LM-2, LM-3,
LM-4, LM-5 and LM-6, respectively;
b. Revising all references to Tables 1, 2, 3, 4, 5 and 6 in
Sec. 75.19 to LM-1, LM-2, LM-3, LM-4, LM-5, and LM-6, respectively;
c. Revising newly designated Table LM-5;
d. Correcting paragraph (c)(3)(ii)(D)(2) and the term
``EFNOX'' that follows Eq. LM-10 in paragraph (c)(4)(ii)(A)
to read as follows:
Sec. 75.19 Optional SO2, NOX, and CO2
emissions calculation for low mass emissions units.
* * * * *
(c) * * *
(3) * * *
(ii) * * *
(D) * * *
(2) Using the appropriate default specific gravity value in Table
LM-6 of this section.
* * * * *
(4) * * *
(ii) * * *
(A) * * *
Where:
* * * * *
EFNNOX = Either the NOX emission factor from
Table LM-2 of this section or the fuel- and unit-specific
NOX emission rate determined under paragraph (c)(1)(iv) of
this section (lb/mmBtu).
* * * * *
Table LM-5.--Default Gross Calorific Values (GCVs) for Various Fuels
------------------------------------------------------------------------
GCV for use in equation LM-2
Fuel or LM-3
------------------------------------------------------------------------
Pipeline Natural Gas...................... 1050 Btu/scf.
Natural Gas............................... 1100 Btu/scf.
Residual Oil.............................. 19,700 Btu/lb or 167,500 Btu/
gallon.
Diesel Fuel............................... 20,500 Btu/lb or 151,700 Btu/
gallon.
------------------------------------------------------------------------
* * * * *
Subpart C--Operation and Maintenance Requirements
19. Section 75.20 is amended by:
a. Revising the title of the section;
b. Revising the titles of paragraphs (c), (d) and (g);
c. Revising the introductory text of paragraphs (a), (c) and (g);
d. Revising paragraphs (a)(1), (a)(3), (a)(4) introductory text,
(a)(4)(i), (a)(4)(ii), (a)(4)(iii), (a)(5)(i), (b), (c)(1), (c)(1)(i),
(c)(1)(ii), (c)(1)(iii), (d)(1), (d)(2), (g)(1), (g)(1)(i), (g)(2),
(g)(4), (g)(5) and (h)(2);
e. Removing existing paragraph (c)(3);
f. Redesignating existing paragraphs (c)(4), (c)(5), (c)(6),
(c)(7), and (c)(8) as paragraphs (c)(3), (c)(4), (c)(8), (c)(9), and
(c)(10), respectively;
g. Revising newly redesignated paragraphs (c)(3), (c)(4)
introductory text, (c)(8) introductory text, (c)(8)(i), and (c)(10)
introductory text; and
h. Adding new paragraphs (c)(5), (c)(6), (c)(7), (g)(6) and (g)(7),
to read as follows:
[[Page 28593]]
Sec. 75.20 Initial certification and recertification procedures.
(a) Initial certification approval process. The owner or operator
shall ensure that each continuous emission or opacity monitoring system
required by this part, which includes the automated data acquisition
and handling system, and, where applicable, the CO2
continuous emission monitoring system, meets the initial certification
requirements of this section and shall ensure that all applicable
initial certification tests under paragraph (c) of this section are
completed by the deadlines specified in Sec. 75.4 and prior to use in
the Acid Rain Program. In addition, whenever the owner or operator
installs a continuous emission or opacity monitoring system in order to
meet the requirements of Secs. 75.11 through 75.18, where no continuous
emission or opacity monitoring system was previously installed, initial
certification is required.
(1) Notification of initial certification test dates. The owner or
operator or designated representative shall submit a written notice of
the dates of initial certification testing at the unit as specified in
Sec. 75.61(a)(1).
* * * * *
(3) Provisional approval of certification (or recertification)
applications. Upon the successful completion of the required
certification (or recertification) procedures of this section for each
continuous emission or opacity monitoring system or component thereof,
continuous emission or opacity monitoring system or component thereof
shall be deemed provisionally certified (or recertified) for use under
the Acid Rain Program for a period not to exceed 120 days following
receipt by the Administrator of the complete certification (or
recertification) application under paragraph (a)(4) of this section.
Notwithstanding this paragraph, no continuous emission or opacity
monitor systems for a combustion source seeking to enter the Opt-in
Program in accordance with part 74 of this chapter shall be deemed
provisionally certified (or recertified) for use under the Acid Rain
Program. Data measured and recorded by a provisionally certified (or
recertified) continuous emission or opacity monitoring system or
component thereof, operated in accordance with the requirements of
appendix B to this part, will be considered valid quality-assured data
(retroactive to the date and time of provisional certification or
recertification), provided that the Administrator does not invalidate
the provisional certification (or recertification) by issuing a notice
of disapproval within 120 days of receipt by the Administrator of the
complete certification (or recertification) application. Note that when
the data validation procedures of paragraph (b)(3) of this section are
used for the initial certification (or recertification) of a continuous
emissions monitoring system, the date and time of provisional
certification (or recertification) of the CEMS may be earlier than the
date and time of completion of the required certification (or
recertification) tests.
(4) Certification (or recertification) application formal approval
process. The Administrator will issue a notice of approval or
disapproval of the certification (or recertification) application to
the owner or operator within 120 days of receipt of the complete
certification (or recertification) application. In the event the
Administrator does not issue such a notice within 120 days of receipt,
each continuous emission or opacity monitoring system which meets the
performance requirements of this part and is included in the
certification (or recertification) application will be deemed certified
(or recertified) for use under the Acid Rain Program.
(i) Approval notice. If the certification (or recertification)
application is complete and shows that each continuous emission or
opacity monitoring system meets the performance requirements of this
part, then the Administrator will issue a notice of approval of the
certification (or recertification) application within 120 days of
receipt.
(ii) Incomplete application notice. A certification (or
recertification) application will be considered complete when all of
the applicable information required to be submitted in Sec. 75.63 has
been received by the Administrator, the EPA Regional Office, and the
appropriate State and/or local air pollution control agency. If the
certification (or recertification) application is not complete, then
the Administrator will issue a notice of incompleteness that provides a
reasonable timeframe for the designated representative to submit the
additional information required to complete the certification (or
recertification) application. If the designated representative has not
complied with the notice of incompleteness by a specified due date,
then the Administrator may issue a notice of disapproval specified
under paragraph (a)(4)(iii) of this section. The 120-day review period
shall not begin prior to receipt of a complete application.
(iii) Disapproval notice. If the certification (or recertification)
application shows that any continuous emission or opacity monitoring
system or component thereof does not meet the performance requirements
of this part, or if the certification (or recertification) application
is incomplete and the requirement for disapproval under paragraph
(a)(4)(ii) of this section has been met, the Administrator shall issue
a written notice of disapproval of the certification (or
recertification) application within 120 days of receipt. By issuing the
notice of disapproval, the provisional certification (or
recertification) is invalidated by the Administrator, and the data
measured and recorded by each uncertified continuous emission or
opacity monitoring system or component thereof shall not be considered
valid quality-assured data as follows: from the hour of the
probationary calibration error test that began the initial
certification (or recertification) test period (if the data validation
procedures of paragraph (b)(3) of this section were used to
retrospectively validate data); or from the date and time of completion
of the invalid certification or recertification tests (if the data
validation procedures of paragraph (b)(3) of this section were not
used), until the date and time that the owner or operator completes
subsequently approved initial certification or recertification tests.
The owner or operator shall follow the procedures for loss of initial
certification in paragraph (a)(5) of this section for each continuous
emission or opacity monitoring system or component thereof which is
disapproved for initial certification. For each disapproved
recertification, the owner or operator shall follow the procedures of
paragraph (b)(5) of this section.
* * * * *
(5) * * *
(i) Until such time, date, and hour as the continuous emission
monitoring system or component thereof can be adjusted, repaired, or
replaced and certification tests successfully completed, the owner or
operator shall substitute the following values, as applicable, for each
hour of unit operation during the period of invalid data specified in
paragraph (a)(4)(iii) of this section or in Sec. 75.21: the maximum
potential concentration of SO2, as defined in section
2.1.1.1 of appendix A to this part, to report SO2
concentration; the maximum potential NOX emission rate, as
defined in Sec. 72.2 of this chapter, to report NOX
emissions in lb/mmBtu; the maximum potential concentration of
[[Page 28594]]
NOX, as defined in section 2.1.2.1 of appendix A to this
part, to report NOX emissions in ppm (when a NOX
concentration monitoring system is used to determine NOX
mass emissions, as defined under Sec. 75.71(a)(2)); the maximum
potential flow rate, as defined in section 2.1.4.1 of appendix A to
this part, to report volumetric flow; the maximum potential
concentration of CO2, as defined in section 2.1.3.1 of
appendix A to this part, to report CO2 concentration data;
and either the minimum potential moisture percentage, as defined in
section 2.1.5 of appendix A to this part or, if Equation 19-3, 19-4 or
19-8 in Method 19 in appendix A to part 60 of this chapter is used to
determine NOX emission rate, the maximum potential moisture
percentage, as defined in section 2.1.6 of appendix A to this part; and
* * * * *
(b) Recertification approval process. Whenever the owner or
operator makes a replacement, modification, or change in a certified
continuous emission monitoring system or continuous opacity monitoring
system that may significantly affect the ability of the system to
accurately measure or record the SO2 or CO2
concentration, stack gas volumetric flow rate, NOX emission
rate, percent moisture, or opacity, or to meet the requirements of
Sec. 75.21 or appendix B to this part, the owner or operator shall
recertify the continuous emission monitoring system or continuous
opacity monitoring system, according to the procedures in this
paragraph. Furthermore, whenever the owner or operator makes a
replacement, modification, or change to the flue gas handling system or
the unit operation that may significantly change the flow or
concentration profile, the owner or operator shall recertify the
monitoring system according to the procedures in this paragraph.
Examples of changes which require recertification include: replacement
of the analyzer; change in location or orientation of the sampling
probe or site; and complete replacement of an existing continuous
emission monitoring system or continuous opacity monitoring system. The
owner or operator shall recertify a continuous opacity monitoring
system whenever the monitor path length changes or as required by an
applicable State or local regulation or permit. Any change to a flow
monitor or gas monitoring system for which a RATA is not necessary
shall not be considered a recertification event. In addition, changing
the polynomial coefficients or K factor(s) of a flow monitor shall
require a 3-load RATA, but is not considered to be a recertification
event; however, records of the polynomial coefficients or K factor (s)
currently in use shall be maintained on-site in a format suitable for
inspection. Changing the coefficient or K factor(s) of a moisture
monitoring system shall require a RATA, but is not considered to be a
recertification event; however, records of the coefficient or K factor
(s) currently in use by the moisture monitoring system shall be
maintained on-site in a format suitable for inspection. In such cases,
any other tests that are necessary to ensure continued proper operation
of the monitoring system (e.g., 3-load flow RATAs following changes to
flow monitor polynomial coefficients, linearity checks, calibration
error tests, DAHS verifications, etc.) shall be performed as diagnostic
tests, rather than as recertification tests. The data validation
procedures in paragraph (b)(3) of this section shall be applied to
RATAs associated with changes to flow or moisture monitor coefficients,
and to linearity checks, 7-day calibration error tests, and cycle time
tests, when these are required as diagnostic tests. When the data
validation procedures of paragraph (b)(3) of this section are applied
in this manner, replace the word ``recertification'' with the word
``diagnostic.''
(1) Tests required. For all recertification testing, the owner or
operator shall complete all initial certification tests in paragraph
(c) of this section that are applicable to the monitoring system,
except as otherwise approved by the Administrator. For diagnostic
testing after changing the flow rate monitor polynomial coefficients,
the owner or operator shall complete a 3-level RATA. For diagnostic
testing after changing the K factor or mathematical algorithm of a
moisture monitoring system, the owner or operator shall complete a
RATA.
(2) Notification of recertification test dates. The owner,
operator, or designated representative shall submit notice of testing
dates for recertification under this paragraph as specified in
Sec. 75.61(a)(1)(ii), unless all of the tests in paragraph (c) of this
section are not required for recertification, in which case the owner
or operator shall provide notice in accordance with the notice
provisions for initial certification testing in Sec. 75.61(a)(1)(i).
(3) Recertification test period requirements and data validation.
The data validation provisions in paragraphs (b)(3)(i) through
(b)(3)(ix) of this section shall apply to all CEMS recertifications and
diagnostic testing. The provisions in paragraphs (b)(3)(ii) through
(b)(3)(ix) of this section may also be applied to initial
certifications (see sections 6.2(a), 6.3.1(a), 6.3.2(a), 6.4(a) and
6.5(f) of appendix A to this part) and may be used to supplement the
linearity check and RATA data validation procedures in sections
2.2.3(b) and 2.3.2(b) of appendix B to this part.
(i) In the period extending from the hour of the replacement,
modification or change made to a monitoring system that triggers the
need to perform recertification test(s) of the CEMS to the hour of
successful completion of a probationary calibration error test
(according to paragraph (b)(3)(ii) of this section) following the
replacement, modification, or change to the CEMS, the owner or operator
shall either substitute for missing data, according to the standard
missing data procedures in Secs. 75.33 through 75.37, or report
emission data using a reference method or another monitoring system
that has been certified or approved for use under this part.
Notwithstanding this requirement, if the replacement, modification, or
change requiring recertification of the CEMS is such that the
historical data stream is no longer representative (e.g., where the
SO2 concentration and stack flow rate change significantly
after installation of a wet scrubber), the owner or operator shall
substitute for missing data as follows, in the period extending from
the hour of commencement of the replacement, modification, or change
requiring recertification of the CEMS to the hour of commencement of
the recertification test period: For a change that results in a
significantly higher concentration or flow rate, substitute maximum
potential values according to the procedures in paragraph (a)(5) of
this section; or for a change that results in a significantly lower
concentration or flow rate, substitute data using the standard missing
data procedures. The owner or operator shall then use the initial
missing data procedures in Sec. 75.31, beginning with the first hour of
quality assured data obtained with the recertified monitoring system,
unless otherwise provided by Sec. 75.34 for units with add-on emission
controls. The first hour of quality-assured data for the recertified
monitoring system shall be determined in accordance with paragraphs
(b)(3)(ii) through (b)(3)(ix) of this section.
(ii) Once the modification or change to the CEMS has been completed
and all of the associated repairs, component replacements, adjustments,
linearization, and reprogramming of the CEMS have been completed, a
probationary calibration error test is required to establish the
beginning point of the recertification test period. In this
[[Page 28595]]
instance, the first successful calibration error test of the monitoring
system following completion of all necessary repairs, component
replacements, adjustments, linearization and reprogramming shall be the
probationary calibration error test. The probationary calibration error
test must be passed before any of the required recertification tests
are commenced.
(iii) Beginning with the hour of commencement of a recertification
test period, emission data recorded by the CEMS are considered to be
conditionally valid, contingent upon the results of the subsequent
recertification tests.
(iv) Each required recertification test shall be completed no later
than the following number of unit operating hours (or unit operating
days) after the probationary calibration error test that initiates the
test period:
(A) For a linearity check and/or cycle time test, 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;
(B) For a RATA (whether normal-load or multiple-load), 720
consecutive unit operating hours, as defined in Sec. 72.2 of this
chapter or, for CEMS installed on common stacks or bypass stacks, 720
consecutive stack operating hours, as defined in Sec. 72.2 of this
chapter; and
(C) For a 7-day calibration error test, 21 consecutive unit
operating days, as defined in Sec. 72.2 of this chapter.
(v) All recertification tests shall be performed hands-off. No
adjustments to the calibration of the CEMS, other than the routine
calibration adjustments following daily calibration error tests as
described in section 2.1.3 of appendix B to this part, are permitted
during the recertification test period. Routine daily calibration error
tests shall be performed throughout the recertification test period, in
accordance with section 2.1.1 of appendix B to this part. The
additional calibration error test requirements in section 2.1.3 of
appendix B to this part shall also apply during the recertification
test period.
(vi) If all of the required recertification tests and required
daily calibration error tests are successfully completed in succession
with no failures, and if each recertification test is completed within
the time period specified in paragraph (b)(3)(iv)(A), (B), or (C) of
this section, then all of the conditionally valid emission data
recorded by the CEMS shall be considered quality assured, from the hour
of commencement of the recertification test period until the hour of
completion of the required test(s).
(vii) If a required recertification test is failed or aborted due
to a problem with the CEMS, or if a daily calibration error test is
failed during a recertification test period, data validation shall be
done as follows:
(A) If any required recertification test is failed, it shall be
repeated. If any recertification test other than a 7-day calibration
error test is failed or aborted due to a problem with the CEMS, the
original recertification test period is ended, and a new
recertification test period must be commenced with a probationary
calibration error test. The tests that are required in the new
recertification test period will include any tests that were required
for the initial recertification event which were not successfully
completed and any recertification or diagnostic tests that are required
as a result of changes made to the monitoring system to correct the
problems that caused the failure of the recertification test. For a 2-
or 3-load flow RATA, if the relative accuracy test is passed at one or
more load levels, but is failed at a subsequent load level, provided
that the problem that caused the RATA failure is corrected without re-
linearizing the instrument, the length of the new recertification test
period shall be equal to the number of unit operating hours remaining
in the original recertification test period, as of the hour of failure
of the RATA. However, if re-linearization of the flow monitor is
required after a flow RATA is failed at a particular load level, then a
subsequent 3-load RATA is required, and the new recertification test
period shall be 720 consecutive unit (or stack) operating hours. The
new recertification test sequence shall not be commenced until all
necessary maintenance activities, adjustments, linearizations, and
reprogramming of the CEMS have been completed;
(B) If a linearity check, RATA, or cycle time test is failed or
aborted due to a problem with the CEMS, all conditionally valid
emission data recorded by the CEMS are invalidated, from the hour of
commencement of the recertification test period to the hour in which
the test is failed or aborted, except for the case in which a multiple-
load flow RATA is passed at one or more load levels, failed at a
subsequent load level, and the problem that caused the RATA failure is
corrected without re-linearizing the instrument. In that case, data
invalidation shall be prospective, from the hour of failure of the RATA
until the commencement of the new recertification test period. Data
from the CEMS remain invalid until the hour in which a new
recertification test period is commenced, following corrective action,
and a probationary calibration error test is passed, at which time the
conditionally valid status of emission data from the CEMS begins again;
(C) If a 7-day calibration error test is failed within the
recertification test period, previously-recorded conditionally valid
emission data from the CEMS are not invalidated. The conditionally
valid data status is unaffected, unless the calibration error on the
day of the failed 7-day calibration error test exceeds twice the
performance specification in section 3 of appendix A to this part, as
described in paragraph (b)(3)(vii)(D) of this section; and
(D) If a daily calibration error test is failed during a
recertification test period (i.e., the results of the test exceed twice
the performance specification in section 3 of appendix A to this part),
the CEMS is out-of-control as of the hour in which the calibration
error test is failed. Emission data from the CEMS shall be invalidated
prospectively from the hour of the failed calibration error test until
the hour of completion of a subsequent successful calibration error
test following corrective action, at which time the conditionally valid
status of data from the monitoring system resumes. Failure to perform a
required daily calibration error test during a recertification test
period shall also cause data from the CEMS to be invalidated
prospectively, from the hour in which the calibration error test was
due until the hour of completion of a subsequent successful calibration
error test. Whenever a calibration error test is failed or missed
during a recertification test period, no further recertification tests
shall be performed until the required subsequent calibration error test
has been passed, re-establishing the conditionally valid status of data
from the monitoring system. If a calibration error test failure occurs
while a linearity check or RATA is still in progress, the linearity
check or RATA must be re-started.
(E) Trial gas injections and trial RATA runs are permissible during
the recertification test period, prior to commencing a linearity check
or RATA, for the purpose of optimizing the performance of the CEMS. The
results of such gas injections and trial runs shall not affect the
status of previously-recorded conditionally valid data or result in
termination of the recertification test period, provided that the
following specifications and conditions are met:
(1) For gas injections, the stable, ending monitor response is
within 5
[[Page 28596]]
percent or within 5 ppm of the tag value of the reference gas;
(2) For RATA trial runs, the average reference method reading and
the average CEMS reading for the run differ by no more than
10% of the average reference method value or 15
ppm, or 1.5% H2O, or 0.02 lb/mmBtu
from the average reference method value, as applicable;
(3) No adjustments to the calibration of the CEMS are made
following the trial injection(s) or run(s), other than the adjustments
permitted under section 2.1.3 of appendix B to this part; and
(4) The CEMS is not repaired, re-linearized or reprogrammed (e.g.,
changing flow monitor polynomial coefficients, linearity constants, or
K-factors) after the trial injection(s) or run(s).
(F) If the results of any trial gas injection(s) or RATA run(s) are
outside the limits in paragraphs (b)(3)(vii)(E)(1) or (2) of this
section or if the CEMS is repaired, re-linearized or reprogrammed after
the trial injection(s) or run(s), the trial injection(s) or run(s)
shall be counted as a failed linearity check or RATA attempt. If this
occurs, follow the procedures pertaining to failed and aborted
recertification tests in paragraphs (b)(3)(vii)(A) and (b)(3)(vii)(B)
of this section.
(viii) If any required recertification test is not completed within
its allotted time period, data validation shall be done as follows. For
a late linearity test, RATA, or cycle time test that is passed on the
first attempt, data from the monitoring system shall be invalidated
from the hour of expiration of the recertification test period until
the hour of completion of the late test. For a late 7-day calibration
error test, whether or not it is passed on the first attempt, data from
the monitoring system shall also be invalidated from the hour of
expiration of the recertification test period until the hour of
completion of the late test. For a late linearity test, RATA, or cycle
time test that is failed on the first attempt or aborted on the first
attempt due to a problem with the monitor, all conditionally valid data
from the monitoring system shall be considered invalid back to the hour
of the first probationary calibration error test which initiated the
recertification test period. Data from the monitoring system shall
remain invalid until the hour of successful completion of the late
recertification test and any additional recertification or diagnostic
tests that are required as a result of changes made to the monitoring
system to correct problems that caused failure of the late
recertification test.
(ix) If any required recertification test of a monitoring system
has not been completed by the end of a calendar quarter and if data
contained in the quarterly report are conditionally valid pending the
results of test(s) to be completed in a subsequent quarter, the owner
or operator shall indicate this by means of a suitable conditionally
valid data flag in the electronic quarterly report for that quarter.
The owner or operator shall resubmit the report for that quarter if the
required recertification test is subsequently failed. In the
resubmitted report, the owner or operator shall use the appropriate
missing data routine in Sec. 75.31 or Sec. 75.33 to replace with
substitute data each hour of conditionally valid data that was
invalidated by the failed recertification test. Alternatively, if any
required recertification test is not completed by the end of a
particular calendar quarter but is completed no later than 30 days
after the end of that quarter (i.e., prior to the deadline for
submitting the quarterly report under Sec. 75.64), the test data and
results may be submitted with the earlier quarterly report even though
the test date(s) are from the next calendar quarter. In such instances,
if the recertification test(s) are passed in accordance with the
provisions of paragraph (b)(3) of this section, conditionally valid
data may be reported as quality-assured, in lieu of reporting a
conditional data flag. If the recertification test(s) is failed and if
conditionally valid data are replaced, as appropriate, with substitute
data, then neither the reporting of a conditional data flag nor
resubmission is required. In addition, if the owner or operator uses a
conditionally valid data flag in any of the four quarterly reports for
a given year, the owner or operator shall indicate the final status of
the conditionally valid data (i.e., resolved or unresolved) in the
annual compliance certification report required under Sec. 72.90 of
this chapter for that year. The Administrator may invalidate any
conditionally valid data that remains unresolved at the end of a
particular calendar year and may require the owner or operator to
resubmit one or more of the quarterly reports for that calendar year,
replacing the unresolved conditionally valid data with substitute data
values determined in accordance with Sec. 75.31 or Sec. 75.33, as
appropriate.
(4) Recertification application. The designated representative
shall apply for recertification of each continuous emission or opacity
monitoring system used under the Acid Rain Program. The owner or
operator shall submit the recertification application in accordance
with Sec. 75.60, and each complete recertification application shall
include the information specified in Sec. 75.63.
(5) Approval or disapproval of request for recertification. The
procedures for provisional certification in paragraph (a)(3) of this
section shall apply to recertification applications. The Administrator
will issue a notice of approval, disapproval, or incompleteness
according to the procedures in paragraph (a)(4) of this section. In the
event that a recertification application is disapproved, data from the
monitoring system are invalidated and the applicable missing data
procedures in Sec. 75.31 or Sec. 75.33 shall be used from the date and
hour of receipt of the disapproval notice back to the hour of the
probationary calibration error test that began the recertification test
period. Data from the monitoring system remain invalid until a
subsequent probationary calibration error test is passed, beginning a
new recertification test period. The owner or operator shall repeat all
recertification tests or other requirements, as indicated in the
Administrator's notice of disapproval, no later than 30 unit operating
days after the date of issuance of the notice of disapproval. The
designated representative shall submit a notification of the
recertification retest dates, as specified in Sec. 75.61(a)(1)(ii), and
shall submit a new recertification application according to the
procedures in paragraph (b)(4) of this section.
(c) Initial certification and recertification procedures. Prior to
the deadline in Sec. 75.4, the owner or operator shall conduct initial
certification tests and in accordance with Sec. 75.63, the designated
representative shall submit an application to demonstrate that the
continuous emission or opacity monitoring system and components thereof
meet the specifications in appendix A to this part. The owner or
operator shall compare reference method values with output from the
automated data acquisition and handling system that is part of the
continuous emission monitoring system being tested. Except as specified
in paragraphs (b)(1), (d), and (e) of this section, the owner or
operator shall perform the following tests for initial certification or
recertification of continuous emission or opacity monitoring systems or
components according to the requirements of appendix A to this part:
(1) For each SO2 pollutant concentration monitor, each
NOX concentration monitoring system used to determine
NOX mass emissions, as
[[Page 28597]]
defined under Sec. 75.71(a)(2), and for each NOX-diluent
continuous emission monitoring system:
(i) A 7-day calibration error 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;
(ii) A linearity check, 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;
(iii) A relative accuracy test audit. For the NOX-
diluent continuous emission monitoring system, the RATA shall be done
on a system basis, in units of lb/mmBtu. For the NOX
concentration monitoring system, the RATA shall be done on a ppm basis.
* * * * *
(3) The initial certification test data from an O2 or a
CO2 diluent gas monitor certified for use in a
NOX continuous emission monitoring system may be submitted
to meet the requirements of paragraph (c)(4) of this section. Also, for
a diluent monitor that is used both as a CO2 monitoring
system and to determine heat input, only one set of diluent monitor
certification data need be submitted (under the component and system
identification numbers of the CO2 monitoring system).
(4) For each CO2 pollutant concentration monitor, each
O2 monitor which is part of a CO2 continuous
emission monitoring system, each diluent monitor used to monitor heat
input and each SO2-diluent continuous emission monitoring
system:
* * * * *
(5) For each continuous moisture monitoring system consisting of
wet- and dry-basis O2 analyzers:
(i) A 7-day calibration error test of each O2 analyzer;
(ii) A cycle time test of each O2 analyzer;
(iii) A linearity test of each O2 analyzer; and
(iv) A RATA, directly comparing the percent moisture measured by
the monitoring system to a reference method.
(6) For each continuous moisture sensor: A RATA, directly comparing
the percent moisture measured by the monitor sensor to a reference
method.
(7) For a continuous moisture monitoring system consisting of a
temperature sensor and a data acquisition and handling system (DAHS)
software component programmed with a moisture lookup table:
(i) A demonstration that the correct moisture value for each hour
is being taken from the moisture lookup tables and applied to the
emission calculations. At a minimum, the demonstration shall be made at
three different temperatures covering the normal range of stack
temperatures from low to high.
(ii) [Reserved]
(8) The owner or operator shall ensure that initial certification
or recertification of a continuous opacity monitor for use under the
Acid Rain Program is conducted according to one of the following
procedures:
(i) Performance of the tests for initial certification or
recertification, according to the requirements of Performance
Specification 1 in appendix B to part 60 of this chapter; or
* * * * *
(10) The owner or operator shall provide adequate facilities for
initial certification or recertification testing that include:
* * * * *
(d) Initial certification and recertification and quality assurance
procedures for optional backup continuous emission monitoring systems.
(1) Redundant backups. The owner or operator of an optional redundant
backup CEMS shall comply with all the requirements for initial
certification and recertification according to the procedures specified
in paragraphs (a), (b), and (c) of this section. The owner or operator
shall operate the redundant backup CEMS during all periods of unit
operation, except for periods of calibration, quality assurance,
maintenance, or repair. The owner or operator shall perform upon the
redundant backup CEMS all quality assurance and quality control
procedures specified in appendix B to this part, except that the daily
assessments in section 2.1 of appendix B to this part are optional for
days on which the redundant backup CEMS is not used to report emission
data under this part. For any day on which a redundant backup CEMS is
used to report emission data, the system must meet all of the
applicable daily assessment criteria in appendix B to this part.
(2) Non-redundant backups. The owner or operator of an optional
non-redundant backup CEMS or like-kind replacement analyzer shall
comply with all of the following requirements for initial
certification, quality assurance, recertification, and data reporting:
(i) Except as provided in paragraph (d)(2)(v) of this section, for
a regular non-redundant backup CEMS (i.e., a non-redundant backup CEMS
that has its own separate probe, sample interface, and analyzer), or a
non-redundant backup flow monitor, all of the tests in paragraph (c) of
this section are required for initial certification of the system,
except for the 7-day calibration error test.
(ii) For a like-kind replacement non-redundant backup analyzer
(i.e., a non-redundant backup analyzer that uses the same probe and
sample interface as a primary monitoring system), no initial
certification of the analyzer is required. A non-redundant backup
analyzer, connected to the same probe and interface as a primary CEMS
in order to satisfy the dual span requirements of section 2.1.1.4 or
2.1.2.4 of appendix A to this part, shall be treated in the same manner
as a like-kind replacement analyzer.
(iii) Each non-redundant backup CEMS or like-kind replacement
analyzer shall comply with the daily and quarterly quality assurance
and quality control requirements in appendix B to this part for each
day and quarter that the non-redundant backup CEMS or like-kind
replacement analyzer is used to report data, and shall meet the
additional linearity and calibration error test requirements specified
in this paragraph. The owner or operator shall ensure that each non-
redundant backup CEMS or like-kind replacement analyzer passes a
linearity check (for pollutant concentration and diluent gas monitors)
or a calibration error test (for flow monitors) prior to each use for
recording and reporting emissions. For a primary NOX-diluent
or SO2-diluent CEMS consisting of the primary pollutant
analyzer and a like-kind replacement diluent analyzer (or vice-versa),
provided that the primary pollutant or diluent analyzer (as applicable)
is operating and is not out-of-control with respect to any of its
quality assurance requirements, only the like-kind replacement analyzer
must pass a linearity check before the system is used for data
reporting. When a non-redundant backup CEMS or like-kind replacement
analyzer is brought into service, prior to conducting the linearity
test, a probationary calibration error test (as described in paragraph
(b)(3)(ii) of this section), which will begin a period of conditionally
valid data, may be performed in order to allow the validation of data
retrospectively, as follows. Conditionally valid data from the CEMS or
like-kind replacement analyzer are validated back to the hour of
completion of the probationary calibration error test if the following
conditions are met: if no adjustments are made to the CEMS or like-kind
[[Page 28598]]
replacement analyzer other than the allowable calibration adjustments
specified in section 2.1.3 of appendix B to this part between the
probationary calibration error test and the successful completion of
the linearity test; and if the linearity test is passed within 168 unit
(or stack) operating hours of the probationary calibration error test.
However, if the linearity test is either failed, aborted due to a
problem with the CEMS or like-kind replacement analyzer, or is not
completed as required, then all of the conditionally valid data are
invalidated back to the hour of the probationary calibration error
test, and data from the non-redundant backup CEMS or from the primary
monitoring system of which the like-kind replacement analyzer is a part
remain invalid until the hour of completion of a successful linearity
test.
(iv) When data are reported from a non-redundant backup CEMS or
like-kind replacement analyzer, the appropriate bias adjustment factor
shall be determined as follows:
(A) For a regular non-redundant backup CEMS, as described in
paragraph (d)(2)(i) of this section, apply the bias adjustment factor
from the most recent RATA of the non-redundant backup system (even if
that RATA was done more than 12 months previously); or
(B) When a like-kind replacement non-redundant backup analyzer is
used as a component of a primary CEMS (as described in paragraph
(d)(2)(ii) of this section), apply the primary monitoring system bias
adjustment factor.
(v) For each parameter monitored (i.e., SO2,
CO2, NOX or flow rate) at each unit or stack, a
regular non-redundant backup CEMS may not be used to report data at
that affected unit or common stack for more than 720 hours in any one
calendar year, unless the CEMS passes a RATA at that unit or stack. For
each parameter monitored (SO2, CO2 or
NOX) at each unit or stack, the use of a like-kind
replacement non-redundant backup analyzer (or analyzers) is restricted
to 720 cumulative hours per calendar year, unless the owner or operator
redesignates the like-kind replacement analyzer(s) as component(s) of
regular non-redundant backup CEMS and each redesignated CEMS passes a
RATA at that unit or stack.
(vi) For each regular non-redundant backup CEMS, no more than eight
successive calendar quarters shall elapse following the quarter in
which the last RATA of the CEMS was done at a particular unit or stack,
without performing a subsequent RATA. Otherwise, the CEMS may not be
used to report data from that unit or stack until the hour of
completion of a passing RATA at that location.
(vii) Each regular non-redundant backup CEMS shall be represented
in the monitoring plan required under Sec. 75.53 as a separate
monitoring system, with unique system and component identification
numbers. When like-kind replacement non-redundant backup analyzers are
used, the owner or operator shall represent each like-kind replacement
analyzer used during a particular calendar quarter in the monitoring
plan required under Sec. 75.53 as a component of a primary monitoring
system. The owner or operator shall also assign a unique component
identification number to each like-kind replacement analyzer and
specify the manufacturer, model and serial number of the like-kind
replacement analyzer. This information may be added, deleted or updated
as necessary, from quarter to quarter. The owner or operator shall also
report data from the like-kind replacement analyzer using the system
identification number of the primary monitoring system and the assigned
component identification number of the like-kind replacement analyzer.
For the purposes of the electronic quarterly report required under
Sec. 75.64, the owner or operator may manually enter the appropriate
component identification number(s) of any like-kind replacement
analyzer(s) used for data reporting during the quarter.
(viii) When reporting data from a certified regular non-redundant
backup CEMS, use a method of determination (MODC) code of ``02.'' When
reporting data from a like-kind replacement non-redundant backup
analyzer, use a MODC of ``17'' (see Table 4a under Sec. 75.57). For the
purposes of the electronic quarterly report required under Sec. 75.64,
the owner or operator may manually enter the required MODC of ``17''
for a like-kind replacement analyzer.
* * * * *
(g) Initial certification and recertification procedures for
excepted monitoring systems under appendices D and E. The owner or
operator of a gas-fired unit, oil-fired unit, or diesel-fired unit
using the optional protocol under appendix D or E to this part shall
ensure that an excepted monitoring system under appendix D or E to this
part meets the applicable general operating requirements of Sec. 75.10,
the applicable requirements of appendices D and E to this part, and the
initial certification or recertification requirements of this
paragraph.
(1) Initial certification and recertification testing. The owner or
operator shall use the following procedures for initial certification
and recertification of an excepted monitoring system under appendix D
or E to this part.
(i) When the optional SO2 mass emissions estimation
procedure in appendix D to this part or the optional NOX
emissions estimation protocol in appendix E to this part is used, the
owner or operator shall provide data from a flowmeter accuracy test (or
shall provide a statement of calibration if the flowmeter meets the
accuracy standard by design) for each fuel flowmeter, according to
section 2.1.5.1 of appendix D to this part.
* * * * *
(2) Initial certification and recertification testing notification.
The designated representative shall provide initial certification
testing notification and routine periodic retesting notification for an
excepted monitoring system under appendix E to this part as specified
in Sec. 75.61. The designated representative shall also submit
recertification testing notification, as specified in Sec. 75.61, for
quality assurance related NOX emission rate re-testing under
section 2.3 of appendix E to this part for an excepted monitoring
system under appendix E to this part. Initial certification testing
notification or periodic retesting notification is not required for
testing of a fuel flowmeter or for testing of an excepted monitoring
system under appendix D to this part.
* * * * *
(4) Initial certification or recertification application. The
designated representative shall submit an initial certification or
recertification application in accordance with Secs. 75.60 and 75.63.
(5) Provisional approval of initial certification and
recertification applications. Upon the successful completion of the
required initial certification or recertification procedures for each
excepted monitoring system under appendix D or E to this part, each
excepted monitoring system under appendix D or E to this part shall be
deemed provisionally certified for use under the Acid Rain Program
during the period for the Administrator's review. The provisions for
the initial certification or recertification application formal
approval process in paragraph (a)(4) of this section shall apply,
except that the term ``excepted monitoring system'' shall apply rather
than ``continuous emission or opacity monitoring system'' and except
that the procedures for loss
[[Page 28599]]
of certification in paragraph (g)(7) of this section shall apply rather
than the procedures for loss of certification in either paragraph
(a)(5) or (b)(5) of this section. Data measured and recorded by a
provisionally certified excepted monitoring system under appendix D or
E to this part will be considered quality assured data from the date
and time of completion of the last initial certification or
recertification test, provided that the Administrator does not revoke
the provisional certification or recertification by issuing a notice of
disapproval in accordance with the provisions in paragraph (a)(4) or
(b)(5) of this section.
(6) Recertification requirements. Recertification of an excepted
monitoring system under appendix D or E to this part is required for
any modification to the system or change in operation that could
significantly affect the ability of the system to accurately account
for emissions and for which the Administrator determines that an
accuracy test of the fuel flowmeter or a retest under appendix E to
this part to re-establish the NOX correlation curve is
required. Examples of such changes or modifications include fuel
flowmeter replacement, changes in unit configuration, or exceedance of
operating parameters.
(7) Procedures for loss of certification or recertification for
excepted monitoring systems under appendices D and E to this part. In
the event that a certification or recertification application is
disapproved for an excepted monitoring system, data from the monitoring
system are invalidated, and the applicable missing data procedures in
section 2.4 of appendix D or section 2.5 of appendix E to this part
shall be used from the date and hour of receipt of such notice back to
the hour of the provisional certification. Data from the excepted
monitoring system remain invalid until all required tests are repeated
and the excepted monitoring system is again provisionally certified.
The owner or operator shall repeat all certification or recertification
tests or other requirements, as indicated in the Administrator's notice
of disapproval, no later than 30 unit operating days after the date of
issuance of the notice of disapproval. The designated representative
shall submit a notification of the certification or recertification
retest dates if required under paragraph (g)(2) of this section and
shall submit a new certification or recertification application
according to the procedures in paragraph (g)(4) of this section.
(h) * * *
(2) Certification application. The designated representative shall
submit a certification application in accordance with
Sec. 75.63(a)(1)(iii).
* * * * *
20. Section 75.21 is amended by:
a. Revising paragraphs (a)(2), (a)(4), (a)(5), (a)(6), and (e);
b. Redesignating existing paragraphs (a)(7) and (a)(8) as
paragraphs (a)(9) and (a)(10), respectively; and revising newly
designated paragraphs (a)(9) and (a)(10); and
c. Adding new paragraphs (a)(7) and (a)(8) to read as follows:
Sec. 75.21 Quality assurance and quality control requirements.
(a) * * *
(2) The owner or operator shall ensure that each non-redundant
backup CEMS meets the quality assurance requirements of Sec. 75.20(d)
for each day and quarter that the system is used to report data.
* * * * *
(4) The owner or operator of a unit with an SO2
continuous emission monitoring system is not required to perform the
daily or quarterly assessments of the SO2 monitoring system
under appendix B to this part on any day or in any calendar quarter in
which only gaseous fuel is combusted in the unit if, during those days
and calendar quarters, SO2 emissions are determined in
accordance with Sec. 75.11(e)(1) or (e)(2). However, such assessments
are permissible, and if any daily calibration error test or linearity
test of the SO2 monitoring system is failed while the unit
is combusting only gaseous fuel, the SO2 monitoring system
shall be considered out-of-control. The length of the out-of-control
period shall be determined in accordance with the applicable procedures
in section 2.1.4 or 2.2.3 of appendix B to this part.
(5) For a unit with an SO2 continuous monitoring system,
in which gaseous fuel that is very low sulfur fuel (as defined in
Sec. 72.2 of this chapter) is sometimes burned as a primary or backup
fuel and in which higher-sulfur fuel(s) such as oil or coal are, at
other times, burned as primary or backup fuel(s), the owner shall
perform the relative accuracy test audits of the SO2
monitoring system (as required by section 6.5 of appendix A to this
part and section 2.3.1 of appendix B to this part) only when the
higher-sulfur fuel is combusted in the unit and shall not perform
SO2 relative accuracy test audits when the very low sulfur
gaseous fuel is the only fuel being combusted.
(6) If the designated representative certifies that a unit with an
SO2 monitoring system burns only very low sulfur fuel (as
defined in Sec. 72.2 of this chapter), the SO2 monitoring
system is exempted from the relative accuracy test audit requirements
in appendices A and B to this part.
(7) If the designated representative certifies that a particular
unit with an SO2 monitoring system combusts primarily
fuel(s) that are very low sulfur fuel(s) (as defined in Sec. 72.2 of
this chapter), and combusts higher sulfur fuel (s) only as emergency
backup fuel(s) or for short-term testing, the SO2 monitoring
system shall be exempted from the RATA requirements of appendices A and
B to this part in any calendar year that the unit combusts the higher-
sulfur fuel(s) for no more than 480 hours. If, in a particular calendar
year, the higher-sulfur fuel usage exceeds 480 hours, the owner or
operator shall perform a RATA of the SO2 monitor (while
combusting the higher-sulfur fuel) either by the end of the calendar
quarter in which the exceedance occurs or by the end of a 720 unit (or
stack) operating hour grace period (under section 2.3.3 of appendix B
to this part) following the quarter in which the exceedance occurs.
(8) On and after April 1, 2000, the quality assurance provisions of
Secs. 75.11(e)(3)(i) through 75.11(e)(3)(iv) shall apply to all units
with SO2 monitoring systems during hours in which only very
low sulfur fuel (as defined in Sec. 72.2 of this chapter) is combusted
in the unit.
(9) Provided that a unit with an SO2 monitoring system
is not exempted under paragraphs (a)(6) or (a)(7) of this section from
the SO2 RATA requirements of this part, any calendar quarter
during which a unit combusts only very low sulfur fuel (as defined in
Sec. 72.2 of this chapter) shall be excluded in determining the quarter
in which the next relative accuracy test audit must be performed for
the SO2 monitoring system. However, no more than eight
successive calendar quarters shall elapse after a relative accuracy
test audit of an SO2 monitoring system, without a subsequent
relative accuracy test audit having been performed. The owner or
operator shall ensure that a relative accuracy test audit is performed,
in accordance with paragraph (a)(5) of this section, either by the end
of the eighth successive elapsed calendar quarter since the last RATA
or by the end of a 720 unit (or stack) operating hour grace period, as
provided in section 2.3.3 of appendix B to this part.
(10) The owner or operator who, in accordance with
Sec. 75.11(e)(1), uses a certified flow monitor and a certified diluent
monitor and Equation F-23 in appendix F to this part to calculate
SO2
[[Page 28600]]
emissions during hours in which a unit combusts only natural gas or
pipeline natural gas (as defined in Sec. 72.2 of this chapter) shall
meet all quality control and quality assurance requirements in appendix
B to this part for the flow monitor and the diluent monitor.
* * * * *
(e) Consequences of audits. The owner or operator shall invalidate
data from a continuous emission monitoring system or continuous opacity
monitoring system upon failure of an audit under appendix B to this
part or any other audit, beginning with the unit operating hour of
completion of a failed audit as determined by the Administrator. The
owner or operator shall not use invalidated data for reporting either
emissions or heat input, nor for calculating monitor data availability.
(1) Audit decertification. Whenever both an audit of a continuous
emission or opacity monitoring system (or component thereof, including
the data acquisition and handling system), of any excepted monitoring
system under appendix D or E to this part, or of any alternative
monitoring system under subpart E of this part, and a review of the
initial certification application or of a recertification application,
reveal that any system or component should not have been certified or
recertified because it did not meet a particular performance
specification or other requirement of this part, both at the time of
the initial certification or recertification application submission and
at the time of the audit, the Administrator will issue a notice of
disapproval of the certification status of such system or component.
For the purposes of this paragraph, an audit shall be either a field
audit of the facility or an audit of any information submitted to EPA
or the State agency regarding the facility. By issuing the notice of
disapproval, the certification status is revoked prospectively by the
Administrator. The data measured and recorded by each system shall not
be considered valid quality-assured data from the date of issuance of
the notification of the revoked certification status until the date and
time that the owner or operator completes subsequently approved initial
certification or recertification tests. The owner or operator shall
follow the procedures in Sec. 75.20(a)(5) for initial certification or
Sec. 75.20(b)(5) for recertification to replace, prospectively, all of
the invalid, non-quality-assured data for each disapproved system.
(2) Out-of-control period. Whenever a continuous emission
monitoring system or continuous opacity monitoring system fails a
quality assurance audit or any another audit, the system is out-of-
control. The owner or operator shall follow the procedures for out-of-
control periods in Sec. 75.24.
21. Section 75.22 is amended by adding a sentence to the end of the
introductory text of paragraph (a) and by revising paragraphs (a)(2),
(a)(4), (b)(4) and the introductory text of paragraph (c)(1) to read as
follows:
Sec. 75.22 Reference test methods.
(a) * * * Unless otherwise specified in this part, use only
codified versions of Methods 3A, 4, 6C and 7E revised as of July 1,
1995 or July 1, 1996 or July 1, 1997.
* * * * *
(2) Method 2 or its allowable alternatives, as provided in appendix
A to part 60 of this chapter, except for Methods 2B and 2E, are the
reference methods for determination of volumetric flow.
* * * * *
(4) Method 4 (either the standard procedure described in section 2
of the method or the moisture approximation procedure described in
section 3 of the method) shall be used to correct pollutant
concentrations from a dry basis to a wet basis (or from a wet basis to
a dry basis) and shall be used when relative accuracy test audits of
continuous moisture monitoring systems are conducted. For the purpose
of determining the stack gas molecular weight, however, the alternative
techniques for approximating the stack gas moisture content described
in section 1.2 of Method 4 may be used in lieu of the procedures in
sections 2 and 3 of the method.
* * * * *
(b) * * *
(4) Method 2, or its allowable alternatives, as provided in
appendix A to part 60 of this chapter, except for Methods 2B and 2E,
for determining volumetric flow. The sample point(s) for reference
methods shall be located according to the provisions of section 6.5.5
of appendix A to this part.
(c)(1) Instrumental EPA Reference Methods 3A, 6C, 7E, and 20 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:
* * * * *
22. Section 75.24 is amended by revising the section title and by
revising paragraph (d) to read as follows:
Sec. 75.24 Out-of-control periods and adjustment for system bias.
* * * * *
(d) When the bias test indicates that an SO2 monitor, a
flow monitor, a NOX-diluent continuous emission monitoring
system or a NOX concentration monitoring system used to
determine NOX mass emissions, as defined in
Sec. 75.71(a)(2), is biased low (i.e., the arithmetic mean of the
differences between the reference method value and the monitor or
monitoring system measurements in a relative accuracy test audit exceed
the bias statistic in section 7 of appendix A to this part), the owner
or operator shall adjust the monitor or continuous emission monitoring
system to eliminate the cause of bias such that it passes the bias test
or calculate and use the bias adjustment factor as specified in section
2.3.4 of appendix B to this part.
* * * * *
Subpart D--Missing Data Substitution Procedures
23. Section 75.30 is amended by revising paragraphs (a)(3) and
(a)(4), adding new paragraphs (a)(5) and (a)(6), revising the first
sentence of paragraph (b) and revising paragraph (d) to read as
follows:
Sec. 75.30 General provisions.
(a) * * *
(3) A valid, quality-assured hour of NOX emission rate
data (in lb/mmBtu) has not been measured or recorded for an affected
unit, either by a certified NOX-diluent continuous emission
monitoring system or by an approved alternative monitoring system under
subpart E of this part; or
(4) A valid, quality-assured hour of CO2 concentration
data (in percent CO2, or percent O2 converted to
percent CO2 using the procedures in appendix F to this part)
has not been measured and recorded for an affected unit, either by a
certified CO2 continuous emission monitoring system or by an
approved alternative monitoring method under subpart E of this part; or
(5) A valid, quality-assured hour of NOX concentration
data (in ppm) has not been measured or recorded for an affected unit,
either by a certified NOX concentration monitoring system
used to determine NOX mass emissions, as defined in
Sec. 75.71(a)(2), or by an approved alternative monitoring system under
subpart E of this part; or
(6) A valid, quality-assured hour of CO2 or
O2 concentration data (in percent CO2, or percent
O2) used for the determination of heat input has not been
measured and recorded for an
[[Page 28601]]
affected unit, either by a certified CO2 or O2
diluent monitor, or by an approved alternative monitoring method under
subpart E of this part.
(b) However, the owner or operator shall have no need to provide
substitute data according to the missing data procedures in this
subpart if the owner or operator uses SO2, CO2,
NOX, or O2 concentration, flow rate, or
NOX emission rate data recorded from either a certified
redundant or regular non-redundant backup CEMS, a like-kind replacement
non-redundant backup analyzer, or a backup reference method monitoring
system when the certified primary monitor is not operating or is out-
of-control. * * *
* * * * *
(d) The owner or operator shall comply with the applicable
provisions of this paragraph during hours in which a unit with an
SO2 continuous emission monitoring system combusts only
gaseous fuel.
(1) Whenever a unit with an SO2 CEMS combusts only
natural gas or pipeline natural gas (as defined in Sec. 72.2 of this
chapter) and the owner or operator is using the procedures in section 7
of appendix F to this part to determine SO2 mass emissions
pursuant to Sec. 75.11(e)(1), the owner or operator shall, for purposes
of reporting heat input data under Sec. 75.54(b)(5) or
Sec. 75.57(b)(5), as applicable, and for the calculation of
SO2 mass emissions using Equation F-23 in section 7 of
appendix F to this part, substitute for missing data from a flow
monitoring system, CO2 diluent monitor or O2
diluent monitor using the missing data substitution procedures in
Sec. 75.36.
(2) Whenever a unit with an SO2 CEMS combusts gaseous
fuel and the owner or operator uses the gas sampling and analysis and
fuel flow procedures in appendix D to this part to determine
SO2 mass emissions pursuant to Sec. 75.11(e)(2), the owner
or operator shall substitute for missing total sulfur content, gross
calorific value, and fuel flowmeter data using the missing data
procedures in appendix D to this part and shall also, for purposes of
reporting heat input data under Sec. 75.54(b)(5) or Sec. 75.57(b)(5),
as applicable, substitute for missing data from a flow monitoring
system, CO2 diluent monitor, or O2 diluent
monitor using the missing data substitution procedures in Sec. 75.36.
(3) The owner or operator of a unit with an SO2
monitoring system shall not include hours when the unit combusts only
gaseous fuel in the SO2 data availability calculations in
Sec. 75.32 or in the calculations of substitute SO2 data
using the procedures of either Sec. 75.31 or Sec. 75.33, for hours when
SO2 emissions are determined in accordance with
Sec. 75.11(e)(1) or (e)(2). For the purpose of the missing data and
availability procedures for SO2 pollutant concentration
monitors in Secs. 75.31 and 75.33 only, all hours during which the unit
combusts only gaseous fuel shall be excluded from the definition of
``monitor operating hour,'' ``quality assured monitor operating hour,''
``unit operating hour,'' and ``unit operating day,'' when
SO2 emissions are determined in accordance with
Sec. 75.11(e)(1) or (e)(2).
(4) During all hours in which a unit with an SO2
continuous emission monitoring system combusts only gaseous fuel and
the owner or operator uses the SO2 monitoring system to
determine SO2 mass emissions pursuant to Sec. 75.11(e)(3),
the owner or operator shall determine the percent monitor data
availability for SO2 in accordance with Sec. 75.32 and shall
use the standard SO2 missing data procedures of Sec. 75.33.
24. Section 75.31 is revised to read as follows:
Sec. 75.31 Initial missing data procedures.
(a) During the first 720 quality-assured monitor operating hours
following initial certification (i.e., the date and time at which
quality assured data begins to be recorded by the CEMS) of an
SO2 pollutant concentration monitor, or a CO2
pollutant concentration monitor (or an O2 monitor used to
determine CO2 concentration in accordance with appendix F to
this part), or an O2 or CO2 diluent monitor used
to calculate heat input or a moisture monitoring system, and during the
first 2,160 quality-assured monitor operating hours following initial
certification of a flow monitor, or a NOX-diluent monitoring
system, or a NOX concentration monitoring system used to
determine NOX mass emissions, the owner or operator shall
provide substitute data required under this subpart according to the
procedures in paragraphs (b) and (c) of this section. The owner or
operator of a unit shall use these procedures for no longer than three
years (26,280 clock hours) following initial certification.
(b) SO2, CO2, or O2 concentration
data and moisture data. For each hour of missing SO2 or
CO2 pollutant concentration data (including CO2
data converted from O2 data using the procedures in appendix
F of this part), or missing O2 or CO2 diluent
concentration data used to calculate heat input, or missing moisture
data, the owner or operator shall calculate the substitute data as
follows:
(1) Whenever prior quality-assured data exist, the owner or
operator shall substitute, by means of the data acquisition and
handling system, for each hour of missing data, the average of the
hourly SO2, CO2 or O2 concentrations
or moisture percentages recorded by a certified monitor for the unit
operating hour immediately before and the unit operating hour
immediately after the missing data period.
(2) Whenever no prior quality assured SO2,
CO2 or O2 concentration data or moisture data
exist, the owner or operator shall substitute, as applicable, for each
hour of missing data, the maximum potential SO2
concentration or the maximum potential CO2 concentration or
the minimum potential O2 concentration or (unless Equation
19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60 of this
chapter is used to determine NOX emission rate) the minimum
potential moisture percentage, as specified, respectively, in sections
2.1.1.1, 2.1.3.1, 2.1.3.2 and 2.1.5 of appendix A to this part. If
Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60 of
this chapter is used to determine NOX emission rate,
substitute the maximum potential moisture percentage, as specified in
section 2.1.6 of appendix A to this part.
(c) Volumetric flow and NOX emission rate or
NOX concentration data. For each hour of missing volumetric
flow rate data, NOX emission rate data or NOX
concentration data used to determine NOX mass emissions:
(1) Whenever prior quality-assured data exist in the load range
corresponding to the operating load at the time the missing data period
occurred, the owner or operator shall substitute, by means of the
automated data acquisition and handling system, for each hour of
missing data, the average hourly flow rate or NOX emission
rate or NOX concentration recorded by a certified monitoring
system. The average flow rate (or NOX emission rate or
NOX concentration) shall be the arithmetic average of all
data in the corresponding load range as determined using the procedure
in appendix C to this part.
(2) Whenever no prior quality-assured flow or NOX
emission rate or NOX concentration data exist for the
corresponding load range, the owner or operator shall substitute, for
each hour of missing data, the average hourly flow rate or the average
hourly NOX emission rate or NOX concentration at
the next higher level load range for which quality-assured data are
available.
[[Page 28602]]
(3) Whenever no prior quality assured flow rate or NOX
emission rate or NOX concentration data exist for the
corresponding load range, or any higher load range, the owner or
operator shall, as applicable, substitute, for each hour of missing
data, the maximum potential flow rate as specified in section 2.1.4.1
of appendix A to this part or shall substitute the maximum potential
NOX emission rate or the maximum potential NOX
concentration, as specified in section 2.1.2.1 of appendix A to this
part.
25. Section 75.32 is amended by revising paragraph (a) introductory
text and revising the last sentence in paragraph (a)(3) to read as
follows:
Sec. 75.32 Determination of monitor data availability for standard
missing data procedures.
(a) Following initial certification (i.e., the date and time at
which quality assured data begins to be recorded by the CEMS), upon
completion of: the first 720 quality-assured monitor operating hours of
an SO2 pollutant concentration monitor, or a CO2
pollutant concentration monitor (or O2 monitor used to
determine CO2 concentration), or an O2 or
CO2 diluent monitor used to calculate heat input or a
moisture monitoring system; or the first 2,160 quality-assured monitor
operating hours of a flow monitor or a NOX-diluent
monitoring system or a NOX concentration monitoring system,
the owner or operator shall calculate and record, by means of the
automated data acquisition and handling system, the percent monitor
data availability for the SO2 pollutant concentration
monitor, the CO2 pollutant concentration monitor, the
O2 or CO2 diluent monitor used to calculate heat
input, the moisture monitoring system, the flow monitor, the
NOX-diluent monitoring system and the NOX
concentration monitoring system as follows:
* * * * *
(3) * * * The owner or operator of a unit with an SO2
monitoring system shall, when SO2 emissions are determined
in accordance with Sec. 75.11(e)(1) or (e)(2), exclude hours in which a
unit combusts only gaseous fuel from calculations of percent monitor
data availability for SO2 pollutant concentration monitors,
as provided in Sec. 75.30(d).
* * * * *
26. Section 75.33 is amended by revising the title of the section,
by revising paragraphs (a), (b)(3) and (c), and adding a new paragraph
(b)(4) to read as follows:
Sec. 75.33 Standard missing data procedures for SO2,
NOX and flow rate.
(a) Following initial certification (i.e., the date and time at
which quality assured data begins to be recorded by the CEMS) and upon
completion of the first 720 quality-assured monitor operating hours of
the SO2 pollutant concentration monitor or the first 2,160
quality assured monitor operating hours of the flow monitor,
NOX-diluent monitoring system or NOX
concentration monitoring system used to determine NOX mass
emissions, the owner or operator shall provide substitute data required
under this subpart according to the procedures in paragraphs (b) and
(c) of this section and depicted in Table 1 (SO2) and Table
2 of this sectioin (NOX, flow). The owner or operator of a
unit shall substitute for missing data using only quality-assured
monitor operating hours of data from the three years (26,280 clock
hours) prior to the date and time of the missing data period.
Table 1.--Missing Data Procedure for SO2 CEMS, CO2 CEMS, Moisture CEMS and Diluent (CO2 or O2) Monitors for Heat
Input Determination
----------------------------------------------------------------------------------------------------------------
Trigger conditions Calculation routines
----------------------------------------------------------------------------------------------------------------
Monitor data availability Duration (N) of CEMS outage
(percent) (hours) \2\ Method Lookback period
----------------------------------------------------------------------------------------------------------------
95 or more.................... N 24 Average........................ HB/HA.
N > 24 For SO2, CO2 and H2O**, the .................
greater of: HB/HA.
Average...................... 720 hours.*
90th percentile..............
............................ For O2, and H2OX, the lesser .................
of: HB/HA.
Average...................... 720 hours.*
10th percentile..............
90 or more, but below 95...... N 8 Average........................ HB/HA.
N > 8 For SO2, CO2 and H2O**, the .................
greater of: HB/HA.
Average...................... 720 hours.*
95th percentile..............
............................ For O2, and H2OX, the lesser .................
of: HB/HA.
Average...................... 720 hours.*
5th percentile...............
80 or more, but below 90...... N > 0 For SO2, CO2 and H2O**,........ .................
Maximum value \1\............ 720 hours.*
............................ For O2, and H2OX: .................
Minimum value\1\............. 720 hours.*
Below 80...................... N > 0 Maximum potential concentration
or % (for SO2, CO2 and H2O**)
or
............................ Minimum potential concentration None.
or % (for O2, and H2OX).
----------------------------------------------------------------------------------------------------------------
HB/HA = hour before and hour after the CEMS outage.
* = Quality-assured, monitor operating hours, during unit operation.
\1\ Where unit with add-on emission controls can demonstrate that the controls are operating properly, as
provided in Sec. 75.34, the unit may, upon approval, use the maximum controlled emission rate from the
previous 720 operating hours.
\2\ During unit operating hours.
X Use this algorithm for moisture except when Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60
of this chapter is used for NOX emission rate.
** Use this algorithm for moisture only when Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60
of this chapter is used for NOX emission rate.
[[Page 28603]]
Table 2.--Missing Data Procedure for NOX-Diluent CEMS, NOX Concentration CEMS and Flow Rate CEMS
--------------------------------------------------------------------------------------------------------------------------------------------------------
Trigger conditions Calculation routines
--------------------------------------------------------------------------------------------------------------------------------------------------------
Monitor data availability Duration (N) of CEMS outage
(percent) (hours) 2 Method Lookback period Load ranges
--------------------------------------------------------------------------------------------------------------------------------------------------------
95 or more........................ N 24................ Average............................. 2160 hours*.............. Yes.
N > 24.......................... The greater of: .................
Average........................... HB/HA.................... No.
90th percentile................... 2160 hours*.............. Yes.
90 or more, but below 95.......... N 8................. Average............................. 2160 hours*.............. Yes.
N > 8........................... The greater of: .................
Average........................... HB/HA.................... No.
95th percentile................... 2160 hours*.............. Yes.
80 or more, but below 90.......... N > 0........................... Maximum value 1..................... 2160 hours*.............. Yes.
Below 80.......................... N > 0........................... Maximum NOX emission rate; or None..................... No.
maximum potential NOX
concentration; or maximum potential
flow rate.
--------------------------------------------------------------------------------------------------------------------------------------------------------
HB/HA=hour before and hour after the CEMS outage.
*=Quality-assured, monitor operating hours, in the corresponding load range (``load bin'') for each hour of the missing data period.
\1\ Where unit with add-on emission controls can demonstrate that the controls are operating properly, as provided in Sec. 75.34, the unit may, upon
approval, use the maximum controlled emission rate from the previous 720 operating hours.
\2\ During unit operating hours.
(b) * * *
(3) Whenever the monitor data availability is at least 80.0 percent
but less than 90.0 percent, the owner or operator shall substitute for
each missing data period the maximum hourly SO2
concentration recorded by an SO2 pollutant concentration
monitor during the previous 720 quality-assured monitor operating
hours.
(4) Whenever the monitor data availability is less than 80.0
percent, the owner or operator shall substitute for each missing data
period the maximum potential SO2 concentration, as defined
in section 2.1.1.1 of appendix A to this part.
(c) Volumetric flow rate, NOX emission rate and
NOX concentration data. For each hour of missing volumetric
flow rate data, NOX emission rate data, or NOX
concentration data used to determine NOX mass emissions:
(1) Whenever the monitor or continuous emission monitoring system
data availability is equal to or greater than 95.0 percent, the owner
or operator shall calculate substitute data by means of the automated
data acquisition and handling system for each hour of each missing data
period according to the following procedures:
(i) For a missing data period less than or equal to 24 hours,
substitute, as applicable, for each missing hour, the arithmetic
average of the flow rates or NOX emission rates or
NOX concentrations recorded by a monitoring system during
the previous 2,160 quality assured monitor operating hours at the
corresponding unit load range, as determined using the procedure in
appendix C to this part.
(ii) For a missing data period greater than 24 hours, substitute,
as applicable, for each missing hour, the greater of:
(A) The 90th percentile hourly flow rate or the 90th percentile
NOX emission rate or the 90th percentile NOX
concentration recorded by a monitoring system during the previous 2,160
quality-assured monitor operating hours at the corresponding unit load
range, as determined using the procedure in appendix C to this part; or
(B) The average of the recorded hourly flow rates, NOX
emission rates or NOX concentrations recorded by a
monitoring system for the hour before and the hour after the missing
data period.
(2) Whenever the monitor or continuous emission monitoring system
data availability is at least 90.0 percent but less than 95.0 percent,
the owner or operator shall calculate substitute data by means of the
automated data acquisition and handling system for each hour of each
missing data period according to the following procedures:
(i) For a missing data period of less than or equal to 8 hours,
substitute, as applicable, the arithmetic average hourly flow rate or
NOX emission rate or NOX concentration recorded
by a monitoring system during the previous 2,160 quality-assured
monitor operating hours at the corresponding unit load range, as
determined using the procedure in appendix C to this part.
(ii) For a missing data period greater than 8 hours, substitute, as
applicable, for each missing hour, the greater of:
(A) The 95th percentile hourly flow rate or the 95th percentile
NOX emission rate or the 95th percentile NOX
concentration recorded by a monitoring system during the previous 2,160
quality-assured monitor operating hours at the corresponding unit load
range, as determined using the procedure in appendix C to this part; or
(B) The average of the hourly flow rates, NOX emission
rates or NOX concentrations recorded by a monitoring system
for the hour before and the hour after the missing data period.
(3) Whenever the monitor data availability is at least 80.0 percent
but less than 90.0 percent, the owner or operator shall, by means of
the automated data acquisition and handling system, substitute, as
applicable, for each hour of each missing data period, the maximum
hourly flow rate or the maximum hourly NOX emission rate or
the maximum hourly NOX concentration recorded during the
previous 2,160 quality-assured monitor operating hours at the
corresponding unit load range, as determined using the procedure in
section 2 of appendix C to this part.
(4) Whenever the monitor data availability is less than 80.0
percent, the owner or operator shall substitute, as applicable, for
each hour of each missing data period, the maximum potential flow rate,
as defined in section 2.1.4.1 of appendix A to this part, or the
maximum NOX emission rate, as defined in section 2.1.2.1 of
appendix A to this part, or the maximum potential NOX
concentration, as defined in section 2.1.2.1 of appendix A to this
part.
(5) Whenever no prior quality-assured flow rate data,
NOX concentration data or NOX emission rate data
exist for the corresponding load range, the owner or operator shall
substitute, as applicable, for each hour of missing data, the
[[Page 28604]]
maximum hourly flow rate or the maximum hourly NOX
concentration or maximum hourly NOX emission rate at the
next higher level load range for which quality-assured data are
available.
(6) Whenever no prior quality-assured flow rate data,
NOX concentration data or NOX emission rate data
exist for either the corresponding load range or a higher load range,
the owner or operator shall substitute, as applicable, either the
maximum potential NOX emission rate or the maximum potential
NOX concentration, as defined in section 2.1.2.1 of appendix
A to this part or the maximum potential flow rate, as defined in
section 2.1.4.1 of appendix A to this part.
27-28. Section 75.34 is amended by revising paragraph (a)(3) to
read as follows:
Sec. 75.34 Units with add-on emission controls.
(a) * * *
(3) The designated representative may petition the Administrator
under Sec. 75.66 for approval of site-specific parametric monitoring
procedure(s) for calculating substitute data for missing SO2
pollutant concentration, NOX pollutant concentration, and
NOX emission rate data in accordance with the requirements
of paragraphs (b) and (c) of this section and appendix C to this part.
The owner or operator shall record the data required in appendix C to
this part, pursuant to Sec. 75.55(b) or Sec. 75.58(b), as applicable.
* * * * *
29. Section 75.35 is amended by revising paragraphs (a) and (b) and
by adding paragraph (d) to read as follows:
Sec. 75.35 Missing data procedures for CO2 data.
(a) On and after April 1, 2000, the owner or operator of a unit
with a CO2 continuous emission monitoring system for
determining CO2 mass emissions in accordance with Sec. 75.10
(or an O2 monitor that is used to determine CO2
concentration in accordance with appendix F to this part) shall
substitute for missing CO2 pollutant concentration data
using the procedures of paragraphs (b) and (d) of this section. The
procedures of paragraphs (b) and (d) of this section shall also be used
on and after April 1, 2000 to provide substitute CO2 data
for heat input determination. Prior to April 1, 2000, the owner or
operator shall substitute for missing CO2 data using either
the procedures of paragraphs (b) and (c), or paragraphs (b) and (d) of
this section.
(b) During the first 720 quality assured monitor operating hours
following initial certification (i.e., the date and time at which
quality assured data begins to be recorded by the CEMS), of the
CO2 continuous emission monitoring system, or (for a
previously certified CO2 monitoring system) during the 720
quality assured monitor operating hours preceding implementation of the
standard missing data procedures in paragraph (d) of this section, the
owner or operator shall provide substitute CO2 pollutant
concentration data or substitute CO2 data for heat input
determination, as applicable, according to the procedures in
Sec. 75.31(b).
* * * * *
(d) Upon completion of 720 quality assured monitor operating hours
using the initial missing data procedures of Sec. 75.31(b), the owner
or operator shall provide substitute data for CO2
concentration data or substitute CO2 data for heat input
determination, as applicable, in accordance with the procedures in
Sec. 75.33(b), except that the term ``CO2 concentration''
shall apply rather than ``SO2 concentration'' and the term
``CO2 pollutant concentration monitor'' or ``CO2
diluent monitor'' shall apply rather than ``SO2 pollutant
concentration monitor.''
30. Section 75.36 is amended by revising the section heading and
paragraphs (a), (b) and (d) to read as follows:
Sec. 75.36 Missing data procedures for heat input determinations.
(a) When hourly heat input is determined using a flow monitoring
system and a diluent gas (O2 or CO2) monitor,
substitute data must be provided to calculate the heat input whenever
quality assured data are unavailable from the flow monitor, the diluent
gas monitor, or both. When flow rate data are unavailable, substitute
flow rate data for the heat input calculation shall be provided
according to Sec. 75.31 or Sec. 75.33, as applicable. On and after
April 1, 2000, when diluent gas data are unavailable, the owner or
operator shall provide substitute O2 or CO2 data
for the heat input calculations in accordance with paragraphs (b) and
(d) of this section. Prior to April 1, 2000, the owner or operator
shall substitute for missing CO2 or O2
concentration data in accordance with either paragraphs (c) and (d) or
paragraphs (b) and (d) of this section.
(b) During the first 720 quality assured monitor operating hours
following initial certification (i.e., the date and time at which
quality assured data begins to be recorded by the CEMS), or (for a
previously certified CO2 or O2 monitor) during
the 720 quality assured monitor operating hours preceding
implementation of the standard missing data procedures in paragraph (d)
of this section, the owner or operator shall provide substitute
CO2 or O2 data, as applicable, for the
calculation of heat input (under section 5.2 of appendix F to this
part) according to Sec. 75.31(b).
(c) * * *
(d) Upon completion of 720 quality-assured monitor operating hours
using the initial missing data procedures of Sec. 75.31(b), the owner
or operator shall provide substitute data for CO2 or
O2 concentration to calculate heat input, as follows.
Substitute CO2 data for heat input determinations shall be
provided according to Sec. 75.35(d). Substitute O2 data for
the heat input determinations shall be provided in accordance with the
procedures in Sec. 75.33(b), except that the term ``O2
concentration'' shall apply rather than the term ``SO2
concentration'' and the term ``O2 diluent monitor'' shall
apply rather than the term ``SO2 pollutant concentration
monitor.'' In addition, the term ``substitute the lesser of'' shall
apply rather than ``substitute the greater of;'' the terms ``minimum
hourly O2 concentration'' and ``minimum potential
O2 concentration, as determined under section 2.1.3.2 of
appendix A to this part'' shall apply rather than, respectively, the
terms ``maximum hourly SO2 concentration'' and ``maximum
potential SO2 concentration, as determined under section
2.1.1.1 of appendix A to this part;'' and the terms ``10th percentile''
and ``5th percentile'' shall apply rather than, respectively, the terms
``90th percentile'' and ``95th percentile'' (see Table 1 of
Sec. 75.33).
31. Section 75.37 is added to subpart D to read as follows:
Sec. 75.37 Missing data procedures for moisture.
(a) On and after April 1, 2000, the owner or operator of a unit
with a continuous moisture monitoring system shall substitute for
missing moisture data using the procedures of this section. Prior to
April 1, 2000, the owner or operator may substitute for missing
moisture data using the procedures of this section.
(b) Where no prior quality assured moisture data exist, substitute
the minimum potential moisture percentage, from section 2.1.5 of
appendix A to this part, except when Equation 19-3, 19-4 or 19-8 in
Method 19 in appendix A to part 60 of this chapter is used to determine
NOX emission rate. If Equation 19-3, 19-4 or 19-8 in Method
19 in appendix A to part 60 of this chapter is used to
[[Page 28605]]
determine NOX emission rate, substitute the maximum
potential moisture percentage, as specified in section 2.1.6 of
appendix A to this part.
(c) During the first 720 quality assured monitor operating hours
following initial certification (i.e., the date and time at which
quality assured data begins to be recorded by the moisture monitoring
system), the owner or operator shall provide substitute data for
moisture according to Sec. 75.31(b).
(d) Upon completion of the first 720 quality-assured monitor
operating hours following initial certification of the moisture
monitoring system, the owner or operator shall provide substitute data
for moisture as follows:
(1) Unless Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A
to part 60 of this chapter is used to determine NOX emission
rate, follow the missing data procedures in Sec. 75.33(b), except that
the term ``moisture percentage'' shall apply rather than
``SO2 concentration;'' the term ``moisture monitoring
system'' shall apply rather than the term ``SO2 pollutant
concentration monitor;'' the term ``substitute the lesser of'' shall
apply rather than ``substitute the greater of;'' the terms ``minimum
hourly moisture percentage'' and ``minimum potential moisture
percentage, as determined under section 2.1.5 of appendix A to this
part'' shall apply rather than, respectively, the terms ``maximum
hourly SO2 concentration'' and ``maximum potential
SO2 concentration, as determined under section 2.1.1.1 of
appendix A to this part;'' and the terms ``10th percentile'' and ``5th
percentile'' shall apply rather than, respectively, the terms ``90th
percentile'' and ``95th percentile'' (see Table 1 of Sec. 75.33).
(2) When Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to
part 60 of this chapter is used to determine NOX emission
rate:
(i) Provided that none of the following equations is used to
determine SO2 emissions, CO2 emissions or heat
input: Equation F-2, F-14b, F-16, F-17, or F-18 in appendix F to this
part, or Equation 19-5 or 19-9 in Method 19 in appendix A to part 60 of
this chapter, use the missing data procedures in Sec. 75.33(b), except
that the term ``moisture percentage'' shall apply rather than
``SO2 concentration'' and the term ``moisture monitoring
system'' shall apply rather than ``SO2 pollutant
concentration monitor;'' or
(ii) If any of the following equations is used to determine
SO2 emissions, CO2 emissions or heat input:
Equation F-2, F-14b, F-16, F-17, or F-18 in appendix F to this part, or
Equation 19-5 or 19-9 in Method 19 in appendix A to part 60 of this
chapter, the owner or operator shall petition the Administrator under
Sec. 75.66(l) for permission to use an alternative moisture missing
data procedure.
Subpart E--Alternative Monitoring Systems
32. Section 75.48 is amended by revising paragraphs (a)(3)(ii) and
(a) (3)(iii), and correcting paragraphs (a)(3)(iv), (a)(3)(viii),
(a)(3)(ix), and (a)(3)(xi) to read as follows:
Sec. 75.48 Petition for an alternative monitoring system.
(a) * * *
(3) * * *
(ii) Hourly test data for the alternative monitoring system at each
required operating level and fuel type. The fuel type, operating level
and gross unit load shall be recorded.
(iii) Hourly test data for the continuous emissions monitoring
system at each required operating level and fuel type. The fuel type,
operating level and gross unit load shall be recorded.
(iv) Arithmetic mean of the alternative monitoring system
measurement values, as specified in Equation 25 in Sec. 75.41(c) of
this part, of the continuous emission monitoring system values, as
specified in Equation 26 in Sec. 75.41(c) of this part, and of their
differences.
* * * * *
(viii) Variance of the measured values for the alternative
monitoring system and of the measured values for the continuous
emission monitoring system, as specified in Equation 23 in
Sec. 75.41(c) of this part.
(ix) F-statistic, as specified in Equation 24 in Sec. 75.41(c) of
this part.
* * * * *
(xi) Coefficient of correlation, r, as specified in Equation 27 in
Sec. 75.41(c) of this part.
* * * * *
Subpart F--Recordkeeping Requirements
Sec. 75.50 [Removed and Reserved]
33. Section 75.50 is removed and reserved.
Sec. 75.51 [Removed and Reserved]
34. Section 75.51 is removed and reserved.
Sec. 75.52 [Removed and Reserved]
35. Section 75.52 is removed and reserved.
Sec. 75.53 Monitoring plan.
36. Section 75.53 is amended by revising paragraphs (a) and (b),
correcting paragraph (c)(1), and adding paragraphs (e) and (f) to read
as follows:
(a) General provisions. (1) The provisions of paragraphs (c) and
(d) of this section shall remain in effect prior to April 1, 2000. The
owner or operator shall meet the requirements of either paragraphs (a)
through (d) or paragraphs (a), (b), (e) and (f) of this section prior
to April 1, 2000. On and after April 1, 2000, the owner or operator
shall meet the requirements of paragraphs (a), (b), (e) and (f) of this
section only. In addition, the provisions in paragraphs (e) and (f) 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 April 1, 2000.
(2) The owner or operator of an affected unit shall prepare and
maintain a monitoring plan. Except as provided in paragraphs (d) or (f)
of this section (as applicable), a monitoring plan shall contain
sufficient information on the continuous emission or opacity monitoring
systems, excepted methodology under Sec. 75.19, or excepted monitoring
systems under appendix D or E to this part and the use of data derived
from these systems to demonstrate that all unit SO2
emissions, NOX emissions, CO2 emissions, and
opacity are monitored and reported.
(b) Whenever the owner or operator makes a replacement,
modification, or change in the certified CEMS, continuous opacity
monitoring system, excepted methodology under Sec. 75.19, excepted
monitoring system under appendix D or E to this part, or alternative
monitoring system under subpart E of this part, including a change in
the automated data acquisition and handling system or in the flue gas
handling system, that affects information reported in the monitoring
plan (e.g., a change to a serial number for a component of a monitoring
system), then the owner or operator shall update the monitoring plan.
(c) * * *
(1) Precertification information, including, as applicable, the
identification of the test strategy, protocol for the relative accuracy
test audit, other relevant test information, span calculations, and
apportionment strategies under Secs. 75.10 through 75.18 of this part.
* * * * *
(e) Contents of the monitoring plan. Each monitoring plan shall
contain the information in paragraph (e)(1) of this section in
electronic format and the information in paragraph (e)(2) of this
section in hardcopy format. Electronic storage of all monitoring plan
[[Page 28606]]
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) ORISPL numbers developed by the Department of
Energy and used in the National Allowance Data Base, for all affected
units involved in the monitoring plan, with the following information
for each unit:
(A) Short name;
(B) Classification of the unit as one of the following: Phase I
(including substitution or compensating units), Phase II, new, or
nonaffected;
(C) Type of boiler (or boilers for a group of units using a common
stack);
(D) Type of fuel(s) fired by boiler, fuel type start and end dates,
primary/secondary fuel indicator, and, if more than one fuel, the fuel
classification of the boiler;
(E) Type(s) of emission controls for SO2,
NOX, and particulates installed or to be installed,
including specifications of whether such controls are pre-combustion,
post-combustion, or integral to the combustion process; control
equipment code, installation date, and optimization date; control
equipment retirement date (if applicable); and an indicator for whether
the controls are an original installation;
(F) Maximum hourly heat input capacity;
(G) Date of first commercial operation;
(H) Unit retirement date (if applicable);
(I) Maximum hourly gross load (in MW, rounded to the nearest MW, or
steam load in 1000 lb/hr, rounded to the nearest 100 lb/hr);
(J) Identification of all units using a common stack;
(K) Activation date for the stack/pipe;
(L) Retirement date of the stack/pipe (if applicable); and
(M) Indicator of whether the stack is a bypass stack.
(ii) For each unit and parameter required to be monitored,
identification of monitoring methodology information, consisting of
monitoring methodology, type of fuel associated with the methodology,
primary/secondary methodology indicator, missing data approach for the
methodology, methodology start date, and methodology end date (if
applicable).
(iii) The following information:
(A) Program(s) for which the EDR is submitted;
(B) Unit classification;
(C) Reporting frequency;
(D) Program participation date;
(E) State regulation code (if applicable); and
(F) State or local regulatory agency code.
(iv) Identification and description of each monitoring component
(including each monitor and its identifiable components, such as
analyzer and/or probe) in the CEMS (e.g., SO2 pollutant
concentration monitor, flow monitor, moisture monitor; NOX
pollutant concentration monitor and diluent gas monitor), the
continuous opacity monitoring system, or the excepted monitoring system
(e.g., fuel flowmeter, data acquisition and handling system),
including:
(A) Manufacturer, model number and serial number;
(B) Component/system identification code assigned by the utility to
each identifiable monitoring component (such as the analyzer and/or
probe). Each code shall use a three-digit format, unique to each
monitoring component and unique to each monitoring system;
(C) Designation of the component type and method of sample
acquisition or operation, (e.g., in situ pollutant concentration
monitor or thermal flow monitor);
(D) Designation of the system as a primary, redundant backup, non-
redundant backup, data backup, or reference method backup system, as
provided in Sec. 75.10(e);
(E) First and last dates the system reported data;
(F) Status of the monitoring component; and
(G) Parameter monitored.
(v) Identification and description of all major hardware and
software components of the automated data acquisition and handling
system, including:
(A) Hardware components that perform emission calculations or store
data for quarterly reporting purposes (provide the manufacturer and
model number); and
(B) Software components (provide the identification of the provider
and model/version number).
(vi) Explicit formulas for each measured emission parameter, using
component/system identification codes for the primary system used to
measure the parameter that links CEMS or excepted monitoring system
observations with reported concentrations, mass emissions, or emission
rates, according to the conversions listed in appendix D or E to this
part. Formulas 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). The formulas must contain all constants and factors required
to derive mass emissions or emission rates from component/system code
observations and an indication of whether the formula is being added,
corrected, deleted, or is unchanged. Each emissions formula is
identified with a unique three digit code. The owner or operator of a
low mass emissions unit for which the owner or operator is using the
optional low mass emissions excepted methodology in Sec. 75.19(c) is
not required to report such formulas.
(vii) Inside cross-sectional area (ft2) at flue exit
(for all units) and at flow monitoring location (for units with flow
monitors, only).
(viii) Stack height (ft) above ground level and stack base
elevation above sea level.
(ix) Part 75 monitoring location identification, facility
identification code as assigned by the Administrator for use under the
Acid Rain Program or this part, and the following information, as
reported to the Energy Information Administration (EIA): facility
identification number, flue identification number, boiler
identification number, reporting year, and 767 reporting indicator.
(x) For each parameter monitored: scale, maximum potential
concentration (and method of calculation), maximum expected
concentration (if applicable) (and method of calculation), maximum
potential flow rate (and method of calculation), maximum potential
NOX emission rate, span value, full-scale range, daily
calibration units of measure, span effective date/hour, span
inactivation date/hour, indication of whether dual spans are required,
default high range value, flow rate span, and flow rate span value and
full scale value (in scfh) for each unit or stack using SO2,
NOX, CO2, O2, or flow component
monitors.
(xi) 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 during controlled/uncontrolled 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
[[Page 28607]]
(I) For units using the excepted methodology under Sec. 75.19, the
applicable SO2 emission factor.
(xii) For each unit or common stack (except for peaking units) on
which hardware CEMS are installed:
(A) 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 or thousands of lb/hr of steam;
(B) The load level(s) designated as normal in section 6.5.2.1 of
appendix A to this part, expressed in megawatts or thousands of lb/hr
of steam;
(C) The two load levels (i.e., low, mid, or high) identified in
section 6.5.2.1 of appendix A to this part as the most frequently used;
(D) The date of the load analysis used to determine the normal load
level(s) and the two most frequently-used load levels; and
(E) Activation and deactivation dates, when the normal load
level(s) or two most frequently-used load levels change and are
updated.
(xiii) For each unit for which the optional fuel flow-to-load test
in section 2.1.7 of appendix D to this part is used:
(A) 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 or thousands of lb/hr of steam;
(B) The load level designated as normal, pursuant to section
6.5.2.1 of appendix A to this part, expressed in megawatts or thousands
of lb/hr of steam; and
(C) The date of the load analysis used to determine the normal load
level.
(2) Hardcopy. (i) Information, including (as applicable):
identification of the test strategy; protocol for the relative accuracy
test audit; other relevant test information; calibration gas levels
(percent of span) for the calibration error test and linearity check;
calculations for determining maximum potential concentration, maximum
expected concentration (if applicable), maximum potential flow rate,
maximum potential NOX emission rate, and span; and
apportionment strategies under Secs. 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, monitor components, and stacks
corresponding to the identification numbers provided in paragraphs
(e)(1)(i), (e)(1)(iv), (e)(1)(vi), and (e)(1)(ix) 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.
(f) 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 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) Submission status of the data;
(E) Monitoring system identification code; and
(F) For gaseous fuels fired by the unit, the method used to verify
that the fuel meets the definition in Sec. 72.2 of pipeline natural gas
or natural gas, if applicable, and the demonstration methods used for
other gaseous fuels, if applicable, to determine the appropriate
frequency for sampling for GCV or sulfur content of the fuel.
(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 or gas-fired
unit, as defined in Sec. 72.2 of this chapter, and NOX
correlation test information, including:
(A) Test date;
(B) Test number;
(C) Operating level;
(D) Segment ID of the NOX correlation curve;
(E) NOX monitoring system identification;
(F) Low and high heat input values and corresponding NOX
rates;
(G) Type of fuel; and
(H) To document the unit qualifies as a peaking unit, current
calendar year, capacity factor data as specified in the definition of
peaking unit in Sec. 72.2 of this part, 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
[[Page 28608]]
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 monitoring system recertification, maintenance, or
other event, the designated representative shall include the following
additional information in electronic format in the monitoring plan:
(i) Component/system identification code;
(ii) Event code or code for required test;
(iii) Event begin date and hour;
(iv) Conditionally valid data period begin date and hour (if
applicable);
(v) Date and hour that last test is successfully completed; and
(vi) Indicator of whether conditionally valid data were reported at
the end of the quarter.
(5) For each unit using the low mass emission excepted methodology
under Sec. 75.19 the designated representative shall include the
following additional information in the monitoring plan:
(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 and the emissions calculated
using the methodology which will be used by the unit to estimate future
emissions.
(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 natural gas or fuel oil
and a list of the fuels that are burned or a statement that the unit is
projected to burn only natural gas or fuel oil and a list of the fuels
that are projected to be burned;
(D) A statement that the unit meets the applicability requirements
in Secs. 75.19(a) and (b); and
(E) Any unit historical actual and projected emissions data and
calculated emissions data demonstrating that the affected unit
qualifies as a low mass emissions unit under Secs. 75.19(a) and
75.19(b).
(6) For each gas-fired unit the designated representative shall
include in the monitoring plan, in electronic format, the following:
current calendar year, fuel usage data as specified in the definition
of gas-fired in Sec. 72.2 of this part, and an indication of whether
the data are actual or projected data.
37. Section 75.54 is amended by revising paragraph (a) introductory
text and paragraph (a)(1), and adding a new paragraph (g) to read as
follows:
Sec. 75.54 General recordkeeping provisions.
(a) Recordkeeping requirements for affected sources. On and after
January 1, 1996, and before April 1, 2000, the owner or operator shall
meet the requirements of either this section or Sec. 75.57. On and
after April 1, 2000, the owner or operator shall meet the requirements
of Sec. 75.57. The owner or operator of any affected source subject to
the requirements of this part shall maintain for each affected unit a
file of all measurements, data, reports, and other information required
by this part at the source in a form suitable for inspection for at
least three (3) years from the date of each record. Unless otherwise
provided, throughout this subpart the phrase ``for each affected unit''
also applies to each group of affected or nonaffected units utilizing a
common stack and common monitoring systems, pursuant to Secs. 75.16
through 75.18, or utilizing a common pipe header and common fuel
flowmeter, pursuant to section 2.1.2 of appendix D to this part. The
file shall contain the following information:
(1) The data and information required in paragraphs (b) through (g)
of this section, beginning with the earlier of the date of provisional
certification, or the deadline in Sec. 75.4(a), (b) or (c);
* * * * *
(g) Missing data records. The owner or operator shall record the
causes of any missing data periods and the actions taken by the owner
or operator to cure such causes.
38. Section 75.55 is amended by adding introductory text prior to
paragraph (a), by correcting paragraphs (b)(1)(i), (b)(1)(xi),
(b)(2)(vii), by revising paragraph (e), and by removing paragraph (f)
to read as follows:
Sec. 75.55 General recordkeeping provisions for specific situations.
Before April 1, 2000, the owner or operator shall meet the
requirements of either this section or Sec. 75.58. On and after April
1, 2000, the owner or operator shall meet the requirements of
Sec. 75.58.
* * * * *
(b) * * *
(1) * * *
(i) The information required in Sec. 75.54(c) for SO2
concentration and volumetric flow if either one of these monitors is
still operating:
* * * * *
(xi) Method of determination of SO2 concentration and
volumetric flow, using Codes 1-15 in Table 4 of Sec. 75.54; and
* * * * *
(2) * * *
(vii) Method of determination of NOX emission rate using
Codes 1-15 in Table 4 of Sec. 75.54; and
* * * * *
(e) Specific SO2 emission record provisions during the
combustion of gaseous fuel. (1) If SO2 emissions are
determined in accordance with the provisions in Sec. 75.11(e)(2) during
hours in which only gaseous fuel is combusted in a unit with an
SO2 CEMS, the owner or operator shall record the information
in paragraph (c)(3) of this section in lieu of the information in
Secs. 75.54(c)(1) and (c)(3) or Secs. 75.57(c)(1) and (c)(4), for those
hours.
(2) The provisions of this paragraph apply to a unit which, in
accordance with the provisions of Sec. 75.11(e)(3), uses an
SO2 CEMS to determine SO2 emissions during hours
in which only gaseous fuel is combusted in the unit. If the unit
sometimes burns only gaseous fuel that is very low sulfur fuel (as
defined in Sec. 72.2 of this chapter) as a primary and/or backup fuel
and at other times combusts higher-sulfur fuels, such as coal or oil,
as primary and/or backup fuel(s), then the owner or operator shall keep
records on-site, suitable for inspection, of the type(s) of fuel(s)
burned during each period of missing SO2 data and the number
of hours that each type of fuel was combusted in the unit during each
missing data period. This recordkeeping requirement does not apply to
an affected unit that burns very low sulfur fuel exclusively, nor does
it apply to a unit that burns such gaseous fuel(s) only during unit
startup.
39. Section 75.56 is amended by adding introductory text prior to
paragraph (a) adding new paragraphs (a)(5)(vii) through (a)(5)(ix) and
removing paragraph (d) to read as follows:
Sec. 75.56 Certification, quality assurance, and quality control
record provisions.
Before April 1, 2000, the owner or operator shall meet the
requirements of
[[Page 28609]]
either this section or Sec. 75.59. On and after April 1, 2000, the
owner or operator shall meet the requirements of Sec. 75.59.
(a) * * *
(5) * * *
(vii) For flow monitors, the equation used to linearize the flow
monitor and the numerical values of the polynomial coefficients or K
factor(s) of that equation.
(viii) The raw data and calculated results for any stratification
tests performed in accordance with sections 6.5.6.1 through 6.5.6.3 in
appendix A to this part.
(ix) For moisture monitoring systems, the coefficient or ``K''
factor or other mathematical algorithm used to adjust the monitoring
system with respect to the reference method.
* * * * *
40. Section 75.57 is added to subpart F to read as follows:
Sec. 75.57 General recordkeeping provisions.
Before April 1, 2000, the owner or operator shall meet the
requirements of either this section or Sec. 75.54. However, the
provisions of this section which support a regulatory option provided
in another section of this part must be followed if that regulatory
option is used prior to April 1, 2000. On or after April 1, 2000, the
owner or operator shall meet the requirements of this section.
(a) Recordkeeping requirements for affected sources. The owner or
operator of any affected source subject to the requirements of this
part shall maintain for each affected unit a file of all measurements,
data, reports, and other information required by this part at the
source in a form suitable for inspection for at least three (3) years
from the date of each record. Unless otherwise provided, throughout
this subpart the phrase ``for each affected unit'' also applies to each
group of affected or nonaffected units utilizing a common stack and
common monitoring systems, pursuant to Secs. 75.16 through 75.18, or
utilizing a common pipe header and common fuel flowmeter, pursuant to
section 2.1.2 of appendix D to this part. The file shall contain the
following information:
(1) The data and information required in paragraphs (b) through (h)
of this section, beginning with the earlier of the date of provisional
certification or the deadline in Sec. 75.4(a), (b), or (c);
(2) The supporting data and information used to calculate values
required in paragraphs (b) through (g) of this section, excluding the
subhourly data points used to compute hourly averages under
Sec. 75.10(d), beginning with the earlier of the date of provisional
certification or the deadline in Sec. 75.4(a), (b), or (c);
(3) The data and information required in Sec. 75.55 or Sec. 75.58
for specific situations, as applicable, beginning with the earlier of
the date of provisional certification or the deadline in Sec. 75.4(a),
(b), or (c);
(4) The certification test data and information required in
Sec. 75.56 or Sec. 75.59 for tests required under Sec. 75.20, beginning
with the date of the first certification test performed, the quality
assurance and quality control data and information required in
Sec. 75.56 or Sec. 75.59 for tests, and the quality assurance/quality
control plan required under Sec. 75.21 and appendix B to this part,
beginning with the date of provisional certification;
(5) The current monitoring plan as specified in Sec. 75.53,
beginning with the initial submission required by Sec. 75.62; and
(6) The quality control plan as described in section 1 of appendix
B to this part, beginning with the date of provisional certification.
(b) Operating parameter record provisions. The owner or operator
shall record for each hour the following information on unit operating
time, heat input rate, and load, separately for each affected unit and
also for each group of units utilizing a common stack and a common
monitoring system or utilizing a common pipe header and common fuel
flowmeter:
(1) Date and hour;
(2) Unit operating time (rounded up to the nearest 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));
(3) Hourly gross unit load (rounded to nearest MWge) (or steam load
in 1000 lb/hr at stated temperature and pressure, rounded to the
nearest 1000 lb/hr, if elected in the monitoring plan);
(4) Operating load range corresponding to hourly gross load of 1 to
10, except for units using a common stack or common pipe header, which
may use up to 20 load ranges for stack or fuel flow, as specified in
the monitoring plan;
(5) Hourly heat input rate (mmBtu/hr, rounded to the nearest
tenth);
(6) Identification code for formula used for heat input, as
provided in Sec. 75.53; and
(7) For CEMS units only, F-factor for heat input calculation and
indication of whether the diluent cap was used for heat input
calculations for the hour.
(c) SO2 emission record provisions. The owner or
operator shall record for each hour the information required by this
paragraph for each affected unit or group of units using a common stack
and common monitoring systems, except as provided under Sec. 75.11(e)
or for a gas-fired or oil-fired unit for which the owner or operator is
using the optional protocol in appendix D to this part or for a low
mass emissions unit for which the owner or operator is using the
optional low mass emissions methodology in Sec. 75.19(c) for estimating
SO2 mass emissions:
(1) For SO2 concentration during unit operation, as
measured and reported from each certified primary monitor, certified
back-up monitor, or other approved method of emissions determination:
(i) Component-system identification code, as provided in
Sec. 75.53;
(ii) Date and hour;
(iii) Hourly average SO2 concentration (ppm, rounded to
the nearest tenth);
(iv) Hourly average SO2 concentration (ppm, rounded to
the nearest tenth), adjusted for bias if bias adjustment factor is
required, as provided in Sec. 75.24(d);
(v) Percent monitor data availability (recorded to the nearest
tenth of a percent), calculated pursuant to Sec. 75.32; and
(vi) Method of determination for hourly average SO2
concentration using Codes 1-55 in Table 4a of this section.
(2) For flow rate during unit operation, as measured and reported
from each certified primary monitor, certified back-up monitor, or
other approved method of emissions determination:
(i) Component-system identification code, as provided in
Sec. 75.53;
(ii) Date and hour;
(iii) Hourly average volumetric flow rate (in scfh, rounded to the
nearest thousand);
(iv) Hourly average volumetric flow rate (in scfh, rounded to the
nearest thousand), adjusted for bias if bias adjustment factor
required, as provided in Sec. 75.24(d);
(v) Percent monitor data availability (recorded to the nearest
tenth of a percent) for the flow monitor, calculated pursuant to
Sec. 75.32; and
(vi) Method of determination for hourly average flow rate using
Codes 1-55 in Table 4a of this section.
(3) For flue gas moisture content during unit operation (where
SO2 concentration is measured on a dry basis), as measured
and reported from each certified primary monitor, certified back-up
monitor, or other approved method of emissions determination:
(i) Component-system identification code, as provided in
Sec. 75.53;
(ii) Date and hour;
[[Page 28610]]
(iii) Hourly average moisture content of flue gas (percent, rounded
to the nearest tenth). If the continuous moisture monitoring system
consists of wet- and dry-basis oxygen analyzers, also record both the
wet- and dry-basis oxygen hourly averages (in percent O2,
rounded to the nearest tenth);
(iv) Percent monitor data availability (recorded to the nearest
tenth of a percent) for the moisture monitoring system, calculated
pursuant to Sec. 75.32; and
(v) Method of determination for hourly average moisture percentage,
using Codes 1-55 in Table 4a of this section.
(4) For SO2 mass emission rate during unit operation, as
measured and reported from the certified primary monitoring system(s),
certified redundant or non-redundant back-up monitoring system(s), or
other approved method(s) of emissions determination:
(i) Date and hour;
(ii) Hourly SO2 mass emission rate (lb/hr, rounded to
the nearest tenth);
(iii) Hourly SO2 mass emission rate (lb/hr, rounded to
the nearest tenth), adjusted for bias if bias adjustment factor
required, as provided in Sec. 75.24(d); and
(iv) Identification code for emissions formula used to derive
hourly SO2 mass emission rate from SO2
concentration and flow and (if applicable) moisture data in paragraphs
(c)(1), (c)(2), and (c)(3) of this section, as provided in Sec. 75.53.
Table 4a.--Codes for Method of Emissions and Flow Determination
------------------------------------------------------------------------
Hourly emissions/flow measurement or
Code estimation method
------------------------------------------------------------------------
1........................ Certified primary emission/flow monitoring
system.
2........................ Certified backup emission/flow monitoring
system.
3........................ Approved alternative monitoring system.
4........................ Reference method:
NSO2: 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........................ Hourly average SO2 concentration, CO2
concentration, O2 concentration, NOX
concentration, moisture percentage, flow
rate, or NOX emission rate using initial
missing data procedures.
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 (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 (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.
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 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....................... Fuel analysis data from appendix G to this
part for CO2 mass emissions. (This code is
optional through 12/31/99, and shall not be
used after 1/1/00.)
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....................... Fuel analysis data from appendix G to this
part for CO2 mass emissions. (This code is
optional through 12/31/99, and shall not be
used after 1/1/00.)
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
monitoring 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).
25....................... Maximum potential NOX emission rate (MER).
(Use only when a NOX concentration full-
scale exceedance occurs and the diluent
monitor is unavailable.)
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.
------------------------------------------------------------------------
(d) NOX emission record provisions. The owner or
operator shall record the applicable information required by this
paragraph for each affected unit for each hour or partial hour during
which the unit operates, except for a gas-fired peaking unit or oil-
fired peaking unit for which the owner or operator is using the
optional protocol in appendix E to this part or a low mass emissions
unit for which the owner or operator is using the optional low mass
emissions excepted methodology in Sec. 75.19(c) for estimating
NOX emission rate. For each NOX emission rate (in
lb/mmBtu) measured by a NOX-diluent monitoring system, or,
if applicable, for each NOX concentration (in ppm) measured
by a
[[Page 28611]]
NOX concentration monitoring system used to calculate
NOX mass emissions under Sec. 75.71(a)(2), record the
following data as measured and reported from the certified primary
monitor, certified back-up monitor, or other approved method of
emissions determination:
(1) Component-system identification code, as provided in Sec. 75.53
(including identification code for the moisture monitoring system, if
applicable);
(2) Date and hour;
(3) Hourly average NOX concentration (ppm, rounded to
the nearest tenth) and hourly average NOX concentration
(ppm, rounded to the nearest tenth) adjusted for bias if bias
adjustment factor required, as provided in Sec. 75.24(d);
(4) Hourly average diluent gas concentration (for NOX-
diluent monitoring systems, only, in units of percent O2 or
percent CO2, rounded to the nearest tenth);
(5) If applicable, the hourly average moisture content of the stack
gas (percent H2O, rounded to the nearest tenth). If the
continuous moisture monitoring system consists of wet- and dry-basis
oxygen analyzers, also record both the hourly wet- and dry-basis oxygen
readings (in percent O2, rounded to the nearest tenth);
(6) Hourly average NOX emission rate (for
NOX-diluent monitoring systems only, in units of lb/mmBtu,
rounded either to the nearest hundredth or thousandth prior to April 1,
2000 and rounded to the nearest thousandth on and after April 1, 2000);
(7) Hourly average NOX emission rate (for
NOX-diluent monitoring systems only, in units of lb/mmBtu,
rounded either to the nearest hundredth or thousandth prior to April 1,
2000 and rounded to the nearest thousandth on and after April 1, 2000),
adjusted for bias if bias adjustment factor is required, as provided in
Sec. 75.24(d). The requirement to report hourly NOX emission
rates to the nearest thousandth shall not affect NOX
compliance determinations under part 76 of this chapter; compliance
with each applicable emission limit under part 76 shall be determined
to the nearest hundredth pound per million Btu;
(8) Percent monitoring system data availability (recorded to the
nearest tenth of a percent), for the NOX-diluent or
NOX concentration monitoring system, and, if applicable, for
the moisture monitoring system, calculated pursuant to Sec. 75.32;
(9) Method of determination for hourly average NOX
emission rate or NOX concentration and (if applicable) for
the hourly average moisture percentage, using Codes 1-55 in Table 4a of
this section; and
(10) Identification codes for emissions formulas used to derive
hourly average NOX emission rate and total NOX
mass emissions, as provided in Sec. 75.53, and (if applicable) the F-
factor used to convert NOX concentrations into emission
rates.
(e) CO2 emission record provisions. Except for a low
mass emissions unit for which the owner or operator is using the
optional low mass emissions excepted methodology in Sec. 75.19(c) for
estimating CO2 mass emissions, the owner or operator shall
record or calculate CO2 emissions for each affected unit
using one of the following methods specified in this section:
(1) If the owner or operator chooses to use a CO2 CEMS
(including an O2 monitor and flow monitor, as specified in
appendix F to this part), then the owner or operator shall record for
each hour or partial hour during which the unit operates the following
information for CO2 mass emissions, as measured and reported
from the certified primary monitor, certified back-up monitor, or other
approved method of emissions determination:
(i) Component-system identification code, as provided in Sec. 75.53
(including identification code for the moisture monitoring system, if
applicable);
(ii) Date and hour;
(iii) Hourly average CO2 concentration (in percent,
rounded to the nearest tenth);
(iv) Hourly average volumetric flow rate (scfh, rounded to the
nearest thousand scfh);
(v) Hourly average moisture content of flue gas (percent, rounded
to the nearest tenth), where CO2 concentration is measured
on a dry basis. If the continuous moisture monitoring system consists
of wet- and dry-basis oxygen analyzers, also record both the hourly
wet- and dry-basis oxygen readings (in percent O2, rounded
to the nearest tenth);
(vi) Hourly average CO2 mass emission rate (tons/hr,
rounded to the nearest tenth);
(vii) Percent monitor data availability for both the CO2
monitoring system and, if applicable, the moisture monitoring system
(recorded to the nearest tenth of a percent), calculated pursuant to
Sec. 75.32;
(viii) Method of determination for hourly average CO2
mass emission rate and hourly average CO2 concentration,
and, if applicable, for the hourly average moisture percentage, using
Codes 1-55 in Table 4a of this section;
(ix) Identification code for emissions formula used to derive
hourly average CO2 mass emission rate, as provided in
Sec. 75.53; and
(x) Indication of whether the diluent cap was used for
CO2 calculation for the hour.
(2) As an alternative to paragraph (e)(1) of this section, the
owner or operator may use the procedures in Sec. 75.13 and in appendix
G to this part, and shall record daily the following information for
CO2 mass emissions:
(i) Date;
(ii) Daily combustion-formed CO2 mass emissions (tons/
day, rounded to the nearest tenth);
(iii) For coal-fired units, flag indicating whether optional
procedure to adjust combustion-formed CO2 mass emissions for
carbon retained in flyash has been used and, if so, the adjustment;
(iv) For a unit with a wet flue gas desulfurization system or other
controls generating CO2, daily sorbent-related
CO2 mass emissions (tons/day, rounded to the nearest tenth);
and
(v) For a unit with a wet flue gas desulfurization system or other
controls generating CO2, total daily CO2 mass
emissions (tons/day, rounded to the nearest tenth) as the sum of
combustion-formed emissions and sorbent-related emissions.
(f) Opacity records. The owner or operator shall record opacity
data as specified by the State or local air pollution control agency.
If the State or local air pollution control agency does not specify
recordkeeping requirements for opacity, then record the information
required by paragraphs (f) (1) through (5) of this section for each
affected unit, except as provided in Secs. 75.14(b), (c), and (d). The
owner or operator shall also keep records of all incidents of opacity
monitor downtime during unit operation, including reason(s) for the
monitor outage(s) and any corrective action(s) taken for opacity, as
measured and reported by the continuous opacity monitoring system:
(1) Component/system identification code;
(2) Date, hour, and minute;
(3) Average opacity of emissions for each six minute averaging
period (in percent opacity);
(4) If the average opacity of emissions exceeds the applicable
standard, then a code indicating such an exceedance has occurred; and
(5) Percent monitor data availability (recorded to the nearest tenth of
a percent), calculated according to the requirements of the procedure
recommended for State Implementation Plans in appendix M to part 51 of
this chapter.
(g) Diluent record provisions. The owner or operator of a unit
using a flow monitor and an O2 diluent monitor to
[[Page 28612]]
determine heat input, in accordance with Equation F-17 or F-18 of
appendix F to this part, or a unit that accounts for heat input using a
flow monitor and a CO2 diluent monitor (which is used only
for heat input determination and is not used as a CO2
pollutant concentration monitor) shall keep the following records for
the O2 or CO2 diluent monitor:
(1) Component-system identification code, as provided in
Sec. 75.53;
(2) Date and hour;
(3) Hourly average diluent gas (O2 or CO2)
concentration (in percent, rounded to the nearest tenth);
(4) Percent monitor data availability for the diluent monitor
(recorded to the nearest tenth of a percent), calculated pursuant to
Sec. 75.32; and
(5) Method of determination code for diluent gas (O2 or
CO2) concentration data using Codes 1-55, in Table 4a of
this section.
(h) Missing data records. The owner or operator shall record the
causes of any missing data periods and the actions taken by the owner
or operator to correct such causes.
41. Section 75.58 is added to subpart F to read as follows:
Sec. 75.58 General recordkeeping provisions for specific situations.
Before April 1, 2000, the owner or operator shall meet the
requirements of either this section or Sec. 75.55. However, the
provisions of this section which support a regulatory option provided
in another section of this part must be followed if that regulatory
option is exercised prior to April 1, 2000. On or after April 1, 2000,
the owner or operator shall meet the requirements of this section.
(a) [Reserved]
(b) Specific parametric data record provisions for calculating
substitute emissions data for units with add-on emission controls. In
accordance with Sec. 75.34, the owner or operator of an affected unit
with add-on emission controls shall either record the applicable
information in paragraph (b)(3) of this section for each hour of
missing SO2 concentration data or NOX emission
rate (in addition to other information), or shall record the
information in paragraph (b)(1) of this section for SO2 or
paragraph (b)(2) of this section for NOX through an
automated data acquisition and handling system, as appropriate to the
type of add-on emission controls:
(1) For units with add-on SO2 emission controls using
the optional parametric monitoring procedures in appendix C to this
part, for each hour of missing SO2 concentration or
volumetric flow data:
(i) The information required in Sec. 75.54(c) or Sec. 75.57(c) for
SO2 concentration and volumetric flow, if either one of
these monitors is still operating;
(ii) Date and hour;
(iii) Number of operating scrubber modules;
(iv) Total feedrate of slurry to each operating scrubber module
(gal/min);
(v) Pressure differential across each operating scrubber module
(inches of water column);
(vi) For a unit with a wet flue gas desulfurization system, an in-
line measure of absorber pH for each operating scrubber module;
(vii) For a unit with a dry flue gas desulfurization system, the
inlet and outlet temperatures across each operating scrubber module;
(viii) For a unit with a wet flue gas desulfurization system, the
percent solids in slurry for each scrubber module;
(ix) For a unit with a dry flue gas desulfurization system, the
slurry feed rate (gal/min) to the atomizer nozzle;
(x) For a unit with SO2 add-on emission controls other
than wet or dry limestone, corresponding parameters approved by the
Administrator;
(xi) Method of determination of SO2 concentration and
volumetric flow using Codes 1-15 in Table 4 of Sec. 75.54 or Codes 1-55
in Table 4a of Sec. 75.57; and
(xii) Inlet and outlet SO2 concentration values,
recorded by an SO2 continuous emission monitoring system,
and the removal efficiency of the add-on emission controls.
(2) For units with add-on NOX emission controls using
the optional parametric monitoring procedures in appendix C to this
part, for each hour of missing NOX emission rate data:
(i) Date and hour;
(ii) Inlet air flow rate (scfh, rounded to the nearest thousand);
(iii) Excess O2 concentration of flue gas at stack
outlet (percent, rounded to the nearest tenth of a percent);
(iv) Carbon monoxide concentration of flue gas at stack outlet
(ppm, rounded to the nearest tenth);
(v) Temperature of flue gas at furnace exit or economizer outlet
duct ( deg.F);
(vi) Other parameters specific to NOX emission controls
(e.g., average hourly reagent feedrate);
(vii) Method of determination of NOX emission rate using
Codes 1-15 in Table 4 of Sec. 75.54 or Codes 1-55 in Table 4a of
Sec. 75.57; and
(viii) Inlet and outlet NOX emission rate values
recorded by a NOX continuous emission monitoring system and
the removal efficiency of the add-on emission controls.
(3) For units with add-on SO2 or NOX emission
controls following the provisions of Sec. 75.34(a)(1) or (a)(2), the
owner or operator shall, for each hour of missing SO2 or
NOX emission data, record:
(i) Parametric data which demonstrate the proper operation of the
add-on emission controls, as described in the quality assurance/quality
control program for the unit. The parametric data shall be maintained
on site and shall be submitted, upon request, to the Administrator, EPA
Regional office, State, or local agency;
(ii) A flag indicating either that the add-on emission controls are
operating properly, as evidenced by all parameters being within the
ranges specified in the quality assurance/quality control program, or
that the add-on emission controls are not operating properly;
(iii) For units substituting a representative SO2
concentration during missing data periods under Sec. 75.34(a)(2), any
available inlet and outlet SO2 concentration values recorded
by an SO2 continuous emission monitoring system; and
(iv) For units substituting a representative NOX
emission rate during missing data periods under Sec. 75.34(a)(2), any
available inlet and outlet NOX emission rate values recorded
by a continuous emission monitoring system.
(c) Specific SO2 emission record provisions for gas-
fired or oil-fired units using optional protocol in appendix D to this
part. In lieu of recording the information in Sec. 75.54(c) or
Sec. 75.57(c), the owner or operator shall record the applicable
information in this paragraph for each affected gas-fired or oil-fired
unit for which the owner or operator is using the optional protocol in
appendix D to this part for estimating SO2 mass emissions:
(1) For each hour when the unit is combusting oil:
(i) Date and hour;
(ii) Hourly average volumetric flow rate of oil, while the unit
combusts oil, with the units in which oil flow is recorded (gal/hr,
scf/hr, m3/hr, or bbl/hr, rounded to the nearest tenth)
(flag value if derived from missing data procedures);
(iii) Sulfur content of oil sample used to determine SO2
mass emission rate (rounded to nearest hundredth for diesel fuel or to
the nearest tenth of a percent for other fuel oil) (flag value if
derived from missing data procedures);
(iv) [Reserved];
(v) Mass flow rate of oil combusted each hour and method of
determination (lb/hr, rounded to the nearest tenth)
[[Page 28613]]
(flag value if derived from missing data procedures);
(vi) SO2 mass emission rate from oil (lb/hr, rounded to
the nearest tenth);
(vii) For units using volumetric oil flowmeters, density of oil
with the units in which oil density is recorded and method of
determination (flag value if derived from missing data procedures);
(viii) Gross calorific value of oil used to determine heat input
and method of determination (Btu/lb) (flag value if derived from
missing data procedures);
(ix) Hourly heat input rate from oil, according to procedures in
appendix D to this part (mmBtu/hr, to the nearest tenth);
(x) Fuel usage time for combustion of oil during the hour (rounded
up to the nearest 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)) (flag to indicate multiple/single fuel types
combusted);
(xi) Monitoring system identification code;
(xii) Operating load range corresponding to gross unit load (01-
20); and
(xiii) Type of oil combusted.
(2) For gas-fired units or oil-fired units using the optional
protocol in appendix D to this part for daily manual oil sampling, when
the unit is combusting oil, the highest sulfur content recorded from
the most recent 30 daily oil samples (rounded to the nearest tenth of a
percent).
(3) For gas-fired units or oil-fired units using the optional
protocol in appendix D to this part, when either an assumed oil sulfur
content or density value is used, or when as-delivered oil sampling is
performed:
(i) Record the measured sulfur content, gross calorific value, and,
if applicable, density from each fuel sample; and
(ii) Record and report the assumed sulfur content, gross calorific
value, and, if applicable, density used to calculate SO2
mass emission rate or heat input rate.
(4) For each hour when the unit is combusting gaseous fuel:
(i) Date and hour.
(ii) Hourly heat input rate from gaseous fuel, according to
procedures in appendix F to this part (mmBtu/hr, rounded to the nearest
tenth).
(iii) Sulfur content or SO2 emission rate, in one of the
following formats, in accordance with the appropriate procedure from
appendix D to this part:
(A) Sulfur content of gas sample and method of determination
(rounded to the nearest 0.1 grains/100 scf) (flag value if derived from
missing data procedures); or
(B) Default SO2 emission rate of 0.0006 lb/mmBtu for
pipeline natural gas, or calculated SO2 emission rate for
natural gas from section 2.3.2.1.1 of appendix D to this part.
(iv) Hourly flow rate of gaseous fuel, while the unit combusts gas
(100 scfh) and source of data code for gas flow rate.
(v) Gross calorific value of gaseous fuel used to determine heat
input rate (Btu/100 scf) (flag value if derived from missing data
procedures).
(vi) SO2 mass emission rate due to the combustion of
gaseous fuels (lb/hr).
(vii) Fuel usage time for combustion of gaseous fuel during the
hour (rounded up to the nearest 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)) (flag to indicate multiple/
single fuel types combusted).
(viii) Monitoring system identification code.
(ix) Operating load range corresponding to gross unit load (01-20).
(x) Type of gas combusted.
(5) For each oil sample or sample of diesel fuel:
(i) Date of sampling;
(ii) Sulfur content (percent, rounded to the nearest hundredth for
diesel fuel and to the nearest tenth for other fuel oil);
(iii) Gross calorific value (Btu/lb); and
(iv) Density or specific gravity, if required to convert volume to
mass.
(6) For each sample of gaseous fuel for sulfur content:
(i) Date of sampling; and
(ii) Sulfur content (grains/100 scf, rounded to the nearest tenth).
(7) For each sample of gaseous fuel for gross calorific value:
(i) Date of sampling; and
(ii) Gross calorific value (Btu/100 scf)
(8) For each oil sample or sample of gaseous fuel:
(i) Type of oil or gas; and
(ii) Type of sulfur sampling (using codes in tables D-4 and D-5 of
appendix D to this part) and value used in calculations, and type of
GCV or density sampling (using codes in tables D-4 and D-5 of appendix
D to this part).
(d) Specific NOX emission record provisions for gas-
fired peaking units or oil-fired peaking units using optional protocol
in appendix E to this part. In lieu of recording the information in
paragraph Sec. 75.54(d) or Sec. 75.57(d), the owner or operator shall
record the applicable information in this paragraph for each affected
gas-fired peaking unit or oil-fired peaking unit for which the owner or
operator is using the optional protocol in appendix E to this part for
estimating NOX emission rate. The owner or operator shall
meet the requirements of this section, except that the requirements
under paragraphs (d)(1)(vii) and (d)(2)(vii) of this section shall
become applicable on the date on which the owner or operator is
required to monitor, record, and report NOX mass emissions
under an applicable State or federal NOX mass emission
reduction program, if the provisions of subpart H of this part are
adopted as requirements under such a program.
(1) For each hour when the unit is combusting oil:
(i) Date and hour;
(ii) Hourly average mass flow rate of oil while the unit combusts
oil with the units in which oil flow is recorded (lb/hr);
(iii) Gross calorific value of oil used to determine heat input
(Btu/lb);
(iv) Hourly average NOX emission rate from combustion of
oil (lb/mmBtu, rounded to the nearest hundredth);
(v) Heat input rate of oil (mmBtu/hr, rounded to the nearest
tenth);
(vi) Fuel usage time for combustion of oil during the hour (rounded
up to the nearest 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);
(vii) NOX mass emissions, calculated in accordance with
section 8.1 of appendix F to this part;
(viii) NOX monitoring system identification code;
(ix) Fuel flow monitoring system identification code; and
(x) Segment identification of the correlation curve.
(2) For each hour when the unit is combusting gaseous fuel:
(i) Date and hour;
(ii) Hourly average fuel flow rate of gaseous fuel, while the unit
combusts gas (100 scfh);
(iii) Gross calorific value of gaseous fuel used to determine heat
input (Btu/100 scf) (flag value if derived from missing data
procedures);
(iv) Hourly average NOX emission rate from combustion of
gaseous fuel (lb/mmBtu, rounded to nearest hundredth);
(v) Heat input rate from gaseous fuel, while the unit combusts gas
(mmBtu/hr, rounded to the nearest tenth);
(vi) Fuel usage time for combustion of gaseous fuel during the hour
(rounded up to the nearest 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);
(vii) NOX mass emissions, calculated in accordance with
section 8.1 of appendix F to this part;
(viii) NOX monitoring system identification code;
[[Page 28614]]
(ix) Fuel flow monitoring system identification code; and
(x) Segment identification of the correlation curve.
(3) For each hour when the unit combusts multiple fuels:
(i) Date and hour;
(ii) Hourly average heat input rate from all fuels (mmBtu/hr,
rounded to the nearest tenth); and
(iii) Hourly average NOX emission rate for the unit for
all fuels (lb/mmBtu, rounded to the nearest hundredth).
(4) For each hour when the unit combusts any fuel(s):
(i) For stationary gas turbines and diesel or dual-fuel
reciprocating engines, hourly averages of operating parameters under
section 2.3 of appendix E to this part (flag if value is outside of
manufacturer's recommended range); and
(ii) For boilers, hourly average boiler O2 reading
(percent, rounded to the nearest tenth) (flag if value exceeds by more
than 2 percentage points the O2 level recorded at the same
heat input during the previous NOX emission rate test).
(5) For each fuel sample:
(i) Date of sampling;
(ii) Gross calorific value (Btu/lb for oil, Btu/100 scf for gaseous
fuel); and
(iii) Density or specific gravity, if required to convert volume to
mass.
(6) Flag to indicate multiple or single fuels combusted.
(e) Specific SO2 emission record provisions during the
combustion of gaseous fuel. (1) If SO2 emissions are
determined in accordance with the provisions in Sec. 75.11(e)(2) during
hours in which only gaseous fuel is combusted in a unit with an
SO2 CEMS, the owner or operator shall record the information
in paragraph (c)(3) of this section in lieu of the information in
Secs. 75.54(c)(1) and (c)(3) or Secs. 75.57(c)(1), (c)(3), and (c)(4),
for those hours.
(2) The provisions of this paragraph apply to a unit which, in
accordance with the provisions of Sec. 75.11(e)(3), uses an
SO2 CEMS to determine SO2 emissions during hours
in which only gaseous fuel is combusted in the unit. If the unit
sometimes burns only gaseous fuel that is very low sulfur fuel (as
defined in Sec. 72.2 of this chapter) as a primary and/or backup fuel
and at other times combusts higher sulfur fuels, such as coal or oil,
as primary and/or backup fuel(s), then the owner or operator shall keep
records on-site, in a form suitable for inspection, of the type(s) of
fuel(s) burned during each period of missing SO2 data and
the number of hours that each type of fuel was combusted in the unit
during each missing data period. This recordkeeping requirement does
not apply to an affected unit that burns very low sulfur fuel
exclusively, nor does it apply to a unit that burns such gaseous
fuel(s) only during unit startup.
(f) Specific SO2, NOX, and CO2
record provisions for gas-fired or oil-fired units using the optional
low mass emissions excepted methodology in Sec. 75.19. In lieu of
recording the information in Secs. 75.54(b) through (e) or
Secs. 75.57(b) through (e), the owner or operator shall record the
following information for each affected low mass emissions unit for
which the owner or operator is using the optional low mass emissions
excepted methodology in Sec. 75.19(c):
(1) All low mass emission units shall report for each hour:
(i) Date and hour;
(ii) Unit operating time (units using the long term fuel flow
methodology report operating time to be 1);
(iii) Fuel type (pipeline natural gas, natural gas, residual oil,
or diesel fuel) (note: if more than one type of fuel is combusted in
the hour, indicate the fuel type which results in the highest emission
factors for NOX);
(iv) Average hourly NOX emission rate (lb/mmBtu, rounded
to the nearest thousandth);
(v) Hourly NOX mass emissions (lbs, rounded to the
nearest tenth);
(vi) Hourly SO2 mass emissions (lbs, rounded to the
nearest tenth);
(vii) Hourly CO2 mass emissions (tons, rounded to the
nearest tenth);
(viii) Hourly calculated unit heat input in mmBtu;
(ix) Hourly unit output in gross load or steam load;
(x) The method of determining hourly heat input: unit maximum rated
heat input, unit long term fuel flow or group long term fuel flow;
(xi) The method of determining NOX emission rate used
for the hour: default based on fuel combusted, unit specific default
based on testing or historical data, group default based on
representative testing of identical units, unit specific based on
testing of a unit with NOX controls operating, or missing
data value; and
(xii) Control status of the unit.
(2) Low mass emission units using the optional long term fuel flow
methodology to determine unit heat input shall report for each quarter:
(i) Type of fuel;
(ii) Beginning date and hour of long term fuel flow measurement
period;
(iii) End date and hour of long term fuel flow period;
(iv) Quantity of fuel measured;
(v) Units of measure;
(vi) Fuel GCV value used to calculate heat input;
(vii) Units of GCV;
(viii) Method of determining fuel GCV used;
(ix) Method of determining fuel flow over period;
(x) Component-system identification code;
(xi) Quarter and year;
(xii) Total heat input (mmBtu); and
(xiii) Operating hours in period.
42. Section 75.59 is added to subpart F to read as follows:
Sec. 75.59 Certification, quality assurance, and quality control
record provisions.
Before April 1, 2000, the owner or operator shall meet the
requirements of this section or Sec. 75.56. However, the provisions of
this section which support a regulatory option provided in another
section of this part must be followed if that regulatory option is
exercised prior to April 1, 2000. On or after April 1, 2000, the owner
or operator shall meet the requirements of this section.
(a) Continuous emission or opacity monitoring systems. The owner or
operator shall record the applicable information in this section for
each certified monitor or certified monitoring system (including
certified backup monitors) measuring and recording emissions or flow
from an affected unit.
(1) For each SO2 or NOX pollutant
concentration monitor, flow monitor, CO2 pollutant
concentration monitor (including O2 monitors used to
determine CO2 emissions), or diluent gas monitor (including
wet- and dry-basis O2 monitors used to determine percent
moisture), the owner or operator shall record the following for all
daily and 7-day calibration error tests and all off-line calibration
demonstrations, including any follow-up tests after corrective action:
(i) Component-system identification code;
(ii) Instrument span and span scale;
(iii) Date and hour;
(iv) Reference value (i.e., calibration gas concentration or
reference signal value, in ppm or other appropriate units);
(v) Observed value (monitor response during calibration, in ppm or
other appropriate units);
(vi) Percent calibration error (rounded to the nearest tenth of a
percent) (flag if using alternative performance specification for low
emitters or differential pressure flow monitors);
(vii) Calibration gas level;
(viii) Test number and reason for test;
(ix) For 7-day calibration tests for certification or
recertification, a certification from the cylinder gas vendor or CEMS
vendor that calibration gas, as defined in Sec. 72.2 of this chapter
and appendix A to this part, was used to conduct calibration error
testing;
[[Page 28615]]
(x) Description of any adjustments, corrective actions, or
maintenance prior to a passed test or following a failed test; and
(xi) For the qualifying test for off-line calibration, the owner or
operator shall indicate whether the unit is off-line or on-line.
(2) For each flow monitor, the owner or operator shall record the
following for all daily interference checks, including any follow-up
tests after corrective action.
(i) Component-system identification code;
(ii) Date and hour;
(iii) Code indicating whether monitor passes or fails the
interference check; and
(iv) Description of any adjustments, corrective actions, or
maintenance prior to a passed test or following a failed test.
(3) For each SO2 or NOX pollutant
concentration monitor, CO2 pollutant concentration monitor
(including O2 monitors used to determine CO2
emissions), or diluent gas monitor (including wet- and dry-basis
O2 monitors used to determine percent moisture), the owner
or operator shall record the following for the initial and all
subsequent linearity check(s), including any follow-up tests after
corrective action.
(i) Component-system identification code;
(ii) Instrument span and span scale;
(iii) Calibration gas level;
(iv) Date and time (hour and minute) of each gas injection at each
calibration gas level;
(v) Reference value (i.e., reference gas concentration for each gas
injection at each calibration gas level, in ppm or other appropriate
units);
(vi) Observed value (monitor response to each reference gas
injection at each calibration gas level, in ppm or other appropriate
units);
(vii) Mean of reference values and mean of measured values at each
calibration gas level;
(viii) Linearity error at each of the reference gas concentrations
(rounded to nearest tenth of a percent) (flag if using alternative
performance specification);
(ix) Test number and reason for test (flag if aborted test); and
(x) Description of any adjustments, corrective action, or
maintenance prior to a passed test or following a failed test.
(4) For each differential pressure type flow monitor, the owner or
operator shall record items in paragraphs (a)(4) (i) through (v) of
this section, for all quarterly leak checks, including any follow-up
tests after corrective action. For each flow monitor, the owner or
operator shall record items in paragraphs (a)(4) (vi) and (vii) for all
flow-to-load ratio and gross heat rate tests:
(i) Component-system identification code.
(ii) Date and hour.
(iii) Reason for test.
(iv) Code indicating whether monitor passes or fails the quarterly
leak check.
(v) Description of any adjustments, corrective actions, or
maintenance prior to a passed test or following a failed test.
(vi) Test data from the flow-to-load ratio or gross heat rate (GHR)
evaluation, including:
(A) Monitoring system identification code;
(B) Calendar year and quarter;
(C) Indication of whether the test is a flow-to-load ratio or gross
heat rate evaluation;
(D) Indication of whether bias adjusted flow rates were used;
(E) Average absolute percent difference between reference ratio (or
GHR) and hourly ratios (or GHR values);
(F) Test result;
(G) Number of hours used in final quarterly average;
(H) Number of hours exempted for use of a different fuel type;
(I) Number of hours exempted for load ramping up or down;
(J) Number of hours exempted for scrubber bypass;
(K) Number of hours exempted for hours preceding a normal-load flow
RATA;
(L) Number of hours exempted for hours preceding a successful
diagnostic test, following a documented monitor repair or major
component replacement; and
(M) Number of hours excluded for flue gases discharging
simultaneously thorough a main stack and a bypass stack.
(vii) Reference data for the flow-to-load ratio or gross heat rate
evaluation, including (as applicable):
(A) Reference flow RATA end date and time;
(B) Test number of the reference RATA;
(C) Reference RATA load and load level;
(D) Average reference method flow rate during reference flow RATA;
(E) Reference flow/load ratio;
(F) Average reference method diluent gas concentration during flow
RATA and diluent gas units of measure;
(G) Fuel specific Fd -or Fc-factor during
flow RATA and F-factor units of measure;
(H) Reference gross heat rate value;
(I) Monitoring system identification code;
(J) Average hourly heat input rate during RATA;
(K) Average gross unit load; and
(L) Operating load level.
(5) For each SO2 pollutant concentration monitor, flow
monitor, each CO2 pollutant concentration monitor (including
any O2 concentration monitor used to determine
CO2 mass emissions or heat input), each NOX-
diluent continuous emission monitoring system, each SO2-
diluent continuous emission monitoring system, each NOX
concentration monitoring system, each diluent gas (O2 or
CO2) monitor used to determine heat input, each moisture
monitoring system, and each approved alternative monitoring system, the
owner or operator shall record the following information for the
initial and all subsequent relative accuracy test audits:
(i) Reference method(s) used.
(ii) Individual test run data from the relative accuracy test audit
for the SO2 concentration monitor, flow monitor,
CO2 pollutant concentration monitor, NOX-diluent
continuous emission monitoring system, SO2-diluent
continuous emission monitoring system, diluent gas (O2 or
CO2) monitor used to determine heat input, NOX
concentration monitoring system, moisture monitoring system, or
approved alternative monitoring system, including:
(A) Date, hour, and minute of beginning of test run;
(B) Date, hour, and minute of end of test run;
(C) Monitoring system identification code;
(D) Test number and reason for test;
(E) Operating load level (low, mid, high, or normal, as
appropriate) and number of load levels comprising test;
(F) Normal load indicator for flow RATAs (except for peaking
units);
(G) Units of measure;
(H) Run number;
(I) Run value from CEMS being tested, in the appropriate units of
measure;
(J) Run value from reference method, in the appropriate units of
measure;
(K) Flag value (0, 1, or 9, as appropriate) indicating whether run
has been used in calculating relative accuracy and bias values or
whether the test was aborted prior to completion;
(L) Average gross unit load, expressed as a total gross unit load,
rounded to the nearest MWe, or as steam load, rounded to the nearest
thousand lb/hr); and
(M) Flag to indicate whether an alternative performance
specification has been used.
(iii) Calculations and tabulated results, as follows:
(A) Arithmetic mean of the monitoring system measurement values, of
the reference method values, and of
[[Page 28616]]
their differences, as specified in Equation A-7 in appendix A to this
part;
(B) Standard deviation, as specified in Equation A-8 in appendix A
to this part;
(C) Confidence coefficient, as specified in Equation A-9 in
appendix A to this part;
(D) Statistical ``t'' value used in calculations;
(E) Relative accuracy test results, as specified in Equation A-10
in appendix A to this part. For multi-level flow monitor tests the
relative accuracy test results shall be recorded at each load level
tested. Each load level shall be expressed as a total gross unit load,
rounded to the nearest MWe, or as steam load, rounded to the nearest
thousand lb/hr;
(F) Bias test results as specified in section 7.6.4 in appendix A
to this part; and
(G) Bias adjustment factor from Equation A-12 in appendix A to this
part for any monitoring system that failed the bias test (except as
otherwise provided in section 7.6.5 of appendix A to this part) and
1.000 for any monitoring system that passed the bias test.
(iv) Description of any adjustment, corrective action, or
maintenance prior to a passed test or following a failed or aborted
test.
(v) F-factor value(s) used to convert NOX pollutant
concentration and diluent gas (O2 or CO2)
concentration measurements into NOX emission rates (in lb/
mmBtu), heat input or CO2 emissions.
(vi) For flow monitors, the equation used to linearize the flow
monitor and the numerical values of the polynomial coefficients or K
factor(s) of that equation.
(vii) For moisture monitoring systems, the coefficient or ``K''
factor or other mathematical algorithm used to adjust the monitoring
system with respect to the reference method.
(6) For each SO2, NOX, or CO2
pollutant concentration monitor, NOX-diluent continuous
emission monitoring system, SO2-diluent continuous emission
monitoring system, NOX concentration monitoring system, or
diluent gas (O2 or CO2) monitor used to determine
heat input, the owner or operator shall record the following
information for the cycle time test:
(i) Component-system identification code;
(ii) Date;
(iii) Start and end times;
(iv) Upscale and downscale cycle times for each component;
(v) Stable start monitor value;
(vi) Stable end monitor value;
(vii) Reference value of calibration gas(es);
(viii) Calibration gas level;
(ix) Cycle time result for the entire system;
(x) Reason for test; and
(xi) Test number.
(7) In addition to the information in paragraph (a)(5) of this
section, the owner or operator shall record, for each relative accuracy
test audit, supporting information sufficient to substantiate
compliance with all applicable sections and appendices in this part.
Unless otherwise specified in this part or in an applicable test
method, the information in paragraphs (a)(7)(i) through (a)(7)(vi) may
be recorded either in hard copy format, electronic format or a
combination of the two, and the owner or operator shall maintain this
information in a format suitable for inspection and audit purposes.
This RATA supporting information shall include, but shall not be
limited to, the following data elements:
(i) For each RATA using Reference Method 2 (or its allowable
alternatives) in appendix A to part 60 of this chapter to determine
volumetric flow rate:
(A) Information indicating whether or not the location meets
requirements of Method 1 in appendix A to part 60 of this chapter; and
(B) Information indicating whether or not the equipment passed the
required leak checks.
(ii) For each run of each RATA using Reference Method 2 (or its
allowable alternatives in appendix A to part 60 of this chapter) to
determine volumetric flow rate, record the following data elements (as
applicable to the measurement method used):
(A) Operating load level (low, mid, high, or normal, as
appropriate);
(B) Number of reference method traverse points;
(C) Average stack gas temperature ( deg.F);
(D) Barometric pressure at test port (inches of mercury);
(E) Stack static pressure (inches of H2O);
(F) Absolute stack gas pressure (inches of mercury);
(G) Percent CO2 and O2 in the stack gas, dry
basis;
(H) CO2 and O2 reference method used;
(I) Moisture content of stack gas (percent H2O);
(J) Molecular weight of stack gas, dry basis (lb/lb-mole);
(K) Molecular weight of stack gas, wet basis (lb/lb-mole);
(L) Stack diameter (or equivalent diameter) at the test port (ft);
(M) Average square root of velocity head of stack gas (inches of
H2O) for the run;
(N) Stack or duct cross-sectional area at test port
(ft2);
(O) Average velocity (ft/sec);
(P) Total volumetric flow rate (scfh, wet basis);
(Q) Flow rate reference method used;
(R) Average velocity, adjusted for wall effects;
(S) Calculated (site-specific) wall effects adjustment factor
determined during the run, and, if different, the wall effects
adjustment factor used in the calculations; and
(T) Default wall effects adjustment factor used.
(iii) For each traverse point of each run of each RATA using
Reference Method 2 (or its allowable alternatives in appendix A to part
60 of this chapter) to determine volumetric flow rate, record the
following data elements (as applicable to the measurement method used):
(A) Reference method probe type;
(B) Pressure measurement device type;
(C) Traverse point ID;
(D) Probe or pitot tube calibration coefficient;
(E) Date of latest probe or pitot tube calibration;
(F) Velocity differential pressure at traverse point (inches of
H2O);
(G) TS, stack temperature at the traverse point
( deg.F);
(H) Composite (wall effects) traverse point identifier;
(I) Number of points included in composite traverse point;
(J) Yaw angle of flow at traverse point (degrees);
(K) Pitch angle of flow at traverse point (degrees);
(L) Calculated velocity at traverse point both accounting and not
accounting for wall effects (ft/sec); and
(M) Probe identification number.
(iv) For each RATA using Method 6C, 7E, or 3A in appendix A to part
60 of this chapter to determine SO2, NOX,
CO2, or O2 concentration:
(A) Pollutant or diluent gas being measured;
(B) Span of reference method analyzer;
(C) Type of reference method system (e.g., extractive or dilution
type);
(D) Reference method dilution factor (dilution type systems, only);
(E) Reference gas concentrations (zero, mid, and high gas levels)
used for the 3-point pre-test analyzer calibration error test (or, for
dilution type reference method systems, for the 3-point pre-test system
calibration error test) and for any subsequent recalibrations;
[[Page 28617]]
(F) Analyzer responses to the zero-, mid-, and high-level
calibration gases during the 3-point pre-test analyzer (or system)
calibration error test and during any subsequent recalibration(s);
(G) Analyzer calibration error at each gas level (zero, mid, and
high) for the 3-point pre-test analyzer (or system) calibration error
test and for any subsequent recalibration(s) (percent of span value);
(H) Upscale gas concentration (mid or high gas level) used for each
pre-run or post-run system bias check or (for dilution type reference
method systems) for each pre-run or post-run system calibration error
check;
(I) Analyzer response to the calibration gas for each pre-run or
post-run system bias (or system calibration error) check;
(J) The arithmetic average of the analyzer responses to the zero-
level gas, for each pair of pre- and post-run system bias (or system
calibration error) checks;
(K) The arithmetic average of the analyzer responses to the upscale
calibration gas, for each pair of pre- and post-run system bias (or
system calibration error) checks;
(L) The results of each pre-run and each post-run system bias (or
system calibration error) check using the zero-level gas (percentage of
span value);
(M) The results of each pre-run and each post-run system bias (or
system calibration error) check using the upscale calibration gas
(percentage of span value);
(N) Calibration drift and zero drift of analyzer during each RATA
run (percentage of span value);
(O) Moisture basis of the reference method analysis;
(P) Moisture content of stack gas, in percent, during each test run
(if needed to convert to moisture basis of CEMS being tested);
(Q) Unadjusted (raw) average pollutant or diluent gas concentration
for each run;
(R) Average pollutant or diluent gas concentration for each run,
corrected for calibration bias (or calibration error) and, if
applicable, corrected for moisture;
(S) The F-factor used to convert reference method data to units of
lb/mmBtu (if applicable);
(T) Date(s) of the latest analyzer interference test(s);
(U) Results of the latest analyzer interference test(s);
(V) Date of the latest NO2 to NO conversion test (Method
7E only);
(W) Results of the latest NO2 to NO conversion test
(Method 7E only); and
(X) For each calibration gas cylinder used during each RATA, record
the cylinder gas vendor, cylinder number, expiration date, pollutant(s)
in the cylinder, and certified gas concentration(s).
(v) For each test run of each moisture determination using Method 4
in appendix A to part 60 of this chapter (or its allowable
alternatives), whether the determination is made to support a gas RATA,
to support a flow RATA, or to quality assure the data from a continuous
moisture monitoring system, record the following data elements (as
applicable to the moisture measurement method used):
(A) Test number;
(B) Run number;
(C) The beginning date, hour, and minute of the run;
(D) The ending date, hour, and minute of the run;
(E) Unit operating level (low, mid, high, or normal, as
appropriate);
(F) Moisture measurement method;
(G) Volume of H2O collected in the impingers (ml);
(H) Mass of H2O collected in the silica gel (g);
(I) Dry gas meter calibration factor;
(J) Average dry gas meter temperature ( deg.F);
(K) Barometric pressure (inches of mercury);
(L) Differential pressure across the orifice meter (inches of
H2O);
(M) Initial and final dry gas meter readings (ft3);
(N) Total sample gas volume, corrected to standard conditions
(dscf); and
(O) Percentage of moisture in the stack gas (percent
H2O).
(vi) The raw data and calculated results for any stratification
tests performed in accordance with sections 6.5.6.1 through 6.5.6.3 of
appendix A to this part.
(8) For each certified continuous emission monitoring system,
continuous opacity monitoring system, or alternative monitoring system,
the date and description of each event which requires recertification
of the system and the date and type of each test performed to recertify
the system in accordance with Sec. 75.20(b).
(9) When hardcopy relative accuracy test reports, certification
reports, recertification reports, or semiannual or annual reports for
gas or flow rate CEMS are required or requested under Sec. 75.60(b)(6)
or Sec. 75.63, the reports shall include, at a minimum, the following
elements (as applicable to the type(s) of test(s) performed):
(i) Summarized test results.
(ii) DAHS printouts of the CEMS data generated during the
calibration error, linearity, cycle time, and relative accuracy tests.
(iii) For pollutant concentration monitor or diluent monitor
relative accuracy tests at normal operating load:
(A) The raw reference method data from each run, i.e., the data
under paragraph (a)(7)(iv)(Q) of this section (usually in the form of a
computerized printout, showing a series of one-minute readings and the
run average);
(B) The raw data and results for all required pre-test, post-test,
pre-run and post-run quality assurance checks (i.e., calibration gas
injections) of the reference method analyzers, i.e., the data under
paragraphs (a)(7)(iv)(E) through (a)(7)(iv)(N) of this section;
(C) The raw data and results for any moisture measurements made
during the relative accuracy testing, i.e., the data under paragraphs
(a)(7)(v)(A) through (a)(7)(v)(O) of this section; and
(D) Tabulated, final, corrected reference method run data (i.e.,
the actual values used in the relative accuracy calculations), along
with the equations used to convert the raw data to the final values and
example calculations to demonstrate how the test data were reduced.
(iv) For relative accuracy tests for flow monitors:
(A) The raw flow rate reference method data, from Reference Method
2 (or its allowable alternatives) under appendix A to part 60 of this
chapter, including auxiliary moisture data (often in the form of
handwritten data sheets), i.e., the data under paragraphs (a)(7)(ii)(A)
through (a)(7)(ii)(T), paragraphs (a)(7)(iii)(A) through
(a)(7)(iii)(M), and, if applicable, paragraphs (a)(7)(v)(A) through
(a)(7)(v)(O) of this section; and
(B) The tabulated, final volumetric flow rate values used in the
relative accuracy calculations (determined from the flow rate reference
method data and other necessary measurements, such as moisture, stack
temperature and pressure), along with the equations used to convert the
raw data to the final values and example calculations to demonstrate
how the test data were reduced.
(v) Calibration gas certificates for the gases used in the
linearity, calibration error, and cycle time tests and for the
calibration gases used to quality assure the gas monitor reference
method data during the relative accuracy test audit.
(vi) Laboratory calibrations of the source sampling equipment.
(vii) A copy of the test protocol used for the CEMS certifications
or recertifications, including narrative that explains any testing
abnormalities, problematic sampling, and analytical conditions that
required a change to the test protocol, and/or solutions to
[[Page 28618]]
technical problems encountered during the testing program.
(viii) Diagrams illustrating test locations and sample point
locations (to verify that locations are consistent with information in
the monitoring plan). Include a discussion of any special traversing or
measurement scheme. The discussion shall also confirm that sample
points satisfy applicable acceptance criteria.
(ix) Names of key personnel involved in the test program, including
test team members, plant contacts, agency representatives and test
observers on site.
(10) Whenever reference methods are used as backup monitoring
systems pursuant to Sec. 75.20(d)(3), the owner or operator shall
record the following information:
(i) For each test run using Reference Method 2 (or its allowable
alternatives in appendix A to part 60 of this chapter) to determine
volumetric flow rate, record the following data elements (as applicable
to the measurement method used):
(A) Unit or stack identification number;
(B) Reference method system and component identification numbers;
(C) Run date and hour;
(D) The data in paragraph (a)(7)(ii) of this section, except for
paragraphs (a)(7)(ii)(A), (F), (H), (L) and (Q) through (T); and
(E) The data in paragraph (a)(7)(iii)(A), except on a run basis.
(ii) For each reference method test run using Method 6C, 7E, or 3A
in appendix A to part 60 of this chapter to determine SO2,
NOX, CO2, or O2 concentration:
(A) Unit or stack identification number;
(B) The reference method system and component identification
numbers;
(C) Run number;
(D) Run start date and hour;
(E) Run end date and hour;
(F) The data in paragraphs (a)(7)(iv)(B) through (I) and (L)
through (O); and (G) Stack gas density adjustment factor (if
applicable).
(iii) For each hour of each reference method test run using Method
6C, 7E, or 3A in appendix A to part 60 of this chapter to determine
SO2, NOX, CO2, or O2
concentration:
(A) Unit or stack identification number;
(B) The reference method system and component identification
numbers;
(C) Run number;
(D) Run date and hour;
(E) Pollutant or diluent gas being measured;
(F) Unadjusted (raw) average pollutant or diluent gas concentration
for the hour; and
(G) Average pollutant or diluent gas concentration for the hour,
adjusted as appropriate for moisture, calibration bias (or calibration
error) and stack gas density.
(11) For each other quality-assurance test or other quality
assurance activity, the owner or operator shall record the following
(as applicable):
(i) Component/system identification code;
(ii) Parameter;
(iii) Test or activity completion date and hour;
(iv) Test or activity description;
(v) Test result;
(vi) Reason for test; and
(vii) Test code.
(12) For each request for a quality assurance test extension or
exemption, for any loss of exempt status, and for each single-load flow
RATA claim pursuant to section 2.3.1.3(c)(3) of appendix B to this
part, the owner or operator shall record the following (as applicable):
(i) For a RATA deadline extension or exemption request:
(A) Monitoring system identification code;
(B) Date of last RATA;
(C) RATA expiration date without extension;
(D) RATA expiration date with extension;
(E) Type of RATA extension of exemption claimed or lost;
(F) Year to date hours of usage of fuel other than very low sulfur
fuel;
(G) Year to date hours of non-redundant back-up CEMS usage at the
unit/stack; and
(H) Quarter and year.
(ii) For a linearity test or flow-to-load ratio test quarterly
exemption:
(A) Component-system identification code;
(B) Type of test;
(C) Basis for exemption;
(D) Quarter and year; and
(E) Span scale.
(iii) For a quality assurance test extension claim based on a grace
period:
(A) Component-system identification code;
(B) Type of test;
(C) Beginning of grace period;
(D) Date and hour of completion of required quality assurance test;
(E) Number of unit or stack operating hours from the beginning of
the grace period to the completion of the quality assurance test or the
maximum allowable grace period; and
(F) Date and hour of end of grace period.
(iv) For a fuel flowmeter accuracy test extension:
(A) Component-system identification code;
(B) Date of last accuracy test;
(C) Accuracy test expiration date without extension;
(D) Accuracy test expiration date with extension;
(E) Type of extension; and
(F) Quarter and year.
(v) For a single-load flow RATA claim:
(A) Monitoring system identification code;
(B) Ending date of last annual flow RATA;
(C) The relative frequency (percentage) of unit or stack operation
at each load level (low, mid, and high) since the previous annual flow
RATA, to the nearest 0.1 percent.
(D) End date of the historical load data collection period; and
(E) Indication of the load level (low, mid or high) claimed for the
single-load flow RATA.
(13) An indication that data have been excluded from a periodic
span and range evaluation of an SO2 or NOX
monitor under section 2.1.1.5 or 2.1.2.5 of appendix A to this part and
the reason(s) for excluding the data. For purposes of reporting under
Sec. 75.64(a)(2), this information shall be reported with the quarterly
report as descriptive text consistent with Sec. 75.64(g).
(b) Excepted monitoring systems for gas-fired and oil-fired units.
The owner or operator shall record the applicable information in this
section for each excepted monitoring system following the requirements
of appendix D to this part or appendix E to this part for determining
and recording emissions from an affected unit.
(1) For certification and quality assurance testing of fuel
flowmeters tested against a reference fuel flow rate (i.e., flow rate
from another fuel flowmeter under section 2.1.5.2 of appendix D to this
part or flow rate from a procedure according to a standard incorporated
by reference under section 2.1.5.1 of appendix D to this part):
(i) Unit or common pipe header identification code;
(ii) Component and system identification codes of the fuel
flowmeter being tested;
(iii) Date and hour of test completion, for a test performed in-
line at the unit;
(iv) Date and hour of flowmeter reinstallation, for laboratory
tests;
(v) Test number;
(vi) Upper range value of the fuel flowmeter;
(vii) Flowmeter measurements during accuracy test (and mean of
values), including units of measure;
(viii) Reference flow rates during accuracy test (and mean of
values), including units of measure;
[[Page 28619]]
(ix) Level of fuel flowrate test during runs (low, mid or high);
(x) Average flowmeter accuracy for low and high fuel flowrates and
highest flowmeter accuracy of any level designated as mid, expressed as
a percent of upper range value;
(xi) Indicator of whether test method was a lab comparison to
reference meter or an in-line comparison against a master meter;
(xii) Test result (aborted, pass, or fail); and
(xiii) Description of fuel flowmeter calibration specification or
procedure (in the certification application, or periodically if a
different method is used for annual quality assurance testing).
(2) For each transmitter or transducer accuracy test for an
orifice-, nozzle-, or venturi-type flowmeter used under section 2.1.6
of appendix D to this part:
(i) Component and system identification codes of the fuel flowmeter
being tested;
(ii) Completion date and hour of test;
(iii) For each transmitter or transducer: transmitter or transducer
type (differential pressure, static pressure, or temperature); the
full-scale value of the transmitter or transducer, transmitter input
(pre-calibration) prior to accuracy test, including units of measure;
and expected transmitter output during accuracy test (reference value
from NIST-traceable equipment), including units of measure;
(iv) For each transmitter or transducer tested: output during
accuracy test, including units of measure; transmitter or transducer
accuracy as a percent of the full-scale value; and transmitter output
level as a percent of the full-scale value;
(v) Average flowmeter accuracy at low and high fuel flowrates and
highest flowmeter accuracy of any level designated as mid fuel
flowrate, expressed as a percent of upper range value;
(vi) Test result (pass, fail, or aborted);
(vii) Test number; and
(viii) Accuracy determination methodology.
(3) For each visual inspection of the primary element or
transmitter or transducer accuracy test for an
orifice-, nozzle-, or venturi-type flowmeter under sections 2.1.6.1
through 2.1.6.4 of appendix D to this part:
(i) Date of inspection/test;
(ii) Hour of completion of inspection/test;
(iii) Component and system identification codes of the fuel
flowmeter being inspected/tested; and
(iv) Results of inspection/test (pass or fail).
(4) For fuel flowmeters that are tested using the optional fuel
flow-to-load ratio procedures of section 2.1.7 of appendix D to this
part:
(i) Test data for the fuel flowmeter flow-to-load ratio or gross
heat rate check, including:
(A) Component/system identification code;
(B) Calendar year and quarter;
(C) Indication of whether the test is for fuel flow-to-load ratio
or gross heat rate;
(D) Quarterly average absolute percent difference between baseline
for fuel flow-to-load ratio (or baseline gross heat rate and hourly
quarterly fuel flow-to-load ratios (or gross heat rate value);
(E) Test result;
(F) Number of hours used in the analysis;
(G) Number of hours excluded due to co-firing;
(H) Number of hours excluded due to ramping; and
(I) Number of hours excluded in lower 25.0 percent range of
operation.
(ii) Reference data for the fuel flowmeter flow-to-load ratio or
gross heat rate evaluation, including:
(A) Completion date and hour of most recent primary element
inspection;
(B) Completion date and hour of most recent flowmeter or
transmitter accuracy test;
(C) Beginning date and hour of baseline period;
(D) Completion date and hour of baseline period;
(E) Average fuel flow rate, in 100 scfh for gas and lb/hr for oil;
(F) Average load, in megawatts or 1000 lb/hr of steam;
(G) Baseline fuel flow-to-load ratio, in the appropriate units of
measure (if using fuel flow-to-load ratio);
(H) Baseline gross heat rate if using gross heat rate, in the
appropriate units of measure (if using gross heat rate check);
(I) Number of hours excluded from baseline data due to ramping;
(J) Number of hours excluded from baseline data in lower 25.0
percent of range of operation;
(K) Average hourly heat input rate; and
(L) Flag indicating baseline data collection is in progress and
that fewer than four calendar quarters have elapsed since the quarter
of the last flowmeter QA test.
(5) For gas-fired peaking units or oil-fired peaking units using
the optional procedures of appendix E to this part, for each initial
performance, periodic, or quality assurance/quality control-related
test:
(i) For each run of emission data, record the following data:
(A) Unit or common pipe identification code;
(B) Monitoring system identification code for appendix E system;
(C) Run start date and time;
(D) Run end date and time;
(E) Total heat input during the run (mmBtu);
(F) NOX emission rate (lb/mmBtu) from reference method;
(G) Response time of the O2 and NOX reference
method analyzers;
(H) Type of fuel(s) combusted during the run;
(I) Heat input rate (mmBtu/hr) during the run;
(J) Test number;
(K) Run number;
(L) Operating level during the run;
(M) NOX concentration recorded by the reference method
during the run;
(N) Diluent concentration recorded by the reference method during
the run; and
(O) Moisture measurement for the run (if applicable).
(ii) For each run during which oil or mixed fuels are combusted
record the following data:
(A) Unit or common pipe identification code;
(B) Monitoring system identification code for oil monitoring
system;
(C) Run start date and time;
(D) Run end date and time;
(E) Mass flow or volumetric flow of oil, in the units of measure
for the type of fuel flowmeter;
(F) Gross calorific value of oil in the appropriate units of
measure;
(G) Density of fuel oil in the appropriate units of measure (if
density is used to convert oil volume to mass);
(H) Hourly heat input (mmBtu) during run from oil;
(I) Test number;
(J) Run number; and
(K) Operating level during the run.
(iii) For each run during which gas or mixed fuels are combusted
record the following data:
(A) Unit or common pipe identification code;
(B) Monitoring system identification code for gas monitoring
system;
(C) Run start date and time;
(D) Run end date and time;
(E) Volumetric flow of gas (100 scf);
(F) Gross calorific value of gas (Btu/100 scf);
(G) Hourly heat input (mmBtu) during run from gas;
(H) Test number;
(I) Run number; and
(J) Operating level during the run.
(iv) For each operating level at which runs were performed:
(A) Completion date and time of last run for operating level;
[[Page 28620]]
(B) Type of fuel(s) combusted during test;
(C) Average heat input rate at that operating level (mmBtu/hr);
(D) Arithmetic mean of NOX emission rates from reference
method run at this level;
(E) F-factor used in calculations of NOX emission rate
at that operating level;
(F) Unit operating parametric data related to NOX
formation for that unit type (e.g., excess O2 level, water/
fuel ratio);
(G) Test number; and
(H) Operating level for runs.
(c) For units with add-on SO2 or NOX emission
controls following the provisions of Sec. 75.34(a)(1) or (a)(2), the
owner or operator shall keep the following records on-site in the
quality assurance/quality control plan required by section 1 of
appendix B to this part:
(1) A list of operating parameters for the add-on emission
controls, including parameters in Sec. 75.55(b) or Sec. 75.58(b),
appropriate to the particular installation of add-on emission controls;
and
(2) The range of each operating parameter in the list that
indicates the add-on emission controls are properly operating.
(d) Excepted monitoring for low mass emissions units under
Sec. 75.19(c)(1)(iv). For oil-and gas-fired units using the optional
SO2, NOX and CO2 emissions
calculations for low mass emission units under Sec. 75.19, the owner or
operator shall record the following information for tests performed to
determine a fuel and unit-specific default as provided in
Sec. 75.19(c)(1)(iv):
(1) For each run of each test performed under section 2.1 of
appendix E to this part, record the following data:
(i) Unit or common pipe identification code;
(ii) Run start date and time;
(iii) Run end date and time;
(iv) NOX emission rate (lb/mmBtu) from reference method;
(v) Response time of the O2 and NOX reference
method analyzers;
(vi) Type of fuel(s) combusted during the run;
(vii) Test number;
(viii) Run number;
(ix) Operating level during the run;
(x) NOX concentration recorded by the reference method
during the run;
(xi) Diluent concentration recorded by the reference method during
the run;
(xii) Moisture measurement for the run (if applicable);
(xiii) An indicator that the resulting NOX emission rate
is the highest NOX emission rate record during any run of
the test (if appropriate);
(xiv) The default NOX emission rate (highest
NOX emission rate value during the test multiplied by 1.15);
(xv) An indicator that control equipment was operating or not
operating during each run of the test; and
(xvi) Parameter data indicating the use and efficacy of control
equipment during the test.
(2) For each unit in a group of identical units qualifying for
reduced testing under Sec. 75.19(c)(1)(iv)(B), record the following
data:
(i) The unique group identification code assigned to the group.
This code must include the ORIS code of one of the units in the group;
(ii) The ORIS code or facility identification code for the unit;
(iii) The plant name of the facility at which the unit is located,
consistent with the facility's monitoring plan;
(iv) The identification code for the unit, consistent with the
facility's monitoring plan;
(v) A record of whether or not the unit underwent fuel and unit-
specific testing for purposes of establishing a fuel and unit-specific
NOX emission rate for purposes of Sec. 75.19;
(vi) The completion date of the fuel and unit-specific test
performed for purposes of establishing a fuel and unit-specific
NOX emission rate for purposes of Sec. 75.19;
(vii) The fuel and unit-specific NOX default rate
established for the group of identical units under Sec. 75.19;
(viii) The type of fuel combusted for the units during testing and
represented by the resulting default NOX emission rate;
(ix) The control status for the units during testing and
represented by the resulting default NOX emission rate;
(x) Documentation supporting the qualification of all units in the
group for reduced testing based on the criteria established in
Secs. 75.19(c)(1)(iv)(B)(1) and (3); and
(xi) Purpose of group tests.
Subpart G--Reporting Requirements
43. Section 75.60 is amended by revising paragraphs (a), (b)(1),
and (b)(2) and by adding new paragraphs (b)(3), (b)(4), (b)(5) and
(b)(6) to read as follows:
Sec. 75.60 General provisions.
(a) The designated representative for any affected unit subject to
the requirements of this part shall comply with all reporting
requirements in this section and with the signatory requirements of
Sec. 72.21 of this chapter for all submissions.
(b) * * *
(1) Initial certifications. The designated representative shall
submit initial certification applications according to Sec. 75.63.
(2) Recertifications. The designated representative shall submit
recertification applications according to Sec. 75.63.
(3) Monitoring plans. The designated representative shall submit
monitoring plans according to Sec. 75.62.
(4) Electronic quarterly reports. The designated representative
shall submit electronic quarterly reports according to Sec. 75.64.
(5) Other petitions and communications. The designated
representative shall submit petitions, correspondence, application
forms, designated representative signature, and petition-related test
results in hardcopy to the Administrator. Additional petition
requirements are specified in Secs. 75.66 and 75.67.
(6) Semiannual or annual RATA reports. If requested by the
applicable EPA Regional Office, appropriate State, and/or appropriate
local air pollution control agency, the designated representative shall
submit a hardcopy RATA report within 45 days after completing a
required semiannual or annual RATA according to section 2.3.1 of
appendix B to this part, or within 15 days of receiving the request,
whichever is later. The designated representative shall report the
hardcopy information required by Sec. 75.59(a)(9) to the applicable EPA
Regional Office, appropriate State, and/or appropriate local air
pollution control agency that requested the RATA report.
* * * * *
44. Section 75.61 is amended by revising paragraphs (a)
introductory text, (a)(1) introductory text, and (b), by adding a new
sentence to the end of paragraph (a)(6)(ii), and by adding a new
paragraph (a)(1)(iv) to read as follows:
Sec. 75.61 Notifications.
(a) Submission. The designated representative for an affected unit
(or owner or operator, as specified) shall submit notice to the
Administrator, to the appropriate EPA Regional Office, and to the
applicable State and local air pollution control agencies for the
following purposes, as required by this part.
(1) Initial certification and recertification test notifications.
The owner or operator or designated representative for an affected unit
shall submit written notification of initial certification tests,
recertification tests, and revised test dates as specified in
[[Page 28621]]
Sec. 75.20 for continuous emission monitoring systems, 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 and
except for testing only of the data acquisition and handling system.
* * * * *
(iv) Waiver from notification requirements. The Administrator, the
appropriate EPA Regional Office, or the applicable State or local air
pollution control agency may issue a waiver from the notification
requirement of paragraph (a)(1) of this section, for a unit or a group
of units, for one or more recertification tests. The Administrator, the
appropriate EPA Regional Office, or the applicable State or local air
pollution control agency may also discontinue the waiver and reinstate
the notification requirement of paragraph (a)(1) of this section for
future recertification tests of a unit or a group of units.
* * * * *
(6) * * *
(ii) * * * The reporting requirements of this paragraph (a)(6)(ii)
also shall apply if the designated representative of a unit is exempt
from certifying a fuel flowmeter for use during the combustion of
emergency fuel under section 2.1.4.3 of appendix D to this part.
(b) The owner or operator or designated representative shall submit
notification of certification tests and recertification tests for
continuous opacity monitoring systems as specified in Sec. 75.20(c)(8)
to the State or local air pollution control agency.
* * * * *
45. Section 75.62 is amended by revising the title of the section
and revising paragraphs (a) and (c) to read as follows:
Sec. 75.62 Monitoring plan submittals.
(a) Submission.--(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 45 days prior to the initial certification test; at the time
of recertification application submission; and in each electronic
quarterly report.
(2) Hardcopy. The designated representative shall submit all of the
hardcopy information required under Sec. 75.53 to the appropriate EPA
Regional Office and the appropriate State and/or local air pollution
control agency prior to initial certification. Thereafter, the
designated representative shall submit hardcopy information only if
that portion of the monitoring plan is revised. The designated
representative shall submit the required hardcopy information as
follows: no later than 45 days prior to the initial certification test;
with any recertification application, if a hardcopy monitoring plan
change is associated with the recertification event; and within 30 days
of any other event with which a hardcopy monitoring plan change is
associated, pursuant to Sec. 75.53(b). Electronic submittal of all
monitoring plan information, including hardcopy portions, is
permissible provided that a paper copy of the hardcopy portions can be
furnished upon request.
* * * * *
(c) Format. The designated representative shall submit each
monitoring plan in a format specified by the Administrator.
46. Section 75.63 is revised to read as follows:
Sec. 75.63 Initial certification or recertification application
submittals.
(a) Submission. The designated representative for an affected unit
or a combustion source shall submit applications and reports as
follows:
(1) Initial certifications. (i) Within 45 days after completing all
initial certification tests, submit to the Administrator the electronic
information required by paragraph (b)(1) of this section and a hardcopy
certification application form (EPA form 7610-14). Except for subpart E
applications for alternative monitoring systems or unless specifically
requested by the Administrator, do not submit a hardcopy of the test
data and results to the Administrator.
(ii) Within 45 days after completing all initial certification
tests, submit the hardcopy information required by paragraph (b)(2) to
the applicable EPA Regional Office and the appropriate State and/or
local air pollution control agency.
(iii) For units for which the owner or operator is applying for
certification approval of the optional excepted methodology under
Sec. 75.19 for low mass emissions units, submit:
(A) To the Administrator, the electronic information required by
paragraph (b)(1)(i), the hardcopy information required by paragraph
(b)(2), and a hardcopy certification application form (EPA form 7610-
14); and
(B) To the applicable EPA Regional Office and appropriate State
and/or local air pollution control agency, the hardcopy information
required by paragraphs (b)(2)(i), (iii), and (iv).
(2) Recertifications. (i) Within 45 days after completing all
recertification tests, submit to the Administrator the electronic
information required by paragraph (b)(1) and a hardcopy certification
application form (EPA form 7610-14). Except for subpart E applications
for alternative monitoring systems or unless specifically requested by
the Administrator, do not submit a hardcopy of the test data and
results to the Administrator.
(ii) Within 45 days after completing all recertification tests,
submit the hardcopy information required by paragraph (b)(2) to the
applicable EPA Regional Office and the appropriate State and/or local
air pollution control agency. The applicable EPA Regional Office or
appropriate State or local air pollution control agency may waive the
requirement for submission to it of a hardcopy recertification. The
applicable EPA Regional Office or the appropriate State or local air
pollution control agency may also discontinue the waiver and reinstate
the requirement of this paragraph to provide a hardcopy report of the
recertification test data and results.
(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,
no hardcopy submittal is required; however, the results of all
diagnostic test(s) shall be submitted in the electronic quarterly
report required under Sec. 75.64. For DAHS (missing data and formula)
verifications, neither a hardcopy nor an electronic submittal of any
kind is required; the owner or operator shall keep these test results
on-site in a format suitable for inspection.
(b) Contents. Each application for initial certification or
recertification shall contain the following information, as applicable:
(1) Electronic. (i) A complete, up-to-date version of the
electronic portion of the monitoring plan, according to Secs. 75.53(c)
and (d), or Secs. 75.53(e) and (f), as applicable, in the format
specified in Sec. 75.62(c).
(ii) The results of the test(s) required by Sec. 75.20, including
the type of test conducted, testing date, information required by
Sec. 75.56 or Sec. 75.59, as applicable, and the results of any failed
tests that affect data validation.
(2) Hardcopy. (i) Any changed portions of the hardcopy monitoring
plan information required under
[[Page 28622]]
Sec. Sec. 75.53(c) and (d), or Secs. 75.53(e) and (f), as applicable.
Electronic submittal of all monitoring plan information, including the
hardcopy portions, is permissible, provided that a paper copy can be
furnished upon request.
(ii) The results of the test(s) required by Sec. 75.20, including
the type of test conducted, testing date, information required by
Sec. 75.59(a)(9), and the results of any failed tests that affect data
validation.
(iii) Certification or recertification application form (EPA form
7610-14).
(iv) Designated representative signature.
(c) Format. The electronic portion of each certification or
recertification application shall be submitted in a format to be
specified by the Administrator. The hardcopy test results shall be
submitted in a format suitable for review and shall include the
information in Sec. 75.59(a)(9).
47. Section 75.64 is revised to 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 later of: the last
(partial) calendar quarter of 1993 (where the calendar quarter data
begins at November 15, 1993); or 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), whichever quarter is earlier. 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), 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 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. Each electronic report
shall include the date of report generation for the information
provided in paragraphs (a)(2) through (a)(11) of this section, and
shall also include for each affected unit (or group of units using a
common stack):
(1) Facility information:
(i) Identification, including:
(A) Facility/ORISPL number;
(B) Calendar quarter and year for the data contained in the report;
and
(C) Version of the electronic data reporting format used for the
report.
(ii) Location, including:
(A) Plant name and facility ID;
(B) EPA AIRS facility system ID;
(C) State facility ID;
(D) Source category/type;
(E) Primary SIC code;
(F) State postal abbreviation;
(G) County code; and
(H) Latitude and longitude.
(2) The information and hourly data required in Secs. 75.53 through
75.59, excluding the following:
(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. 75.54(f) or 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. 75.55(b)(3) or Sec. 75.58(b)(3);
(v) The information recorded under Sec. 75.56(a)(7) for the period
prior to April 1, 2000;
(vi) Information required by Sec. 75.54(g) or Sec. 75.57(h)
concerning the causes of any missing data periods and the actions taken
to cure such causes;
(vii) Hardcopy monitoring plan information required by Sec. 75.53
and hardcopy test data and results required by Sec. 75.56 or
Sec. 75.59;
(viii) Records of flow monitor and moisture monitoring system
polynomial equations, coefficients or ``K'' factors required by
Sec. 75.56(a)(5)(vii), Sec. 75.56(a)(5)(ix), Sec. 75.59(a)(5)(vi) or
Sec. 75.59(a)(5)(vii);
(ix) Daily fuel sampling information required by
Sec. 75.58(c)(3)(i) for units using assumed values under appendix D;
(x) Information required by Secs. 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;
(xi) Stratification test results required as part of the RATA
supplementary records under Secs. 75.56(a)(7) or 75.59(a)(7);
(xii) 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
(xiv) Supplementary RATA information required under
Sec. 75.59(a)(7)(i) through Sec. 75.59(a)(7)(v), except that: the data
under Sec. 75.59(a)(7)(ii)(A) through (T) and the data under
Sec. 75.59(a)(7)(iii)(A) through (M) shall, as applicable, be reported
for flow RATAs in which angular compensation (measurement of pitch and/
or yaw angles) is used and for flow RATAs in which a site-specific wall
effects adjustment factor is determined by direct measurement; and the
data under Sec. 75.59(a)(7)(ii)(T) shall be reported for all flow RATAs
in which a default wall effects adjustment factor is applied.
(3) Tons (rounded to the nearest tenth) of SO2 emitted
during the quarter and cumulative SO2 emissions for the
calendar year.
(4) Average NOX emission rate (lb/mmBtu, rounded to the
nearest hundredth prior to April 1, 2000 and to the nearest thousandth
on and after April 1, 2000) during the quarter and cumulative
NOX emission rate for the calendar year.
(5) Tons of CO2 emitted during quarter and cumulative
CO2 emissions for calendar year.
(6) Total heat input (mmBtu) for quarter and cumulative heat input
for calendar year.
(7) Unit or stack or common pipe header operating hours for quarter
and cumulative unit or stack or common pipe header operating hours for
calendar year.
(8) If the affected unit is using a qualifying Phase I technology,
then the quarterly report shall include the information required in
paragraph (e) of this section.
(9) For low mass emissions units for which the owner or operator is
using the optional low mass emissions methodology in Sec. 75.19(c) to
calculate NOX mass emissions, the designated representative
must also report tons (rounded to the nearest tenth) of NOX
emitted during the quarter and cumulative NOX mass emissions
for the calendar year.
(10) For low mass emissions units using the optional long term fuel
flow methodology under Sec. 75.19(c), for each quarter report the long
term fuel flow for each fuel according to Sec. 75.59.
(11) For units using the optional fuel flow to load procedure in
section 2.1.7 of appendix D to this part, report both the fuel flow-to-
load baseline data and
[[Page 28623]]
the results of the fuel flow-to-load test each quarter.
(b) The designated representative shall affirm that the component/
system identification codes and formulas in the quarterly electronic
reports, submitted to the Administrator pursuant to Sec. 75.53,
represent current operating conditions.
(c) Compliance certification. The designated representative shall
submit a certification in support of each quarterly emissions
monitoring report based on reasonable inquiry of those persons with
primary responsibility for ensuring that all of the unit's emissions
are correctly and fully monitored. The certification shall indicate
whether the monitoring data submitted were recorded in accordance with
the applicable requirements of this part including the quality control
and quality assurance procedures and specifications of this part and
its appendices, and any such requirements, procedures and
specifications of an applicable excepted or approved alternative
monitoring method. For a unit with add-on emission controls, the
designated representative shall also include a certification, for all
hours where data are substituted following the provisions of
Sec. 75.34(a)(1), that the add-on emission controls were operating
within the range of parameters listed in the monitoring plan and that
the substitute values recorded during the quarter do not systematically
underestimate SO2 or NOX emissions, pursuant to
Sec. 75.34.
(d) Electronic format. Each quarterly report shall be submitted in
a format to be specified by the Administrator, including both
electronic submission of data and electronic or hardcopy submission of
compliance certifications.
(e) Phase I qualifying technology reports. In addition to reporting
the information in paragraphs (a), (b), and (c) of this section, the
designated representative for an affected unit on which SO2
emission controls have been installed and operated for the purpose of
meeting qualifying Phase I technology requirements pursuant to
Sec. 72.42 of this chapter shall also submit reports documenting the
measured percent SO2 emissions removal to the Administrator
on a quarterly basis, beginning the first quarter of 1997 and
continuing through the fourth quarter of 1999. Each report shall
include all measurements and calculations necessary to substantiate
that the qualifying technology achieves the required percent reduction
in SO2 emissions.
(f) Method of submission. Beginning with the quarterly report for
the first quarter of the year 2001, all quarterly reports shall be
submitted to EPA by direct computer-to-computer electronic transfer via
modem and EPA-provided software, unless otherwise approved by the
Administrator.
(g) Any cover letter text accompanying a quarterly report shall
either be submitted in hardcopy to the Agency or be provided in
electronic format compatible with the other data required to be
reported under this section.
48. Section 75.65 is revised to read as follows:
Sec. 75.65 Opacity reports.
The owner or operator or designated representative shall report
excess emissions of opacity recorded under Sec. 75.54(f) or
Sec. 75.57(f), as applicable, to the applicable State or local air
pollution control agency.
49. Section 75.66 is amended by revising paragraph (a) and the
first sentence of paragraph (e) introductory text; by redesignating
paragraph (i) as paragraph (l) and revising it; and by adding
paragraphs (i) through (k) to read as follows:
Sec. 75.66 Petitions to the Administrator.
(a) General. The designated representative for an affected unit
subject to the requirements of this part may submit a petition to the
Administrator requesting that the Administrator exercise his or her
discretion to approve an alternative to any requirement prescribed in
this part or incorporated by reference in this part. Any such petition
shall be submitted in accordance with the requirements of this section.
The designated representative shall comply with the signatory
requirements of Sec. 72.21 of this chapter for each submission.
* * * * *
(e) Parametric monitoring procedure petitions. The designated
representative for an affected unit may submit a petition to the
Administrator, where each petition shall contain the information
specified in Sec. 75.55(b) or Sec. 75.58(b), as applicable, for the use
of a parametric monitoring method. * * *
* * * * *
(i) Emergency fuel petition. The designated representative for an
affected unit may submit a petition to the Administrator to use the
emergency fuel provisions in section 2.1.4 of appendix E to this part.
The designated representative shall include the following information
in the petition:
(1) Identification of the affected plant and unit(s);
(2) A procedure for determining the NOX emission rate
for the unit when the emergency fuel is combusted; and
(3) A demonstration that the permit restricts use of the fuel to
emergencies only.
(j) Petition for alternative method of accounting for emissions
prior to completion of certification tests. The designated
representative for an affected unit may submit a petition to the
Administrator to use an alternative to the procedures in
Sec. 75.4(d)(3), (e)(3), (f)(3) or (g)(3) to account for emissions
during the period between the compliance date for a unit and the
completion of certification testing for that unit. The designated
representative shall include:
(1) Identification of the affected unit(s);
(2) A detailed explanation of the alternative method to account for
emissions of the following parameters, as applicable: SO2
mass emissions (in lbs), NOX emission rate (in lbs/mmBtu),
CO2 mass emissions (in lbs) and, if the unit is subject to
the requirements of subpart H of this part, NOX mass
emissions (in lbs); and
(3) A demonstration that the proposed alternative does not
underestimate emissions.
(k) Petition for an alternative to the stabilization criteria for
the cycle time test in section 6.4 of appendix A to this part. The
designated representative for an affected unit may submit a petition to
the Administrator to use an alternative stabilization criteria for the
cycle time test in section 6.4 of appendix A to this part, if the
installed monitoring system does not record data in 1-minute or 3-
minute intervals. The designated representative shall provide a
description of the alternative criteria.
(l) Any other petitions to the Administrator under this part.
Except for petitions addressed in paragraphs (b) through (k) of this
section, any petition submitted under this paragraph shall include
sufficient information for the evaluation of the petition, including,
at a minimum, the following information:
(1) Identification of the affected plant and unit(s);
(2) A detailed explanation of why the proposed alternative is being
suggested in lieu of the requirement;
(3) A description and diagram of any equipment and procedures used
in the proposed alternative, if applicable;
(4) A demonstration that the proposed alternative is consistent
with the purposes of the requirement for which the alternative is
proposed and is consistent with the purposes of this part and of
section 412 of the Act and that any adverse effect of approving such
alternative will be de minimis; and
(5) Any other relevant information that the Administrator may
require.
[[Page 28624]]
Subpart H--NOX Mass Emissions Provisions
50. Section 75.70 is amended by revising paragraphs (e), (f)
introductory text and (f)(1)(iv), and by adding new paragraph (g)(6) to
read as follows:
Sec. 75.70 NOX mass emissions provisions.
* * * * *
(e) Quality assurance and quality control requirements. For units
that use continuous emission monitoring systems to account for
NOX mass emissions, the owner or operator shall meet the
applicable quality assurance and quality control requirements in
Sec. 75.21, appendix B to this part, and Sec. 75.74(c) for the
NOX-diluent continuous emission monitoring systems, flow
monitoring systems, NOX concentration monitoring systems,
and diluent monitors required under Sec. 75.71. A NOX
concentration monitoring system for determining NOX mass
emissions in accordance with Sec. 75.71 shall meet the same
certification testing requirements, quality assurance requirements, and
bias test requirements as are specified in this part for an
SO2 pollutant concentration monitor, except as otherwise
provided in Sec. 75.74(c). Units using excepted methods under
Sec. 75.19 shall meet the applicable quality assurance requirements of
that section, and, except as otherwise provided in Sec. 75.74(c), units
using excepted monitoring methods under appendices D and E to this part
shall meet the applicable quality assurance requirements of those
appendices.
(f) Missing data procedures. Except as provided in Sec. 75.34,
paragraph (g) of this section, and Sec. 75.74, the owner or operator
shall provide substitute data from monitoring systems required under
Sec. 75.71 for each affected unit as follows:
(1) * * *
(iv) A valid, quality-assured hour of NOX concentration
data (in ppm) has not been measured and recorded by a certified
NOX concentration monitoring system, or by an approved
alternative monitoring method under subpart E of this part, where the
owner or operator chooses to use a NOX concentration
monitoring system with a volumetric flow monitor, and without a diluent
monitor to calculate NOX mass emissions. The initial missing
data procedures for determining monitor data availability and the
standard missing data procedures for a NOX concentration
monitoring system shall be the same as the procedures specified for a
NOX-diluent continuous emission monitoring system under
Secs. 75.31, 75.32 and 75.33.
* * * * *
(g) * * *
(6) For any unit using continuous emissions monitors, the
procedures in Sec. 75.20(b)(3).
* * * * *
51. Section 75.71 is amended by revising paragraphs (b) and (d)(2)
to read as follows:
Sec. 75.71 Specific provisions for monitoring NOX emission
rate and heat input for the purpose of calculating NOX mass
emissions.
* * * * *
(b) Moisture correction. (1) If a correction for the stack gas
moisture content is needed to properly calculate the NOX
emission rate in lb/mmBtu (i.e., if the NOX pollutant
concentration monitor in a NOX-diluent monitoring system
measures on a different moisture basis from the diluent monitor), the
owner or operator of an affected unit shall account for the moisture
content of the flue gas on a continuous basis in accordance with
Sec. 75.12(b).
(2) If a correction for the stack gas moisture content is needed to
properly calculate NOX mass emissions in tons, in the case
where a NOX concentration monitoring system which measures
on a dry basis is used with a flow rate monitor to determine
NOX mass emissions, the owner or operator of an affected
unit shall account for the moisture content of the flue gas on a
continuous basis in accordance with Sec. 75.11(b) except that the term
``SO2'' shall be replaced by the term ``NOX.''
(3) If a correction for the stack gas moisture content is needed to
properly calculate NOX mass emissions, in the case where a
diluent monitor that measures on a dry basis is used with a flow rate
monitor to determine heat input, which is then multiplied by the
NOX emission rate, the owner or operator shall install,
operate, maintain and quality assure a continuous moisture monitoring
system, as described in Sec. 75.11(b).
* * * * *
(d) * * *
(2) Use the procedures in appendix D to this part for determining
hourly heat input and the procedure specified in appendix E to this
part for estimating hourly NOX emission rate. However, the
heat input apportionment provisions in section 2.1.2 of appendix D to
this part shall not be used to meet the NOX mass reporting
provisions of this subpart. In addition, if after certification of an
excepted monitoring system under appendix E to this part, the operation
of a unit that reports emissions on an annual basis under Sec. 75.74(a)
of this part exceeds a capacity factor of 20.0 percent in any calendar
year or exceeds an annual capacity factor of 10.0 percent averaged over
three years, or the operation of a unit that reports emissions on an
ozone season basis under Sec. 75.74(b) of this part exceeds a capacity
factor of 20.0 percent in any ozone season or exceeds an ozone season
capacity factor of 10.0 percent averaged over three years, the owner or
operator shall meet the requirements of paragraph (c) of this section
or, if applicable, paragraph (e) of this section by no later than
December 31 of the following calendar year.
* * * * *
52. Text is added to reserved section 75.73 to read as follows:
Sec. 75.73 Recordkeeping and reporting.
(a) General recordkeeping provisions. The owner or operator of any
affected unit shall maintain for each affected unit and each non-
affected unit under Sec. 75.72(b)(2)(ii) a file of all measurements,
data, reports, and other information required by this part at the
source in a form suitable for inspection for at least three (3) years
from the date of each record. Except for the certification data
required in Sec. 75.57(a)(4) and the initial submission of the
monitoring plan required in Sec. 75.57(a)(5), the data shall be
collected beginning with the earlier of the date of provisional
certification or the deadline in Sec. 75.70. The certification data
required in Sec. 75.57(a)(4) shall be collected beginning with the date
of the first certification test performed. The file shall contain the
following information:
(1) The information required in Secs. 75.57(a)(2), (a)(4), (a)(5),
(a)(6), (b), (c)(2), (d), (g), and (h).
(2) The information required in Secs. 75.58(b)(2) or (b)(3) (for
units with add-on NOX emission controls), as applicable, (d)
(as applicable for units using Appendix E to this part), and (f) (as
applicable for units using the low mass emissions unit provisions of
Sec. 75.19).
(3) For each hour when the unit is operating, NOX mass
emissions, calculated in accordance with section 8.1 of appendix F to
this part.
(4) During the second and third calendar quarters, cumulative ozone
season heat input and cumulative ozone season operating hours.
(5) Heat input and NOX methodologies for the hour.
(6) Specific heat input record provisions for gas-fired or oil-
fired units using the procedures in appendix D to this part. In lieu of
the information required in Sec. 75.57(c)(2), the owner or operator
shall record the following information in this paragraph for each
[[Page 28625]]
affected gas-fired or oil-fired unit and each non-affected gas- or oil-
fired unit under Sec. 75.72(b)(2)(ii) for which the owner or operator
is using the procedures in appendix D to this part for estimating heat
input:
(i) For each hour when the unit is combusting oil:
(A) Date and hour;
(B) Hourly average mass flow rate of oil, while the unit combusts
oil (in lb/hr, rounded to the nearest tenth) (flag value if derived
from missing data procedures);
(C) Method of oil sampling (flow proportional, continuous drip, as
delivered, manual from storage tank, or daily manual);
(D) For units using volumetric flowmeters, volumetric flow rate of
oil combusted each hour (in gal/hr, lb/hr, m3/hr, or bbl/hr,
rounded to the nearest tenth) (flag value if derived from missing data
procedures);
(E) For units using volumetric oil flowmeters, density of oil (flag
value if derived from missing data procedures);
(F) Gross calorific value of oil used to determine heat input (in
Btu/lb);
(G) Hourly heat input rate during combustion of oil, according to
procedures in appendix F to this part (in mmBtu/hr, to the nearest
tenth);
(H) Fuel usage time for combustion of oil during the hour (rounded
up to the nearest 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) (flag to indicate multiple/single fuel types
combusted); and
(I) Monitoring system identification code.
(ii) For gas-fired units or oil-fired units, using the procedures
in appendix D to this part with an assumed density or for as-delivered
fuel sampled from each delivery:
(A) Measured gross calorific value and, if measuring with
volumetric oil flowmeters, density from each fuel sample; and
(B) Assumed gross calorific value and, if measuring with volumetric
oil flowmeters, density used to calculate heat input rate.
(iii) For each hour when the unit is combusting gaseous fuel:
(A) Date and hour;
(B) Hourly heat input rate from gaseous fuel, according to
procedures in appendix F to this part (in mmBtu/hr, rounded to the
nearest tenth);
(C) Hourly flow rate of gaseous fuel, while the unit combusts gas
(in 100 scfh) (flag value if derived from missing data procedures);
(D) Gross calorific value of gaseous fuel used to determine heat
input rate (in Btu/100 scf) (flag value if derived from missing data
procedures);
(E) Fuel usage time for combustion of gaseous fuel during the hour
(rounded up to the nearest 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) (flag to indicate multiple/single fuel
types combusted); and
(F) Monitoring system identification code.
(iv) For each oil sample or sample of diesel fuel:
(A) Date of sampling;
(B) Gross calorific value (in Btu/lb) (flag value if derived from
missing data procedures); and
(C) Density or specific gravity, if required to convert volume to
mass (flag value if derived from missing data procedures).
(v) For each sample of gaseous fuel:
(A) Date of sampling; and
(B) Gross calorific value (in Btu/100 scf) (flag value if derived
from missing data procedures).
(vi) For each oil sample or sample of gaseous fuel:
(A) Type of oil or gas; and
(B) Percent carbon or F-factor of fuel.
(7) Specific NOX record provisions for gas-fired or oil-
fired units using the optional low mass emissions excepted methodology
in Sec. 75.19. In lieu of recording the information in Secs. 75.57(b),
(c)(2), (d), and (g), the owner or operator shall record, for each hour
when the unit is operating for any portion of the hour, the following
information for each affected low mass emissions unit for which the
owner or operator is using the low mass emissions excepted methodology
in Sec. 75.19(c):
(i) Date and hour;
(ii) If one type of fuel is combusted in the hour, fuel type
(pipeline natural gas, natural gas, residual oil, or diesel fuel) or,
if more than one type of fuel is combusted in the hour, the fuel type
which results in the highest emission factors for NOX;
(iii) Average hourly NOX emission rate (in lb/mmBtu,
rounded to the nearest thousandth); and
(iv) Hourly NOX mass emissions (in lbs, rounded to the
nearest tenth).
(b) Certification, quality assurance and quality control record
provisions. The owner or operator of any affected unit shall record the
applicable information in Sec. 75.59 for each affected unit or group of
units monitored at a common stack and each non-affected unit under
Sec. 75.72(b)(2)(ii).
(c) Monitoring plan recordkeeping provisions--(1) General
provisions. The owner or operator of an affected unit shall prepare and
maintain a monitoring plan for each affected unit or group of units
monitored at a common stack and each non-affected unit under
Sec. 75.72(b)(2)(ii). Except as provided in paragraph (d) or (f) of
this section, a monitoring plan shall contain sufficient information on
the continuous emission monitoring systems, excepted methodology under
Sec. 75.19, or excepted monitoring systems under appendix D or E to
this part and the use of data derived from these systems to demonstrate
that all the unit's NOX emissions are monitored and
reported.
(2) Whenever the owner or operator makes a replacement,
modification, or change in the certified continuous emission monitoring
system, excepted methodology under Sec. 75.19, excepted monitoring
system under appendix D or E to this part, or alternative monitoring
system under subpart E of this part, including a change in the
automated data acquisition and handling system or in the flue gas
handling system, that affects information reported in the monitoring
plan (e.g., a change to a serial number for a component of a monitoring
system), then the owner or operator shall update the monitoring plan.
(3) Contents of the monitoring plan for units not subject to an
Acid Rain emissions limitation. Each monitoring plan shall contain the
information in Sec. 75.53(e)(1) in electronic format and the
information in Sec. 75.53(e)(2) in hardcopy format. In addition, to the
extent applicable, each monitoring plan shall contain the information
in Secs. 75.53(f)(1)(i), (f)(2)(i), (f)(4), and (f)(5)(i) for units
using the low mass emitter methodology in electronic format and the
information in Secs. 75.53(f)(1)(ii), (f)(2)(ii), and (f)(5)(ii) in
hardcopy format. The monitoring plan also shall identify, in electronic
format, the reporting schedule for the affected unit (ozone season or
quarterly), the beginning and end dates for the reporting schedule, and
whether year-round reporting for the unit is required by a state or
local agency.
(d) General reporting provisions. (1) The designated representative
for an affected unit shall comply with all reporting requirements in
this section and with any additional requirements set forth in an
applicable State or federal NOX mass emission reduction
program that adopts the requirements of this subpart.
(2) The designated representative for an affected unit shall submit
the following for each affected unit or group of units monitored at a
common stack and each non-affected unit under Sec. 75.72(b)(2)(ii):
[[Page 28626]]
(i) Initial certification and recertification applications in
accordance with Sec. 75.70(d);
(ii) Monitoring plans in accordance with paragraph (e) of this
section; and
(iii) Quarterly reports in accordance with paragraph (f) of this
section.
(3) Other petitions and communications. The designated
representative for an affected unit shall submit petitions,
correspondence, application forms, and petition-related test results in
accordance with the provisions in Sec. 75.70(h).
(4) Quality assurance RATA reports. If requested by the permitting
authority, the designated representative of an affected unit shall
submit the quality assurance RATA report for each affected unit or
group of units monitored at a common stack and each non-affected unit
under Sec. 75.72(b)(2)(ii) by the later of 45 days after completing a
quality assurance RATA according to section 2.3 of appendix B to this
part or 15 days of receiving the request. The designated representative
shall report the hardcopy information required by Sec. 75.59(a)(9) to
the permitting authority.
(5) Notifications. The designated representative for an affected
unit shall submit written notice to the permitting authority according
to the provisions in Sec. 75.61 for each affected unit or group of
units monitored at a common stack and each non-affected unit under
Sec. 75.72(b)(2)(ii).
(e) Monitoring plan reporting.--(1) Electronic submission. 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 (e)(2) of this section) for each
affected unit or group of units monitored at a common stack and each
non-affected unit under Sec. 75.72(b)(2)(ii) as follows:
(i) To the permitting authority, no later than 45 days prior to the
initial certification test and at the time of recertification
application submission; and
(ii) To the Administrator, no later than 45 days prior to the
initial certification test, at the time of submission of a
recertification application, and in each electronic quarterly report.
(2) Hardcopy submission. The designated representative of an
affected unit shall submit all of the hardcopy information required
under Sec. 75.53, for each affected unit or group of units monitored at
a common stack and each non-affected unit under Sec. 75.72(b)(2)(ii),
to the permitting authority prior to initial certification. Thereafter,
the designated representative shall submit hardcopy information only if
that portion of the monitoring plan is revised. The designated
representative shall submit the required hardcopy information as
follows: no later than 45 days prior to the initial certification test;
with any recertification application, if a hardcopy monitoring plan
change is associated with the recertification event; and within 30 days
of any other event with which a hardcopy monitoring plan change is
associated, pursuant to Sec. 75.53(b).
(f) Quarterly reports.--(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. Each electronic
report must be submitted to the Administrator within 30 days following
the end of each calendar quarter. Each electronic report shall include
the date of report generation, for the information provided in
paragraphs (f)(1)(ii) through (1)(vi) of this section, and shall also
include for each affected unit or group of units monitored at a common
stack:
(i) Facility information:
(A) Identification, including:
(1) Facility/ORISPL number;
(2) Calendar quarter and year data contained in the report; and
(3) Electronic data reporting format version used for the report.
(B) Location of facility, including:
(1) Plant name and facility identification code;
(2) EPA AIRS facility system identification code;
(3) State facility identification code;
(4) Source category/type;
(5) Primary SIC code;
(6) State postal abbreviation;
(7) FIPS county code; and
(8) Latitude and longitude.
(ii) The information and hourly data required in paragraph (a) of
this section, except for:
(A) Descriptions of adjustments, corrective action, and
maintenance;
(B) Information which is incompatible with electronic reporting
(e.g., field data sheets, lab analyses, quality control plan);
(C) For units with 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);
(D) Information required by Sec. 75.57(h) concerning the causes of
any missing data periods and the actions taken to cure such causes;
(E) Hardcopy monitoring plan information required by Sec. 75.53 and
hardcopy test data and results required by Sec. 75.59;
(F) Records of flow polynomial equations and numerical values
required by Sec. 75.59(a)(5)(vi);
(G) Daily fuel sampling information required by Sec. 75.58(c)(3)(i)
for units using assumed values under appendix D;
(H) Information required by Sec. 75.59(b)(2) concerning transmitter
or transducer accuracy tests;
(I) Stratification test results required as part of the RATA
supplementary records under Sec. 75.59(a)(7);
(J) 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 operational problems with the unit; and
(K) Supplementary RATA information required under
Sec. 75.59(a)(7)(i) through Sec. 75.59(a)(7)(v), except that: the data
under Sec. 75.59(a)(7)(ii)(A) through (T) and the data under
Sec. 75.59(a)(7)(iii)(A) through (M) shall, as applicable, be reported
for flow RATAs in which angular compensation (measurement of pitch and/
or yaw angles) is used and for flow RATAs in which a site-specific wall
effects adjustment factor is determined by direct measurement; and the
data under Sec. 75.59(a)(7)(ii)(T) shall be reported for all flow RATAs
in which a default wall effects adjustment factor is applied.
(iii) Average NOX emission rate (lb/mmBtu, rounded to
the nearest thousandth) during the quarter and cumulative
NOX emission rate for the calendar year.
(iv) Tons of NOX emitted during quarter, cumulative tons
of NOX emitted during the year, and, during the second and
third calendar quarters, cumulative tons of NOX emitted
during the ozone season.
(v) During the second and third calendar quarters, cumulative heat
input for the ozone season.
(vi) Unit or stack or common pipe header operating hours for
quarter, cumulative unit, stack or common pipe header operating hours
for calendar year, and, during the second and third calendar quarters,
cumulative operating hours during the ozone season.
(2) The designated representative shall certify that the component
and system identification codes and formulas in the quarterly
electronic reports submitted to the Administrator pursuant to paragraph
(e) of this section represent current operating conditions.
(3) Compliance certification. The designated representative shall
submit and sign a compliance certification in
[[Page 28627]]
support of each quarterly emissions monitoring report based on
reasonable inquiry of those persons with primary responsibility for
ensuring that all of the unit's emissions are correctly and fully
monitored. The certification shall state that:
(i) The monitoring data submitted were recorded in accordance with
the applicable requirements of this part, including the quality
assurance procedures and specifications; and
(ii) With regard to a unit with add-on emission controls and for
all hours where data are substituted in accordance with
Sec. 75.34(a)(1), the add-on emission controls were operating within
the range of parameters listed in the monitoring plan and the
substitute values do not systematically underestimate NOX
emissions.
(4) The designated representative shall comply with all of the
quarterly reporting requirements in Secs. 75.64(d), (f), and (g).
53. Section 75.74 is amended by:
a. Revising paragraphs (b)(2), (c)(1) and (c)(2);
b. Redesignating paragraphs (c)(3), (c)(4), (c)(5), (c)(6), (c)(7),
(c)(8), (c)(9) and (c)(10), as paragraphs (c)(4), (c)(5), (c)(6),
(c)(7), (c)(8), (c)(9), (c)(10) and (c)(11), respectively;
c. Adding a new paragraph (c)(3); and
d. Revising newly redesignated paragraphs (c)(4), (c)(5), (c)(6)
and (c)(7), to read as follows:
Sec. 75.74 Annual and ozone season monitoring and reporting
requirements.
* * * * *
(b) * * *
(2) Meet the requirements of this subpart during the ozone season,
except as specified in paragraph (c) of this section.
(c) * * *
(1) The owner or operator of a unit that uses continuous emissions
monitoring systems or a fuel flowmeter to meet any of the requirements
of this subpart shall quality assure the hourly ozone season emission
data required by this subpart. To achieve this, the owner or operator
shall operate, maintain and calibrate each required CEMS and shall
perform diagnostic testing and quality assurance testing of each
required CEMS or fuel flowmeter according to the applicable provisions
of paragraphs (c)(2) through (c)(5) of this section. Except where
otherwise noted, the provisions of paragraphs (c)(2) and (c)(3) of this
section apply instead of the quality assurance provisions in sections
2.1 through 2.3 of appendix B to this part, and shall be used in lieu
of those appendix B provisions.
(2) Quality assurance requirements prior to the ozone season. The
provisions of this paragraph apply to each ozone season. 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 owner or operator shall, at
a minimum, perform the following diagnostic testing and quality
assurance assessments, and shall maintain the following records, to
ensure that the hourly emission data recorded at the beginning of the
current ozone season are suitable for reporting as quality-assured
data:
(i) For each required gas monitor (i.e., for each NOX
pollutant concentration monitor and each diluent gas (CO2 or
O2) monitor, including CO2 and O2
monitors used exclusively for heat input determination and
O2 monitors used for moisture determination), a linearity
check shall be performed and passed.
(A) 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.
(B) Each linearity check shall be done ``hands-off,'' as described
in section 2.2.3(c) of appendix B to this part.
(C) In the time period extending from the date and hour in which
the linearity check is passed through April 30 of the current calendar
year, the owner or operator shall operate and maintain the CEMS and
shall perform daily calibration error tests of the CEMS in accordance
with section 2.1 of appendix B to this part. When a calibration error
test is failed, as described in section 2.1.4 of appendix B to this
part, corrective actions shall be taken. The additional calibration
error test provisions of section 2.1.3 of appendix B to this part shall
be followed. Records of the required daily calibration error tests
shall be kept in a format suitable for inspection on a year-round
basis.
(D) Exceptions. (1) If the monitor passed a linearity check on or
after January 1 of the previous year and the unit or stack on which the
monitor is located operated for less than 336 hours in the previous
ozone season, the owner or operator may have a grace period of up to
168 hours to perform a linearity check. In addition, if the unit or
stack operates for 168 hours or less in the current ozone season the
owner or operator is exempt from the linearity check requirement for
that ozone season and the owner or operator may submit quality assured
data from that monitor as long as all other required quality assurance
tests are passed. If the unit or stack operates for more than 168 hours
in the current ozone season, the owner or operator of the unit shall
report substitute data using the missing data procedures under
paragraph (c)(7) of this section starting with the 169th unit or stack
operating hour of the ozone season and continuing until the successful
completion of a linearity check.
(2) If a monitor does not qualify for an exception under paragraph
(c)(2)(i)(D)(1) and if a required linearity check has not been
completed prior to the start of the current ozone season, follow the
applicable procedures in paragraph (c)(3)(vi) of this section.
(ii) For each required CEMS (i.e., for each NOX
concentration monitoring system, each NOX-diluent monitoring
system, each flow rate monitoring system, each moisture monitoring
system and each diluent gas CEMS used exclusively for heat input
determination), a relative accuracy test audit (RATA) shall be
performed and passed.
(A) Conduct each RATA in accordance with the applicable procedures
in sections 6.5 through 6.5.10 of appendix A to this part, except that
the data validation procedures in sections 6.5(f)(1) through (f)(6) do
not apply, and, for flow rate monitoring systems, the required RATA
load level(s) shall be as specified in this paragraph.
(B) Each RATA shall be done ``hands-off,'' as described in section
2.3.2 (c) of appendix B to this part. The provisions in section 2.3.1.4
of appendix B to this part, pertaining to the number of allowable RATA
attempts, shall apply.
(C) For flow rate monitoring systems installed on peaking units or
bypass stacks, a single-load RATA is required. For all other flow rate
monitoring systems, a 2-load RATA is required at the two most
frequently-used load levels (as defined under section 6.5.2.1 of
appendix A to this part), with the following exceptions. A 3-load flow
RATA is required at least once in every period of five consecutive
calendar years. A 3-load RATA is also required if the flow monitor
polynomial coefficients or K factor(s) are changed prior to conducting
the flow RATA required under this paragraph.
(D) A bias test of each required NOX concentration
monitoring system, each NOX-diluent monitoring system and
each flow rate monitoring system shall be performed in accordance with
section 7.6 of appendix A to this part. If the bias test is failed, a
bias adjustment factor (BAF) shall be calculated for the monitoring
system, as described in section 7.6.5 of appendix A to this part and
shall be applied to the subsequent data recorded by the CEMS.
[[Page 28628]]
(E) In the time period extending from the hour of completion of the
required RATA through April 30 of the current calendar year, the owner
or operator shall operate and maintain the CEMS by performing, at a
minimum, the following activities:
(1) The owner or operator shall perform daily calibration error
tests and (if applicable) daily flow monitor interference checks,
according to section 2.1 of appendix B to this part. When a daily
calibration error test or interference check is failed, as described in
section 2.1.4 of appendix B to this part, corrective actions shall be
taken. The additional calibration error test provisions in section
2.1.3 of appendix B to this part shall be followed. Records of the
required daily calibration error tests and interference checks shall be
kept in a format suitable for inspection on a year-round basis.
(2) If the owner or operator makes a replacement, modification, or
change in a certified monitoring system that significantly affects the
ability of the system to accurately measure or record NOX
mass emissions or heat input or to meet the requirements of Sec. 75.21
or appendix B to this part, the owner or operator shall recertify the
monitoring system according to Sec. 75.20(b).
(F) If the results of a RATA performed according to the provisions
of this paragraph indicate that the CEMS qualifies for an annual RATA
frequency (see Figure 2 in appendix B to this part), the RATA may be
used to quality assure data for the entire current ozone season.
(G) If the results of a RATA performed according to the provisions
of this paragraph indicate that the CEMS qualifies for a semiannual
RATA frequency rather than an annual frequency, provided that the RATA
was completed on or after January 1 of the current calendar year, the
RATA may be used to quality assure data for the entire current ozone
season. However, if the RATA was performed in the fourth calendar
quarter of the previous year, the RATA may only be used to quality
assure data for a part of the current ozone season, from May 1 through
June 30. An additional RATA is then required by June 30 of the current
calendar year to quality assure the remainder of the data (from June 30
through September 30) for the current ozone season. If such an
additional RATA is required but is not completed by June 30 of the
current calendar year, data from the CEMS shall be considered invalid
as of the first unit or stack operating hour subsequent to June 30 of
the current calendar year and shall remain invalid until the required
RATA is performed and passed.
(H) Exceptions. (1) If the monitoring system passed a RATA on or
after January 1 of the previous year and the unit or stack on which the
monitor is located operated for less than 336 hours in the previous
ozone season, the owner or operator may have a grace period of up to
720 hours to perform a RATA. If the unit or stack operates for 720
hours or less in the current ozone season, the owner or operator of the
unit is exempt from the requirement to perform a RATA for that ozone
season and the owner or operator may submit quality assured data from
that monitor as long as all other required quality assurance tests are
passed. If the unit or stack operates for more than 720 hours in the
current ozone season, the owner or operator of the unit or stack shall
report substitute data using the missing data procedures under
paragraph (c)(7) of this section, starting with the 721st unit
operating hour and continuing until the successful completion of the
RATA.
(2) If a monitor does not qualify for a grace period under
paragraph (c)(2)(ii)(H)(1) of this section and if a required RATA has
not been completed prior to the start of the current ozone season,
follow the applicable procedures in paragraph (c)(3)(vi) of this
section.
(3) Quality assurance requirements within the ozone season. The
provisions of this paragraph apply to each ozone season. The owner or
operator shall, at a minimum, perform the following quality assurance
testing during the ozone season, i.e. in the time period extending from
May 1 through September 30 of each calendar year:
(i) Daily calibration error tests and (if applicable) interference
checks of each CEMS required by this subpart shall be performed in
accordance with sections 2.1.1 and 2.1.2 of appendix B to this part.
The applicable provisions in sections 2.1.3, 2.1.4 and 2.1.5 of
appendix B to this part, pertaining, respectively, to additional
calibration error tests and calibration adjustments, data validation,
and quality assurance of data with respect to daily assessments, shall
also apply.
(ii) For each gas monitor required by this subpart, linearity
checks shall be performed in the second and third calendar quarters, in
accordance with section 2.2.1 of appendix B to this part (see also
paragraph (c)(3)(vii) of this section). For the second calendar quarter
of the year, only unit or stack operating hours in the months of May
and June shall be included when determining whether the second calendar
quarter is a ``QA operating quarter'' (as defined in Sec. 72.2 of this
chapter). Data validation for these linearity checks shall be done in
accordance with sections 2.2.3(a) through (e) of appendix B to this
part. The grace period provision in section 2.2.4 of appendix B to this
part does not apply to these linearity checks. If the required
linearity check has not been completed by the end of the calendar
quarter, unless the conditional data validation provisions of
Sec. 75.20(b)(3) are applied, data from the CEMS are considered to be
invalid, beginning with the first unit or stack operating hour after
the end of the quarter and shall remain invalid until a linearity check
of the CEMS is performed and passed.
(iii) For each flow monitoring system required by this subpart,
flow-to-load ratio tests are required in the second and third calendar
quarters, in accordance with section 2.2.5 of appendix B to this part.
If the flow-to-load ratio test for the second calendar quarter is
failed, the owner or operator shall declare the flow monitor out-of-
control as of the first unit or stack operating hour following the
second calendar quarter and shall either implement Option 1 in section
2.2.5.1 of appendix B to this part or Option 2 in section 2.2.5.2 of
appendix B to this part. If the flow-to-load ratio test for the third
calendar quarter is failed, data from the flow monitor shall be
considered invalid at the beginning of the next ozone season unless,
prior to May 1 of the next calendar year, the owner or operator has
either successfully implemented Option 1 in section 2.2.5.1 of appendix
B to this part or Option 2 in section 2.2.5.2 of appendix B to this
part, or unless a flow RATA has been performed and passed in accordance
with paragraph (c)(2)(ii) of this section.
(iv) For each differential pressure-type flow monitor used to meet
the requirements of this subpart, quarterly leak checks are required in
the second and third calendar quarters, in accordance with section
2.2.2 of appendix B to this part. For the second calendar quarter of
the year, only unit or stack operating hours in the months of May and
June shall be included when determining whether the second calendar
quarter is a QA operating quarter (as defined in Sec. 72.2 of this
chapter). Data validation for quarterly flow monitor leak checks shall
be done in accordance with section 2.2.3(g) of appendix B to this part.
If the leak check for the third calendar quarter is failed and a
subsequent leak check is not passed by the end of the ozone season,
then data from the flow monitor shall be considered invalid at the
beginning of the next ozone season unless a leak
[[Page 28629]]
check is passed prior to May 1 of the next calendar year.
(v) A fuel flow-to-load ratio test in section 2.1.7 of appendix D
to this part shall be performed in the second and third calendar
quarters if, for a unit using a fuel flowmeter to determine heat input
under this subpart, the owner or operator has elected to use the fuel
flow-to-load ratio test to extend the deadline for the next fuel
flowmeter accuracy test. If a fuel flow-to-load ratio test is failed,
follow the applicable procedures and data validation provisions in
section 2.1.7.4 of appendix D to this part. If the fuel flow-to-load
ratio test for the third calendar quarter is failed, data from the fuel
flowmeter shall be considered invalid at the beginning of the next
ozone season unless the requirements of section 2.1.7.4 of appendix D
to this part have been fully met prior to May 1 of the next calendar
year.
(vi) If, at the start of the current ozone season (i.e., as of May
1 of the current calendar year), the linearity check or RATA required
under paragraph (c)(2)(i) or (c)(2)(ii) of this section has not been
performed for a particular monitor or monitoring system, and if, during
the previous ozone season, the unit or stack on which the monitoring
system is installed operated for 336 hours or more the owner or
operator shall invalidate all data from the CEMS until either:
(A) The required linearity check or RATA of the CEMS has been
performed and passed; or
(B) A ``probationary calibration error test'' of the CEMS is passed
in accordance with Sec. 75.20(b)(3). Note that a calibration error test
passed on April 30 may be used as the probationary calibration error
test, to ensure that emission data recorded by the CEMS at the
beginning of the ozone season will have a conditionally valid status.
Once the probationary calibration error test has been passed, the owner
or operator shall perform the required linearity check or RATA in
accordance with the conditional data validation provisions and within
the associated timelines in Sec. 75.20(b)(3), with the term
``diagnostic'' applying 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.
(vii) A RATA which is performed and passed during the second or
third quarter of the current calendar year may be used to quality
assure data in the next ozone season, provided that:
(A) The results of the RATA indicate that the CEMS qualifies for an
annual RATA frequency (see Figure 2 in appendix B to this part); and
(B) The CEMS is continuously operated and maintained, and daily
calibration error tests and (if applicable) interference checks of the
CEMS are performed in the time period extending from the end of the
current ozone season (October 1 of the current calendar year) through
April 30 of the next calendar year; and
(C) For a gas monitoring system, the linearity check requirement of
paragraph (c)(2)(i) of this section is met prior to May 1 of the next
calendar year.
(D) If conditions in paragraphs (c)(3)(vii)(A), (B) and, if
applicable, (c)(3)(vii)(C) of this section are met, then a RATA
completed and passed in the second or third calendar quarter of the
current year may be used to quality assure data for the next ozone
season, as follows:
(1) If the RATA is completed and passed in the second calendar
quarter of the current year, the RATA may be used to quality assure
data from the CEMS through June 30 of the next calendar year.
(2) If the RATA is completed and passed in the third calendar
quarter of the current year, the RATA may be used to quality assure
data from the CEMS through September 30 of the next calendar year.
(viii) If a linearity check performed to meet the requirement of
paragraph (c)(2)(i) of this section is completed and passed in the
second calendar quarter of the current year, provided that the date and
hour of completion of the test is within the first 168 unit or stack
operating hours of the current ozone season, the linearity check may be
used to satisfy both the requirement of paragraph (c)(2)(i) of this
section and to meet the second quarter linearity check requirement of
paragraph (c)(3)(ii) of this section.
(ix) If, for any required CEMS, diagnostic linearity checks or
RATAs other than those required by this section are performed during
the ozone season, use the applicable data validation procedures in
section 2.2.3 (for linearity checks) or 2.3.2 (for RATAs) of appendix B
to this part.
(x) If any required CEMS is recertified within the ozone season,
use the data validation provisions in Sec. 75.20(b)(3) and paragraphs
(c)(3)(xi) and (c)(3)(xii) of this section.
(xi) If, at the end of the second quarter of any calendar year, a
required quality assurance, diagnostic or recertification test of a
monitoring system has not been completed, and if data contained in the
quarterly report are conditionally valid pending the results of test(s)
to be completed in a subsequent quarter, the owner or operator shall
indicate this by means of a suitable conditionally valid data flag in
the electronic quarterly report for the second calendar quarter. The
owner or operator shall resubmit the report for the second quarter if
the required quality assurance, diagnostic or recertification test is
subsequently failed. In the resubmitted report, the owner or operator
shall use the appropriate missing data routine in Sec. 75.31 or
Sec. 75.33 to replace with substitute data each hour of conditionally
valid data that was invalidated by the failed quality assurance,
diagnostic or recertification test. Alternatively, if any required
quality assurance, diagnostic or recertification test is not completed
by the end of the second calendar quarter but is completed no later
than 30 days after the end of that quarter (i.e., prior to the deadline
for submitting the quarterly report under Sec. 75.73), the test data
and results may be submitted with the second quarter report even though
the test date(s) are from the third calendar quarter. In such
instances, if the quality assurance, diagnostic or recertification
test(s) are passed in accordance with the provisions of
Sec. 75.20(b)(3), conditionally valid data may be reported as quality-
assured, in lieu of reporting a conditional data flag. If the tests are
failed and if conditionally valid data are replaced, as appropriate,
with substitute data, then neither the reporting of a conditional data
flag nor resubmission is required.
(xii) If, at the end of the third quarter of any calendar year, a
required quality assurance, diagnostic or recertification test of a
monitoring system has not been completed, and if data contained in the
quarterly report are conditionally valid pending the results of test(s)
to be completed, the owner or operator shall do one of the following:
(A) If the results of the required tests are not available within
30 days of the end of the third calendar quarter and cannot be
submitted with the quarterly report for the third calendar quarter,
then the test results are considered to be missing and the owner or
operator shall use the appropriate missing data routine in Sec. 75.31
or Sec. 75.33 to replace with substitute data each hour of
conditionally valid data in the third quarter report. In addition, if
the data in the second quarterly report were flagged as conditionally
valid at the end of the quarter, pending the results of the same
missing tests, the owner or operator shall resubmit the report for the
second quarter and shall use the appropriate missing data routine in
Sec. 75.31 or Sec. 75.33 to replace with substitute data
[[Page 28630]]
each hour of conditionally valid data associated with the missing
quality assurance, diagnostic or recertification tests; or
(B) If the required quality assurance, diagnostic or
recertification tests are completed no later than 30 days after the end
of the third calendar quarter, the test data and results may be
submitted with the third quarter report even though the test date(s)
are from the fourth calendar quarter. In this instance, if the required
tests are passed in accordance with the provisions of Sec. 75.20(b)(3),
all conditionally valid data associated with the tests shall be
reported as quality assured. If the tests are failed, the owner or
operator shall use the appropriate missing data routine in Sec. 75.31
or Sec. 75.33 to replace with substitute data each hour of
conditionally valid data associated with the failed test(s). In
addition, if the data in the second quarterly report were flagged as
conditionally valid at the end of the quarter, pending the results of
the same failed test(s), the owner or operator shall resubmit the
report for the second quarter and shall use the appropriate missing
data routine in Sec. 75.31 or Sec. 75.33 to replace with substitute
data each hour of conditionally valid data associated with the failed
test(s).
(4) The owner or operator of a unit using the procedures in
appendix D of this part to determine heat input is required to maintain
fuel flowmeters only during the ozone season, except that for purposes
of determining the deadline for the next periodic quality assurance
test on the fuel flowmeter, the owner or operator shall include all
fuel flowmeter QA operating quarters (as defined in Sec. 72.2) for the
entire calendar year, not just fuel flowmeter QA operating quarters in
the ozone season. For each calendar year, the owner or operator shall
record, for each fuel flowmeter, the number of fuel flowmeter QA
operating quarters.
(5) The owner or operator of a unit using the procedures in
appendix D of this part to determine heat input is only required to
sample fuel for the purposes of determining density and GCV during the
ozone season, except that:
(i) The owner or operator of a unit that performs sampling from the
fuel storage tank upon delivery must sample the tank between the date
and hour of the most recent delivery before the first date and hour
that the unit operates in the ozone season and the first date and hour
that the unit operates in the ozone season.
(ii) The owner or operator of a unit that performs sampling upon
delivery from the delivery vehicle must ensure that all shipments
received during the calendar year are sampled.
(iii) The owner or operator of a unit that performs sampling on
each day the unit combusts fuel or that performs fuel sampling
continuously must sample the fuel starting on the first day the unit
operates during the ozone season. The owner or operator then shall use
that sampled value for all hours of combustion during the first day of
unit operation, continuing until the date and hour of the next sample.
(6) The owner or operator shall, in accordance with Sec. 75.73,
record and report the hourly data required by this subpart and shall
record and report the results of all required quality assurance tests,
as follows:
(i) All hourly emission data for the period of time from May 1
through September 30 of each calendar year shall be recorded and
reported. For missing data purposes, only the data recorded in the time
period from May 1 through September 30 shall be considered quality-
assured;
(ii) The results of all daily calibration error tests and flow
monitor interference checks performed in the time period from May 1
through September 30 shall be recorded and reported;
(iii) For the time periods described in paragraphs (c)(2)(i)(C) and
(c)(2)(ii)(E) of this section, hourly emission data and the results of
all daily calibration error tests and flow monitor interference checks
shall be recorded. The results of all daily calibration error tests and
flow monitor interference checks performed in the time period from
April 1 through April 30 shall be reported. The owner or operator may
also report the hourly emission data and unit operating data recorded
in the time period from April 1 through April 30. However, only the
emission data recorded in the time period from May 1 through September
30 shall be used for NOX mass compliance determination;
(iv) The results of all required quality assurance tests (RATAs,
linearity checks, flow-to-load ratio tests and leak checks) performed
during the ozone season shall be reported in the appropriate ozone
season quarterly report; and
(v) The results of RATAs (and any other quality assurance test(s)
required under paragraph (c)(2) or (c)(3) of this section) which affect
data validation for the current ozone season, but which were performed
outside the ozone season (i.e., between October 1 of the previous
calendar year and April 30 of the current calendar year), shall be
reported in the quarterly report for the second quarter of the current
calendar year.
(7) The owner or operator shall use only quality-assured data from
within ozone seasons in the substitute data procedures under subpart D
of this part and section 2.4.2 of appendix D to this part.
(i) The lookback periods (e.g., 2160 quality-assured monitor
operating hours for a NOX-diluent continuous emission
monitoring system, a NOX concentration monitoring system, or
a flow monitoring system) used to calculate missing data must include
only quality-assured data from periods within ozone seasons.
(ii) The missing data procedures of Secs. 75.31 through 75.33 shall
be used, with two exceptions. First, when the NOX emission
rate or NOX concentration of the unit was consistently lower
in the previous ozone season because the unit combusted a fuel that
produces less NOX than the fuel currently being combusted;
and second, when the unit's add-on emission controls are not working
properly, as shown by the parametric data recorded under paragraph
(c)(8) of this section. In those two cases, the owner or operator shall
substitute the maximum potential NOX emission rate, as
defined in Sec. 72.2 of this chapter, from a NOX-diluent
continuous emission monitoring system, or the maximum potential
concentration of NOX, as defined in section 2.1.2.1 of
appendix A to this part, from a NOX concentration monitoring
system. The maximum potential value used shall be for the fuel
currently being combusted. The length of time for which the owner or
operator shall substitute these maximum potential values for each hour
of missing NOX operator shall substitute these maximum
potential value for each hour of missing NOX data, shall be
as follows:
(A) For a unit that changed fuels, substitute the maximum potential
values until the first hour when the unit combusts a fuel that produces
the same or less NOX than the fuel combusted in the previous
ozone season; and
(B) For a unit with add-on emission controls that are not working
properly, substitute the maximum potential values until the first hour
in which the add-on emission controls are documented to be operating
properly, according to paragraph (c)(8) of this section.
* * * * *
54. Appendix A to part 75 is amended by--
a. Revising sections 2 through 2.1.1.4;
b. Adding section 2.1.1.5;
c. Revising sections 2.1.2 through 2.1.2.4;
d. Adding section 2.1.2.5;
[[Page 28631]]
e. Revising section 2.1.3;
f. Adding sections 2.1.3.1 through 2.1.3.3;
g. Revising section 2.1.4;
h. Adding sections 2.1.4.1 through 2.1.6;
i. Removing and reserving section 2.2 and removing sections 2.2.1
through 2.2.2.2 to read as follows:
Appendix A to Part 75--Specifications and Test Procedures
* * * * *
2. Equipment Specifications
2.1 Instrument Span and Range
In implementing sections 2.1.1 through 2.1.6 of this appendix,
set the measurement range for each parameter (SO2,
NOX, CO2, O2, or flow rate) high
enough to prevent full-scale exceedances from occurring, yet low
enough to ensure good measurement accuracy and to maintain a high
signal-to-noise ratio. To meet these objectives, select the range
such that the readings obtained during typical unit operation are
kept, to the extent practicable, between 20.0 and 80.0 percent of
full-scale range of the instrument. These guidelines do not apply
to: (1) SO2 readings obtained during the combustion of
very low sulfur fuel (as defined in Sec. 72.2 of this chapter); (2)
SO2 or NOX readings recorded on the high
measurement range, for units with SO2 or NOX
emission controls and two span values; or (3) SO2 or
NOX readings less than 20.0 percent of full-scale on the
low measurement range for a dual span unit with SO2 or
NOX emission controls, provided that the readings occur
during periods of high control device efficiency.
2.1.1 SO2 Pollutant Concentration Monitors
Determine, as indicated in this section 2, the span value(s) and
range(s) for an SO2 pollutant concentration monitor so
that all potential and expected concentrations can be accurately
measured and recorded. Note that if a unit exclusively combusts
fuels that are very low sulfur fuels (as defined in Sec. 72.2 of
this chapter), the SO2 monitor span requirements in
Sec. 75.11(e)(3)(iv) apply in lieu of the requirements of this
section.
2.1.1.1 Maximum Potential Concentration
(a) Make an initial determination of the maximum potential
concentration (MPC) of SO2 by using Equation A-1a or A-
1b. Base the MPC calculation on the maximum percent sulfur and the
minimum gross calorific value (GCV) for the highest-sulfur fuel to
be burned. The maximum sulfur content and minimum GCV shall be
determined from all available fuel sampling and analysis data for
that fuel from the previous 12 months (minimum), excluding clearly
anomalous fuel sampling values. If the designated representative
certifies that the highest-sulfur fuel is never burned alone in the
unit during normal operation but is always blended or co-fired with
other fuel(s), the MPC may be calculated using a best estimate of
the highest sulfur content and lowest gross calorific value expected
for the blend or fuel mixture and inserting these values into
Equation A-1a or A-1b. Derive the best estimate of the highest
percent sulfur and lowest GCV for a blend or fuel mixture from
weighted-average values based upon the historical composition of the
blend or mixture in the previous 12 (or more) months. If
insufficient representative fuel sampling data are available to
determine the maximum sulfur content and minimum GCV, use values
from contract(s) for the fuel(s) that will be combusted by the unit
in the MPC calculation.
(b) Alternatively, if a certified SO2 CEMS is already
installed, the owner or operator may make the initial MPC
determination based upon quality assured historical data recorded by
the CEMS. If this option is chosen, the MPC shall be the maximum
SO2 concentration observed during the previous 720 (or
more) quality assured monitor operating hours when combusting the
highest-sulfur fuel (or highest-sulfur blend if fuels are always
blended or co-fired) that is to be combusted in the unit or units
monitored by the SO2 monitor. For units with
SO2 emission controls, the certified SO2
monitor used to determine the MPC must be located at or before the
control device inlet. Report the MPC and the method of determination
in the monitoring plan required under Sec. 75.53.
(c) When performing fuel sampling to determine the MPC, use ASTM
Methods: ASTM D3177-89, ``Standard Test Methods for Total Sulfur in
the Analysis Sample of Coal and Coke''; ASTM D4239-85, ``Standard
Test Methods for Sulfur in the Analysis Sample of Coal and Coke
Using High Temperature Tube Furnace Combustion Methods''; ASTM
D4294-90, ``Standard Test Method for Sulfur in Petroleum Products by
Energy-Dispersive X-Ray Fluorescence Spectroscopy''; ASTM D1552-90,
``Standard Test Method for Sulfur in Petroleum Products (High
Temperature Method)''; ASTM D129-91, ``Standard Test Method for
Sulfur in Petroleum Products (General Bomb Method)''; ASTM D2622-92,
``Standard Test Method for Sulfur in Petroleum Products by X-Ray
Spectrometry'' for sulfur content of solid or liquid fuels; ASTM
D3176-89, ``Standard Practice for Ultimate Analysis of Coal and
Coke''; ASTM D240-87 (Reapproved 1991), ``Standard Test Method for
Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb
Calorimeter''; or ASTM D2015-91, ``Standard Test Method for Gross
Calorific Value of Coal and Coke by the Adiabatic Bomb Calorimeter''
for GCV (incorporated by reference under Sec. 75.6).
[GRAPHIC] [TIFF OMITTED] TR26MY99.000
or
[GRAPHIC] [TIFF OMITTED] TR26MY99.001
Where,
MPC = Maximum potential concentration (ppm, wet basis). (To convert
to dry basis, divide the MPC by 0.9.)
MEC = Maximum expected concentration (ppm, wet basis). (To convert
to dry basis, divide the MEC by 0.9).
%S = Maximum sulfur content of fuel to be fired, wet basis, weight
percent, as determined by ASTM D3177-89, ASTM D4239-85, ASTM D4294-
90, ASTM D1552-90, ASTM D129-91, or ASTM D2622-92 for solid or
liquid fuels (incorporated by reference under Sec. 75.6).
%O2w = Minimum oxygen concentration, percent wet basis,
under typical operating conditions.
%CO2w = Maximum carbon dioxide concentration, percent wet
basis, under typical operating conditions.
11.32 x 106 = Oxygen-based conversion factor in Btu/lb
(ppm)/%.
66.93 x 106 = Carbon dioxide-based conversion factor in
Btu/lb (ppm)/%.
Note: All percent values to be inserted in the equations of this
section are to be expressed as a percentage, not a fractional value
(e.g., 3, not .03).
2.1.1.2 Maximum Expected Concentration
(a) Make an initial determination of the maximum expected
concentration (MEC) of SO2 whenever: (a) SO2
emission controls are used; or (b) both high-sulfur and low-sulfur
fuels (e.g., high-sulfur coal and low-sulfur coal or different
grades of fuel oil) or high-sulfur and low-sulfur fuel blends are
combusted as primary or backup fuels in a unit without
SO2 emission controls. For units with SO2
emission controls, use Equation A-2 to make the initial MEC
determination. When high-sulfur and low-sulfur fuels or blends are
burned as primary or backup fuels in a unit without SO2
controls, use Equation A-1a or A-1b to calculate the initial MEC
value for each fuel or blend, except for: (1) the highest-sulfur
fuel or blend (for which the MPC was previously calculated in
section 2.1.1.1 of this appendix); (2) fuels or blends that are very
low sulfur fuels (as defined in Sec. 72.2 of this chapter); or (3)
fuels or blends that are used only for unit startup.
(b) For each MEC determination, substitute into Equation A-1a or
A-1b the highest sulfur content and minimum GCV value for
[[Page 28632]]
that fuel or blend, based upon all available fuel sampling and
analysis results from the previous 12 months (or more), or, if fuel
sampling data are unavailable, based upon fuel contract(s).
(c) Alternatively, if a certified SO2 CEMS is already
installed, the owner or operator may make the initial MEC
determination(s) based upon historical monitoring data. If this
option is chosen for a unit with SO2 emission controls,
the MEC shall be the maximum SO2 concentration measured
downstream of the control device outlet by the CEMS over the
previous 720 (or more) quality assured monitor operating hours with
the unit and the control device both operating normally. For units
that burn high- and low-sulfur fuels or blends as primary and backup
fuels and have no SO2 emission controls, the MEC for each
fuel shall be the maximum SO2 concentration measured by
the CEMS over the previous 720 (or more) quality assured monitor
operating hours in which that fuel or blend was the only fuel being
burned in the unit.
[GRAPHIC] [TIFF OMITTED] TR26MY99.002
Where:
MEC = Maximum expected concentration (ppm).
MPC = Maximum potential concentration (ppm), as determined by Eq. A-
1a or A-1b.
RE = Expected average design removal efficiency of control equipment
(%).
2.1.1.3 Span Value(s) and Range(s)
Determine the high span value and the high full-scale range of
the SO2 monitor as follows. (Note: For purposes of this
part, the high span and range refer, respectively, either to the
span and range of a single span unit or to the high span and range
of a dual span unit.) The high span value shall be obtained by
multiplying the MPC by a factor no less than 1.00 and no greater
than 1.25. Round the span value upward to the next highest multiple
of 100 ppm. If the SO2 span concentration is
500 ppm, the span value may be rounded upward to the next
highest multiple of 10 ppm, instead of the nearest 100 ppm. The high
span value shall be used to determine concentrations of the
calibration gases required for daily calibration error checks and
linearity tests. Select the full-scale range of the instrument to be
consistent with section 2.1 of this appendix and to be greater than
or equal to the span value. Report the full-scale range setting and
calculations of the MPC and span in the monitoring plan for the
unit. Note that for certain applications, a second (low)
SO2 span and range may be required (see section 2.1.1.4
of this appendix). If an existing state, local, or federal
requirement for span of an SO2 pollutant concentration
monitor requires a span lower than that required by this section or
by section 2.1.1.4 of this appendix, the state, local, or federal
span value may be used if a satisfactory explanation is included in
the monitoring plan, unless span and/or range adjustments become
necessary in accordance with section 2.1.1.5 of this appendix. Span
values higher than those required by either this section or section
2.1.1.4 of this appendix must be approved by the Administrator.
2.1.1.4 Dual Span and Range Requirements
For most units, the high span value based on the MPC, as
determined under section 2.1.1.3 of this appendix will suffice to
measure and record SO2 concentrations (unless span and/or
range adjustments become necessary in accordance with section
2.1.1.5 of this appendix). In some instances, however, a second
(low) span value based on the MEC may be required to ensure accurate
measurement of all possible or expected SO2
concentrations. To determine whether two SO2 span values
are required, proceed as follows:
(a) For units with SO2 emission controls, compare the
MEC from section 2.1.1.2 of this appendix to the high full-scale
range value from section 2.1.1.3 of this appendix. If the MEC is
20.0 percent of the high range value, then the high span
value and range determined under section 2.1.1.3 of this appendix
are sufficient. If the MEC is <20.0 percent of the high range value,
then a second (low) span value is required.
(b) For units that combust high- and low-sulfur primary and
backup fuels (or blends) and have no SO2 controls,
compare the high range value from section 2.1.1.3 of this appendix
(for the highest-sulfur fuel or blend) to the MEC value for each of
the other fuels or blends, as determined under section 2.1.1.2 of
this appendix. If all of the MEC values are 20.0 percent
of the high range value, the high span and range determined under
section 2.1.1.3 of this appendix are sufficient, regardless of which
fuel or blend is burned in the unit. If any MEC value is <20.0
percent of the high range value, then a second (low) span value must
be used when that fuel or blend is combusted.
(c) When two SO2 spans are required, the owner or
operator may either use a single SO2 analyzer with a dual
range (i.e., low- and high-scales) or two separate SO2
analyzers connected to a common sample probe and sample interface.
For units with SO2 emission controls, the owner or
operator may use a low range analyzer and a default high range
value, as described in paragraph (f) of this section, in lieu of
maintaining and quality assuring a high-scale range. Other monitor
configurations are subject to the approval of the Administrator.
(d) The owner or operator shall designate the monitoring systems
and components in the monitoring plan under Sec. 75.53 as follows:
designate the low and high monitor ranges as separate SO2
components of a single, primary SO2 monitoring system; or
designate the low and high monitor ranges as the SO2
components of two separate, primary SO2 monitoring
systems; or designate the normal monitor range as a primary
monitoring system and the other monitor range as a non-redundant
backup monitoring system; or, when a single, dual-range
SO2 analyzer is used, designate the low and high ranges
as a single SO2 component of a primary SO2
monitoring system (if this option is selected, use a special dual-
range component type code, as specified by the Administrator, to
satisfy the requirements of Sec. 75.53(e)(1)(iv)(D)); or, for units
with SO2 controls, if the default high range value is
used, designate the low range analyzer as the SO2
component of a primary SO2 monitoring system. Do not
designate the default high range as a monitoring system or
component. Other component and system designations are subject to
approval by the Administrator. Note that the component and system
designations for redundant backup monitoring systems shall be the
same as for primary monitoring systems.
(e) Each monitoring system designated as primary or redundant
backup shall meet the initial certification and quality assurance
requirements for primary monitoring systems in Sec. 75.20(c) or
Sec. 75.20(d)(1), as applicable, and appendices A and B to this
part, with one exception: relative accuracy test audits (RATAs) are
required only on the normal range (for units with SO2
emission controls, the low range is considered normal). Each
monitoring system designated as a non-redundant backup shall meet
the applicable quality assurance requirements in Sec. 75.20(d)(2).
(f) For dual span units with SO2 emission controls,
the owner or operator may, as an alternative to maintaining and
quality assuring a high monitor range, use a default high range
value. If this option is chosen, the owner or operator shall report
a default SO2 concentration of 200 percent of the MPC for
each unit operating hour in which the full-scale of the low range
SO2 analyzer is exceeded.
(g) The high span value and range shall be determined in
accordance with section 2.1.1.3 of this appendix. The low span value
shall be obtained by multiplying the MEC by a factor no less than
1.00 and no greater than 1.25, and rounding the result upward to the
next highest multiple of 10 ppm (or 100 ppm, as appropriate). For
units that burn high- and low-sulfur primary and backup fuels or
blends and have no SO2 emission controls, select, as the
basis for calculating the appropriate low span value and range, the
fuel-specific MEC value closest to 20.0 percent of the high full-
scale range value (from paragraph (b) of this section). The low
range must be greater than or equal to the low span value, and the
required calibration gases must be selected based on the low span
value. For units with two SO2 spans, use the low range
whenever the SO2 concentrations are expected to be
consistently below 20.0 percent of the high full-scale range value,
i.e., when the MEC of the fuel or blend being combusted is less than
20.0 percent of the high full-scale range value. When the full-scale
of the low range is exceeded, the high range shall be used to
measure and record the SO2 concentrations; or, if
applicable, the default high range value in paragraph (f) of this
section shall be reported for each hour of the full-scale
exceedance.
2.1.1.5 Adjustment of Span and Range
For each affected unit or common stack, the owner or operator
shall make a periodic evaluation of the MPC, MEC, span, and range
values for each SO2 monitor (at a minimum, an annual
evaluation is required) and shall make any necessary span and range
adjustments, with corresponding monitoring plan updates, as
described in paragraphs (a) and (b) of this section. Span and range
[[Page 28633]]
adjustments may be required, for example, as a result of changes in
the fuel supply, changes in the manner of operation of the unit, or
installation or removal of emission controls. In implementing the
provisions in paragraphs (a) and (b) of this section, SO2
data recorded during short-term, non-representative process
operating conditions (e.g., a trial burn of a different type of
fuel) shall be excluded from consideration. The owner or operator
shall keep the results of the most recent span and range evaluation
on-site, in a format suitable for inspection. Make each required
span or range adjustment no later than 45 days after the end of the
quarter in which the need to adjust the span or range is identified,
except that up to 90 days after the end of that quarter may be taken
to implement a span adjustment if the calibration gases currently
being used for daily calibration error tests and linearity checks
are unsuitable for use with the new span value.
(a) If the fuel supply, the composition of the fuel blend(s),
the emission controls, or the manner of operation change such that
the maximum expected or potential concentration changes
significantly, adjust the span and range setting to assure the
continued accuracy of the monitoring system. A ``significant''
change in the MPC or MEC means that the guidelines in section 2.1 of
this appendix can no longer be met, as determined by either a
periodic evaluation by the owner or operator or from the results of
an audit by the Administrator. The owner or operator should evaluate
whether any planned changes in operation of the unit may affect the
concentration of emissions being emitted from the unit or stack and
should plan any necessary span and range changes needed to account
for these changes, so that they are made in as timely a manner as
practicable to coordinate with the operational changes. Determine
the adjusted span(s) using the procedures in sections 2.1.1.3 and
2.1.1.4 of this appendix (as applicable). Select the full-scale
range(s) of the instrument to be greater than or equal to the new
span value(s) and to be consistent with the guidelines of section
2.1 of this appendix.
(b) Whenever a full-scale range is exceeded during a quarter and
the exceedance is not caused by a monitor out-of-control period,
proceed as follows:
(1) For exceedances of the high range, report 200.0 percent of
the current full-scale range as the hourly SO2
concentration for each hour of the full-scale exceedance and make
appropriate adjustments to the MPC, span, and range to prevent
future full-scale exceedances.
(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 is not out-of-control or out-of-
service for any reason. However, if 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).
(c) Whenever changes are made to the MPC, MEC, full-scale range,
or span value of the SO2 monitor, as described in
paragraphs (a) or (b) of this section, record and report (as
applicable) the new full-scale range setting, the new MPC or MEC and
calculations of the adjusted span value in an updated monitoring
plan. The monitoring plan update shall be made in the quarter in
which the changes become effective. In addition, record and report
the adjusted span as part of the records for the daily calibration
error test and linearity check specified by appendix B to this part.
Whenever the span value is adjusted, use calibration gas
concentrations that meet the requirements of section 5.1 of this
appendix, based on the adjusted span value. When a span adjustment
is so significant that the calibration gases currently being used
for daily calibration error tests and linearity checks are
unsuitable for use with the new span value, then a diagnostic
linearity test using the new calibration gases must be performed and
passed. Data from the monitor are considered invalid from the hour
in which the span is adjusted until the required linearity check is
passed in accordance with section 6.2 of this appendix.
2.1.2 NOX Pollutant Concentration Monitors
Determine, as indicated in section 2.1.2.1, the span and range
value(s) for the NOX pollutant concentration monitor so
that all expected NOX concentrations can be determined
and recorded accurately.
2.1.2.1 Maximum Potential Concentration
(a) The maximum potential concentration (MPC) of NOX
for each affected unit shall be based upon whichever fuel or blend
combusted in the unit produces the highest level of NOX
emissions. Make an initial determination of the MPC using the
appropriate option as follows:
Option 1: Use 800 ppm for coal-fired and 400 ppm for oil- or
gas-fired units as the maximum potential concentration of
NOX (if an MPC of 1600 ppm for coal-fired units or 480
ppm for oil- or gas-fired units was previously selected under this
part, that value may still be used, provided that the guidelines of
section 2.1 of this appendix are met);
Option 2: Use the specific values based on boiler type and fuel
combusted, listed in Table 2-1 or Table 2-2;
Option 3: Use NOX emission test results; or
Option 4: Use historical CEM data over the previous 720 (or
more) unit operating hours when combusting the fuel or blend with
the highest NOX emission rate.
(b) For the purpose of providing substitute data during
NOX missing data periods in accordance with Secs. 75.31
and 75.33 and as required elsewhere under this part, the owner or
operator shall also calculate the maximum potential NOX
emission rate (MER), in lb/mmBtu, by substituting the MPC for
NOX in conjunction with the minimum expected
CO2 or maximum O2 concentration (under all
unit operating conditions except for unit startup, shutdown, and
upsets) and the appropriate F-factor into the applicable equation in
appendix F to this part. The diluent cap value of 5.0 percent
CO2 (or 14.0 percent O2) for boilers or 1.0
percent CO2 (or 19.0 percent O2) for
combustion turbines may be used in the NOX MER
calculation.
(c) Report the method of determining the initial MPC and the
calculation of the maximum potential NOX emission rate in
the monitoring plan for the unit.
(d) For units with add-on NOX controls (whether or
not the unit is equipped with low-NOX burner technology),
NOX emission testing may only be used to determine the
MPC if testing can be performed either upstream of the add-on
controls or during a time or season when the add-on controls are not
in operation. If NOX emission testing is performed, use
the following guidelines. Use Method 7E from appendix A to part 60
of this chapter to measure total NOX concentration.
(Note: Method 20 from appendix A to part 60 may be used for gas
turbines, instead of Method 7E.) Operate the unit, or group of units
sharing a common stack, at the minimum safe and stable load, the
normal load, and the maximum load. If the normal load and maximum
load are identical, an intermediate level need not be tested.
Operate at the highest excess O2 level expected under
normal operating conditions. Make at least three runs of 20 minutes
(minimum) duration with three traverse points per run at each
operating condition. Select the highest point NOX
concentration from all test runs as the MPC for NOX.
(e) If historical CEM data are used to determine the MPC, the
data must, for uncontrolled units or units equipped with low-
NOX burner technology and no other NOX
controls, represent a minimum of 720 quality assured monitor
operating hours, obtained under various operating conditions
including the minimum safe and stable load, normal load (including
periods of high excess air at normal load), and maximum load. For a
unit with add-on NOX controls (whether or not the unit is
equipped with low-NOX burner technology), historical CEM
data may only be used to determine the MPC if the 720 quality
assured monitor operating hours of CEM data are collected upstream
of the add-on controls or if the 720 hours of data include periods
when the add-on controls are not in operation. The highest hourly
NOX concentration in ppm shall be the MPC.
[[Page 28634]]
Table 2-1.--Maximum Potential Concentration for NOX--Coal-Fired Units
------------------------------------------------------------------------
Maximum
potential
Unit type concentration
for NOX (ppm)
------------------------------------------------------------------------
Tangentially-fired dry bottom and fluidized bed......... 460
Wall-fired dry bottom, turbo-fired dry bottom, stokers.. 675
Roof-fired (vertically-fired) dry bottom, cell burners, 975
arch-fired.............................................
Cyclone, wall-fired wet bottom, wet bottom turbo-fired.. 1200
Others.................................................. (\1\)
------------------------------------------------------------------------
\1\ As approved by the Administrator.
Table 2-2.--Maximum Potential Concentration for NOX--Gas-and Oil-Fired
Units
------------------------------------------------------------------------
Maximum
potential
Unit type concentration
for NOX (ppm)
------------------------------------------------------------------------
Tangentially-fired dry bottom........................... 380
Wall-fired dry bottom................................... 600
Roof-fired (vertically-fired) dry bottom, arch-fired.... 550
Existing combustion turbine or combined cycle turbine... 200
New stationary gas turbine/combustion turbine........... 50
Others.................................................. (\1\)
------------------------------------------------------------------------
\1\ As approved by the Administrator
2.1.2.2 Maximum Expected Concentration
(a) Make an initial determination of the maximum expected
concentration (MEC) of NOX during normal operation for
affected units with add-on NOX controls of any kind
(e.g., steam injection, water injection, SCR, or SNCR). Determine a
separate MEC value for each type of fuel (or blend) combusted in the
unit, except for fuels that are only used for unit startup and/or
flame stabilization. Calculate the MEC of NOX using
Equation A-2, if applicable, inserting the maximum potential
concentration, as determined using the procedures in section 2.1.2.1
of this appendix. Where Equation A-2 is not applicable, set the MEC
either by: (1) measuring the NOX concentration using the
testing procedures in this section; or (2) using historical CEM data
over the previous 720 (or more) quality assured monitor operating
hours. Include in the monitoring plan for the unit each MEC value
and the method by which the MEC was determined.
(b) If NOX emission testing is used to determine the
MEC value(s), the MEC for each type of fuel (or blend) shall be
based upon testing at minimum load, normal load, and maximum load.
At least three tests of 20 minutes (minimum) duration, using at
least three traverse points, shall be performed at each load, using
Method 7E from appendix A to part 60 of this chapter (Note: Method
20 from appendix A to part 60 may be used for gas turbines instead
of Method 7E). The test must be performed at a time when all
NOX control devices and methods used to reduce
NOX emissions are operating properly. The testing shall
be conducted downstream of all NOX controls. The highest
point NOX concentration (e.g., the highest one-minute
average) recorded during any of the test runs shall be the MEC.
(c)If historical CEM data are used to determine the MEC
value(s), the MEC for each type of fuel shall be based upon 720 (or
more) hours of quality assured data representing the entire load
range under stable operating conditions. The data base for the MEC
shall not include any CEM data recorded during unit startup,
shutdown, or malfunction or during any NOX control device
malfunctions or outages. All NOX control devices and
methods used to reduce NOX emissions must be operating
properly during each hour. The CEM data shall be collected
downstream of all NOX controls. For each type of fuel,
the highest of the 720 (or more) quality assured hourly average
NOX concentrations recorded by the CEMS shall be the MEC.
2.1.2.3 Span Value(s) and Range(s)
(a) Determine the high span value of the NOX monitor
as follows. The high span value shall be obtained by multiplying the
MPC by a factor no less than 1.00 and no greater than 1.25. Round
the span value upward to the next highest multiple of 100 ppm. If
the NOX span concentration is 500 ppm, the
span value may be rounded upward to the next highest multiple of 10
ppm, rather than 100 ppm. The high span value shall be used to
determine the concentrations of the calibration gases required for
daily calibration error checks and linearity tests. Note that for
certain applications, a second (low) NOX span and range
may be required (see section 2.1.2.4 of this appendix).
(b) If an existing State, local, or federal requirement for span
of a NOX pollutant concentration monitor requires a span
lower than that required by this section or by section 2.1.2.4 of
this appendix, the State, local, or federal span value may be used,
where a satisfactory explanation is included in the monitoring plan,
unless span and/or range adjustments become necessary in accordance
with section 2.1.2.5 of this appendix. Span values higher than
required by this section or by section 2.1.2.4 of this appendix must
be approved by the Administrator.
(c) Select the full-scale range of the instrument to be
consistent with section 2.1 of this appendix and to be greater than
or equal to the high span value. Include the full-scale range
setting and calculations of the MPC and span in the monitoring plan
for the unit.
2.1.2.4 Dual Span and Range Requirements
For most units, the high span value based on the MPC, as
determined under section 2.1.2.3 of this appendix will suffice to
measure and record NOX concentrations (unless span and/or
range adjustments must be made in accordance with section 2.1.2.5 of
this appendix). In some instances, however, a second (low) span
value based on the MEC may be required to ensure accurate
measurement of all expected and potential NOX
concentrations. To determine whether two NOX spans are
required, proceed as follows:
(a) Compare the MEC value(s) determined in section 2.1.2.2 of
this appendix to the high full-scale range value determined in
section 2.1.2.3 of this appendix. If the MEC values for all fuels
(or blends) are 20.0 percent of the high range value, the
high span and range values determined under section 2.1.2.3 of this
appendix are sufficient, irrespective of which fuel or blend is
combusted in the unit. If any of the MEC values is <20.0 percent of
the high range value, two spans (low and high) are required, one
based on the MPC and the other based on the MEC.
(b) When two NOX spans are required, the owner or
operator may either use a single NOX analyzer with a dual
range (low-and high-scales) or two separate NOX analyzers
connected to a common sample probe and sample interface. For units
with add-on NOX emission controls (i.e., steam injection,
water injection, SCR, or SNCR), the owner or operator may use a low
range analyzer and
[[Page 28635]]
a ``default high range value,'' as described in paragraph 2.1.2.4(e)
of this section, in lieu of maintaining and quality assuring a high-
scale range. Other monitor configurations are subject to the
approval of the Administrator.
(c) The owner or operator shall designate the monitoring systems
and components in the monitoring plan under Sec. 75.53 as follows:
designate the low and high ranges as separate NOX
components of a single, primary NOX monitoring system; or
designate the low and high ranges as the NOX components
of two separate, primary NOX monitoring systems; or
designate the normal range as a primary monitoring system and the
other range as a non-redundant backup monitoring system; or, when a
single, dual-range NOX analyzer is used, designate the
low and high ranges as a single NOX component of a
primary NOX monitoring system (if this option is
selected, use a special dual-range component type code, as specified
by the Administrator, to satisfy the requirements of
Sec. 75.53(e)(1)(iv)(D)); or, for units with add-on NOX
controls, if the default high range value is used, designate the low
range analyzer as the NOX component of the primary
NOX monitoring system. Do not designate the default high
range as a monitoring system or component. Other component and
system designations are subject to approval by the Administrator.
Note that the component and system designations for redundant backup
monitoring systems shall be the same as for primary monitoring
systems.
(d) Each monitoring system designated as primary or redundant
backup shall meet the initial certification and quality assurance
requirements in Sec. 75.20(c) (for primary monitoring systems), in
Sec. 75.20(d)(1) (for redundant backup monitoring systems) and
appendices A and B to this part, with one exception: relative
accuracy test audits (RATAs) are required only on the normal range
(for dual span units with add-on NOX emission controls,
the low range is considered normal). Each monitoring system
designated as non-redundant backup shall meet the applicable quality
assurance requirements in Sec. 75.20(d)(2).
(e) For dual span units with add-on NOX emission
controls (e.g., steam injection, water injection, SCR, or SNCR), the
owner or operator may, as an alternative to maintaining and quality
assuring a high monitor range, use a default high range value. If
this option is chosen, the owner or operator shall report a default
value of 200.0 percent of the MPC for each unit operating hour in
which the full-scale of the low range NOX analyzer is
exceeded.
(f) The high span and range shall be determined in accordance
with section 2.1.2.3 of this appendix. The low span value shall be
100.0 to 125.0 percent of the MEC, rounded up to the next highest
multiple of 10 ppm (or 100 ppm, if appropriate). If more than one
MEC value (as determined in section 2.1.2.2 of this appendix) is
<20.0 percent of the high full-scale range value, the low span value
shall be based upon whichever MEC value is closest to 20.0 percent
of the high range value. The low range must be greater than or equal
to the low span value, and the required calibration gases for the
low range must be selected based on the low span value. For units
with two NOX spans, use the low range whenever
NOX concentrations are expected to be consistently <20.0
percent of the high range value, i.e., when the MEC of the fuel
being combusted is <20.0 percent of the high range value. When the
full-scale of the low range is exceeded, the high range shall be
used to measure and record the NOX concentrations; or, if
applicable, the default high range value in paragraph (e) of this
section shall be reported for each hour of the full-scale
exceedance.
2.1.2.5 Adjustment of Span and Range
For each affected unit or common stack, the owner or operator
shall make a periodic evaluation of the MPC, MEC, span, and range
values for each NOX monitor (at a minimum, an annual
evaluation is required) and shall make any necessary span and range
adjustments, with corresponding monitoring plan updates, as
described in paragraphs (a) and (b) of this section. Span and range
adjustments may be required, for example, as a result of changes in
the fuel supply, changes in the manner of operation of the unit, or
installation or removal of emission controls. In implementing the
provisions in paragraphs (a) and (b) of this section, note that
NOX data recorded during short-term, non-representative
operating conditions (e.g., a trial burn of a different type of
fuel) shall be excluded from consideration. The owner or operator
shall keep the results of the most recent span and range evaluation
on-site, in a format suitable for inspection. Make each required
span or range adjustment no later than 45 days after the end of the
quarter in which the need to adjust the span or range is identified,
except that up to 90 days after the end of that quarter may be taken
to implement a span adjustment if the calibration gases currently
being used for daily calibration error tests and linearity checks
are unsuitable for use with the new span value.
(a) If the fuel supply, emission controls, or other process
parameters change such that the maximum expected concentration or
the maximum potential concentration changes significantly, adjust
the NOX pollutant concentration span(s) and (if
necessary) monitor range(s) to assure the continued accuracy of the
monitoring system. A ``significant'' change in the MPC or MEC means
that the guidelines in section 2.1 of this appendix can no longer be
met, as determined by either a periodic evaluation by the owner or
operator or from the results of an audit by the Administrator. The
owner or operator should evaluate whether any planned changes in
operation of the unit or stack may affect the concentration of
emissions being emitted from the unit and should plan any necessary
span and range changes needed to account for these changes, so that
they are made in as timely a manner as practicable to coordinate
with the operational changes. An example of a change that may
require a span and range adjustment is the installation of low-
NOX burner technology on a previously uncontrolled unit.
Determine the adjusted span(s) using the procedures in section
2.1.2.3 or 2.1.2.4 of this appendix (as applicable). Select the
full-scale range(s) of the instrument to be greater than or equal to
the adjusted span value(s) and to be consistent with the guidelines
of section 2.1 of this appendix.
(b) Whenever a full-scale range is exceeded during a quarter and
the exceedance is not caused by a monitor out-of-control period,
proceed as follows:
(1) For exceedances of the high range, report 200.0 percent of
the current full-scale range as the hourly NOX
concentration for each hour of the full-scale exceedance and make
appropriate adjustments to the MPC, span, and range to prevent
future full-scale exceedances.
(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 is not out-of-control or out-of-
service for any reason. However, if 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).
(c) Whenever changes are made to the MPC, MEC, full-scale range,
or span value of the NOX monitor as described in
paragraphs (a) and (b) of this section, record and report (as
applicable) the new full-scale range setting, the new MPC or MEC,
maximum potential NOX emission rate, and the adjusted
span value in an updated monitoring plan for the unit. The
monitoring plan update shall be made in the quarter in which the
changes become effective. In addition, record and report the
adjusted span as part of the records for the daily calibration error
test and linearity check required by appendix B to this part.
Whenever the span value is adjusted, use calibration gas
concentrations that meet the requirements of section 5.1 of this
appendix, based on the adjusted span value. When a span adjustment
is significant enough that the calibration gases currently being
used for daily calibration error tests and linearity checks are
unsuitable for use with the new span value, a linearity test using
the new calibration gases must be performed and passed. Data from
the monitor are considered invalid from the hour in which the span
is adjusted until the required linearity check is passed in
accordance with section 6.2 of this appendix.
2.1.3 CO2 and O2 Monitors
For an O2 monitor (including O2 monitors
used to measure CO2 emissions or percentage moisture),
select a span value between 15.0 and 25.0 percent O2. For
a CO2 monitor installed on a boiler, select a span value
between 14.0 and 20.0 percent CO2. For a CO2
monitor installed on a combustion turbine, an alternative span value
between 6.0 and 14.0 percent CO2 may be used. An
alternative O2 span value below 15.0 percent
O2 may be used if an appropriate technical justification
is included in the monitoring plan (e.g., O2
concentrations above a certain level create an unsafe operating
condition).
[[Page 28636]]
Select the full-scale range of the instrument to be consistent with
section 2.1 of this appendix and to be greater than or equal to the
span value. Select the calibration gas concentrations for the daily
calibration error tests and linearity checks in accordance with
section 5.1 of this appendix, as percentages of the span value. For
O2 monitors with span values 21.0 percent
O2, purified instrument air containing 20.9 percent
O2 may be used as the high-level calibration material.
2.1.3.1 Maximum Potential Concentration of CO2
For CO2 pollutant concentration monitors, the maximum
potential concentration shall be 14.0 percent CO2 for
boilers and 6.0 percent CO2 for combustion turbines.
Alternatively, the owner or operator may determine the MPC based on
a minimum of 720 hours of quality assured historical CEM data
representing the full operating load range of the unit(s). Note that
the MPC for CO2 monitors shall only be used for the
purpose of providing substitute data under this part. The
CO2 monitor span and range shall be determined according
to section 2.1.3 of this appendix.
2.1.3.2 Minimum Potential Concentration of O2
The owner or operator of a unit that uses a flow monitor and an
O2 diluent monitor to determine heat input in accordance
with Equation F-17 or F-18 in appendix F to this part shall, for the
purposes of providing substitute data under Sec. 75.36, determine
the minimum potential O2 concentration. The minimum
potential O2 concentration shall be based upon 720 hours
or more of quality-assured CEM data, representing the full operating
load range of the unit(s). The minimum potential O2
concentration shall be the lowest quality-assured hourly average
O2 concentration recorded in the 720 (or more) hours of
data used for the determination.
2.1.3.3 Adjustment of Span and Range
Adjust the span value and range of a CO2 or
O2 monitor in accordance with section 2.1.1.5 of this
appendix (insofar as those provisions are applicable), with the term
``CO2 or O2'' applying instead of the term
``SO2''. Set the new span and range in accordance with
section 2.1.3 of this appendix and report the new span value in the
monitoring plan.
2.1.4 Flow Monitors
Select the full-scale range of the flow monitor so that it is
consistent with section 2.1 of this appendix and can accurately
measure all potential volumetric flow rates at the flow monitor
installation site.
2.1.4.1 Maximum Potential Velocity and Flow Rate
For this purpose, determine the span value of the flow monitor
using the following procedure. Calculate the maximum potential
velocity (MPV) using Equation A-3a or A-3b or determine the MPV (wet
basis) from velocity traverse testing using Reference Method 2 (or
its allowable alternatives) in appendix A to part 60 of this
chapter. If using test values, use the highest average velocity
(determined from the Method 2 traverses) measured at or near the
maximum unit operating load. Express the MPV in units of wet
standard feet per minute (fpm). For the purpose of providing
substitute data during periods of missing flow rate data in
accordance with Secs. 75.31 and 75.33 and as required elsewhere in
this part, calculate the maximum potential stack gas flow rate (MPF)
in units of standard cubic feet per hour (scfh), as the product of
the MPV (in units of wet, standard fpm) times 60, times the cross-
sectional area of the stack or duct (in ft2) at the flow
monitor location.
[GRAPHIC] [TIFF OMITTED] TR26MY99.003
or
[GRAPHIC] [TIFF OMITTED] TR26MY99.004
Where:
MPV = maximum potential velocity (fpm, standard wet basis).
Fd = dry-basis F factor (dscf/mmBtu) from Table 1,
Appendix F to this part.
Fc = carbon-based F factor (scf CO2/mmBtu)
from Table 1, Appendix F to this part.
Hf = maximum heat input (mmBtu/minute) for all units, combined,
exhausting to the stack or duct where the flow monitor is located.
A = inside cross sectional area (ft2) of the flue at the
flow monitor location.
%O2d = maximum oxygen concentration, percent dry basis,
under normal operating conditions.
%CO2d = minimum carbon dioxide concentration, percent dry
basis, under normal operating conditions.
%H2O = maximum percent flue gas moisture content under
normal operating conditions.
2.1.4.2 Span Values and Range
Determine the span and range of the flow monitor as follows.
Convert the MPV, as determined in section 2.1.4.1 of this appendix,
to the same measurement units of flow rate that are used for daily
calibration error tests (e.g., scfh, kscfh, kacfm, or differential
pressure (inches of water)). Next, determine the ``calibration span
value'' by multiplying the MPV (converted to equivalent daily
calibration error units) by a factor no less than 1.00 and no
greater than 1.25, and rounding up the result to at least two
significant figures. For calibration span values in inches of water,
retain at least two decimal places. Select appropriate reference
signals for the daily calibration error tests as percentages of the
calibration span value. Finally, calculate the ``flow rate span
value'' (in scfh) as the product of the MPF, as determined in
section 2.1.4.1 of this appendix, times the same factor (between
1.00 and 1.25) that was used to calculate the calibration span
value. Round off the flow rate span value to the nearest 1000 scfh.
Select the full-scale range of the flow monitor so that it is
greater than or equal to the span value and is consistent with
section 2.1 of this appendix. Include in the monitoring plan for the
unit: calculations of the MPV, MPF, calibration span value, flow
rate span value, and full-scale range (expressed both in scfh and,
if different, in the measurement units of calibration).
2.1.4.3 Adjustment of Span and Range
For each affected unit or common stack, the owner or operator
shall make a periodic evaluation of the MPV, MPF, span, and range
values for each flow rate monitor (at a minimum, an annual
evaluation is required) and shall make any necessary span and range
adjustments with corresponding monitoring plan updates, as described
in paragraphs (a) through (c) of this section 2.1.4.3. Span and
range adjustments may be required, for example, as a result of
changes in the fuel supply, changes in the stack or ductwork
configuration, changes in the manner of operation of the unit, or
installation or removal of emission controls. In implementing the
provisions in paragraphs (a) and (b) of this section 2.1.4.3, note
that flow rate data recorded during short-term, non-representative
operating conditions (e.g., a trial burn of a different type of
fuel) shall be excluded from consideration. The owner or operator
shall keep the results of the most recent span and range evaluation
on-site, in a format suitable for inspection. Make each required
span or range adjustment no later than 45 days after the end of the
quarter in which the need to adjust the span or range is identified.
(a) If the fuel supply, stack or ductwork configuration,
operating parameters, or other conditions change such that the
maximum potential flow rate changes significantly, adjust the span
and range to assure the continued accuracy of the flow monitor. A
``significant'' change in the MPV or MPF means that the guidelines
of section 2.1 of this appendix can no longer be met, as
[[Page 28637]]
determined by either a periodic evaluation by the owner or operator
or from the results of an audit by the Administrator. The owner or
operator should evaluate whether any planned changes in operation of
the unit may affect the flow of the unit or stack and should plan
any necessary span and range changes needed to account for these
changes, so that they are made in as timely a manner as practicable
to coordinate with the operational changes. Calculate the adjusted
calibration span and flow rate span values using the procedures in
section 2.1.4.2 of this appendix.
(b) Whenever the full-scale range is exceeded during a quarter,
provided that the exceedance is not caused by a monitor out-of-
control period, report 200.0 percent of the current full-scale range
as the hourly flow rate for each hour of the full-scale exceedance.
If the range is exceeded, make appropriate adjustments to the MPF,
flow rate span, and range to prevent future full-scale exceedances.
Calculate the new calibration span value by converting the new flow
rate span value from units of scfh to units of daily calibration. A
calibration error test must be performed and passed to validate data
on the new range.
(c) Whenever changes are made to the MPV, MPF, full-scale range,
or span value of the flow monitor, as described in paragraphs (a)
and (b) of this section, record and report (as applicable) the new
full-scale range setting, calculations of the flow rate span value,
calibration span value, MPV, and MPF in an updated monitoring plan
for the unit. The monitoring plan update shall be made in the
quarter in which the changes become effective. Record and report the
adjusted calibration span and reference values as parts of the
records for the calibration error test required by appendix B to
this part. Whenever the calibration span value is adjusted, use
reference values for the calibration error test that meet the
requirements of section 2.2.2.1 of this appendix, based on the most
recent adjusted calibration span value. Perform a calibration error
test according to section 2.1.1 of appendix B to this part whenever
making a change to the flow monitor span or range, unless the range
change also triggers a recertification under Sec. 75.20(b).
2.1.5 Minimum Potential Moisture Percentage
Except as provided in section 2.1.6 of this appendix, the owner
or operator of a unit that uses a continuous moisture monitoring
system to correct emission rates and heat inputs from a dry basis to
a wet basis (or vice-versa) shall, for the purpose of providing
substitute data under Sec. 75.37, use a default value of 3.0 percent
H2O as the minimum potential moisture percentage.
Alternatively, the minimum potential moisture percentage may be
based upon 720 hours or more of quality-assured CEM data,
representing the full operating load range of the unit(s). If this
option is chosen, the minimum potential moisture percentage shall be
the lowest quality-assured hourly average H2O
concentration recorded in the 720 (or more) hours of data used for
the determination.
2.1.6 Maximum Potential Moisture Percentage
When Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to
part 60 of this chapter is used to determine NOX emission
rate, the owner or operator of a unit that uses a continuous
moisture monitoring system shall, for the purpose of providing
substitute data under Sec. 75.37, determine the maximum potential
moisture percentage. The maximum potential moisture percentage shall
be based upon 720 hours or more of quality-assured CEM data,
representing the full operating load range of the unit(s). The
maximum potential moisture percentage shall be the highest quality-
assured hourly average H2O concentration recorded in the
720 (or more) hours of data used for the determination.
55. Appendix A to part 75 is amended by revising section 3.1,
the last sentence in the first paragraph of section 3.2, and section
3.3.2; by adding section 3.3.6; and by revising sections 3.3.7,
3.4.1 and 3.5 to read as follows:
3. Performance Specifications
3.1 Calibration Error
(a) The calibration error performance specifications in this
section apply only to 7-day calibration error tests under sections
6.3.1 and 6.3.2 of this appendix and to the offline calibration
demonstration described in section 2.1.1.2 of appendix B to this
part. The calibration error limits for daily operation of the
continuous monitoring systems required under this part are found in
section 2.1.4(a) of appendix B to this part.
(b) The calibration error of SO2 and NOX
pollutant concentration monitors shall not deviate from the
reference value of either the zero or upscale calibration gas by
more than 2.5 percent of the span of the instrument, as calculated
using Equation A-5 of this appendix. Alternatively, where the span
value is less than 200 ppm, calibration error test results are also
acceptable if the absolute value of the difference between the
monitor response value and the reference value, |R-A- in Equation A-
5 of this appendix, is
5 ppm. The calibration error of CO2 or
O2 monitors (including O2 monitors used to
measure CO2 emissions or percent moisture) shall not
deviate from the reference value of the zero or upscale calibration
gas by >0.5 percent O2 or CO2, as calculated
using the term -R-A| in the numerator of Equation A-5 of this
appendix. The calibration error of flow monitors shall not exceed
3.0 percent of the calibration span value of the instrument, as
calculated using Equation A-6 of this appendix. For differential
pressure-type flow monitors, the calibration error test results are
also acceptable if |R-A|, the absolute value of the difference
between the monitor response and the reference value in Equation A-
6, does not exceed 0.01 inches of water.
3.2 Linearity Check
* * * For CO2 or O2 monitors (including
O2 monitors used to measure CO2 emissions or
percent moisture):
* * * * *
3.3 * * *
3.3.2 Relative Accuracy for NOX-Diluent Continuous Emission
Monitoring Systems
(a) The relative accuracy for NOX-diluent continuous
emission monitoring systems shall not exceed 10.0 percent.
(b) For affected units where the average of the monitoring
system measurements of NOX emission rate during the
relative accuracy test audit is less than or equal to 0.200 lb/
mmBtu, the mean value of the continuous emission monitoring system
measurements shall not exceed 0.020 lb/mmBtu of the
reference method mean value whenever the relative accuracy
specification of 10.0 percent is not achieved.
* * * * *
3.3.6 Relative Accuracy for Moisture Monitoring Systems
The relative accuracy of a moisture monitoring system shall not
exceed 10.0 percent. The relative accuracy test results are also
acceptable if the mean difference of the reference method
measurements (in percent H2O) and the corresponding
moisture monitoring system measurements (in percent H2O),
calculated using Equation A-7 of this appendix, are within
1.5 percent H2O.
3.3.7 Relative Accuracy for NOX Concentration Monitoring
Systems
(a) The following requirement applies only to NOX
concentration monitoring systems (i.e., NOX pollutant
concentration monitors) that are used to determine NOX
mass emissions, where the owner or operator elects to monitor and
report NOX mass emissions using a NOX
concentration monitoring system and a flow monitoring system.
(b) The relative accuracy for NOX concentration
monitoring systems shall not exceed 10.0 percent. Alternatively, for
affected units where the average of the monitoring system
measurements of NOX concentration during the relative
accuracy test audit is less than or equal to 250.0 ppm, the mean
value of the continuous emission monitoring system measurements
shall not exceed 15.0 ppm of the reference method mean
value.
3.4 * * *
3.4.1 SO2 Pollutant Concentration Monitors, NOX
Concentration Monitoring Systems and NOX-Diluent Continuous
Emission Monitoring Systems
SO2 pollutant concentration monitors, NOX-
diluent continuous emission monitoring systems and NOX
concentration monitoring systems used to determine NOX
mass emissions, as defined in Sec. 75.71(a)(2), shall not be biased
low as determined by the test procedure in section 7.6 of this
appendix. The bias specification applies to all SO2
pollutant concentration monitors and to all NOX
concentration monitoring systems, including those measuring an
average SO2 or NOX concentration of 250.0 ppm
or less, and to all NOX-diluent continuous emission
monitoring systems, including those measuring an average
NOX emission rate of 0.200 lb/mmBtu or less.
* * * * *
[[Page 28638]]
3.5 Cycle Time
The cycle time for pollutant concentration monitors, oxygen
monitors used to determine percent moisture, and any other
continuous emission monitoring system(s) required to perform a cycle
time test shall not exceed 15 minutes.
56. Appendix A to part 75 is amended by revising the first
sentence of the first paragraph of section 4 and paragraph (6) to
read as follows:
4. Data Acquisition and Handling Systems
Automated data acquisition and handling systems shall read and
record the full range of pollutant concentrations and volumetric
flow from zero through span and provide a continuous, permanent
record of all measurements and required information as an ASCII flat
file capable of transmission both by direct computer-to-computer
electronic transfer via modem and EPA-provided software and by an
IBM-compatible personal computer diskette.
* * * * *
(6) Provide a continuous, permanent record of all measurements
and required information as an ASCII flat file capable of
transmission both by direct computer-to-computer electronic transfer
via modem and EPA-provided software and by an IBM-compatible
personal computer diskette.
57. Appendix A to part 75 is amended by revising sections 5
through 5.1.6, adding sections 5.1.7 through 5.1.8, and revising
sections 5.2 through 5.2.4 to read as follows:
5. Calibration Gas
5.1 Reference Gases
For the purposes of part 75, calibration gases include the
following:
5.1.1 Standard Reference Materials (SRM)
These calibration gases may be obtained from the National
Institute of Standards and Technology (NIST) at the following
address: Quince Orchard and Cloppers Road, Gaithersburg, MD 20899-
0001.
5.1.2 SRM-Equivalent Compressed Gas Primary Reference Material (PRM)
Contact the Gas Metrology Team, Analytical Chemistry Division,
Chemical Science and Technology Laboratory of NIST, at the address
in section 5.1.1, for a list of vendors and cylinder gases.
5.1.3 NIST Traceable Reference Materials
Contact the Gas Metrology Team, Analytical Chemistry Division,
Chemical Science and Technology Laboratory of NIST, at the address
in section 5.1.1, for a list of vendors and cylinder gases.
5.1.4 EPA Protocol Gases
(a) EPA Protocol gases must be vendor-certified to be within 2.0
percent of the concentration specified on the cylinder label (tag
value), using the uncertainty calculation procedure in section 2.1.8
of the ``EPA Traceability Protocol for Assay and Certification of
Gaseous Calibration Standards,'' September 1997, EPA-600/R-97/121.
(b) A copy of EPA-600/R-97/121 is available from the National
Technical Information Service, 5285 Port Royal Road, Springfield,
VA, 703-487-4650 and from the Office of Research and Development,
(MD-77B), U.S. Environmental Protection Agency, Research Triangle
Park, NC 27711.
5.1.5 Research Gas Mixtures
Research gas mixtures must be vendor-certified to be within 2.0
percent of the concentration specified on the cylinder label (tag
value), using the uncertainty calculation procedure in section 2.1.8
of the ``EPA Traceability Protocol for Assay and Certification of
Gaseous Calibration Standards,'' September 1997, EPA-600/R-97/121.
Inquiries about the RGM program should be directed to: National
Institute of Standards and Technology, Analytical Chemistry
Division, Chemical Science and Technology Laboratory, B-324
Chemistry, Gaithersburg, MD 20899.
5.1.6 Zero Air Material
Zero air material is defined in Sec. 72.2 of this chapter.
5.1.7 NIST/EPA-Approved Certified Reference Materials
Existing certified reference materials (CRMs) that are still
within their certification period may be used as calibration gas.
5.1.8 Gas Manufacturer's Intermediate Standards
Gas manufacturer's intermediate standards is defined in
Sec. 72.2 of this chapter.
5.2 Concentrations
Four concentration levels are required as follows.
5.2.1 Zero-level Concentration
0.0 to 20.0 percent of span, including span for high-scale or
both low- and high-scale for SO2, NOX,
CO2, and O2 monitors, as appropriate.
5.2.2 Low-level Concentration
20.0 to 30.0 percent of span, including span for high-scale or
both low- and high-scale for SO2, NOX,
CO2, and O2 monitors, as appropriate.
5.2.3 Mid-level Concentration
50.0 to 60.0 percent of span, including span for high-scale or
both low- and high-scale for SO2, NOX,
CO2, and O2 monitors, as appropriate.
5.2.4 High-level Concentration
80.0 to 100.0 percent of span, including span for high-scale or
both low-and high-scale for SO2, NOX,
CO2, and O2 monitors, as appropriate.
58. Appendix A to part 75 is amended by revising sections 6.2,
6.3.1, 6.3.2, 6.4, 6.5, 6.5.1, 6.5.2, 6.5.6, 6.5.7, 6.5.9 and
6.5.10, and adding sections 6.5.2.1, 6.5.2.2, 6.5.6.1, 6.5.6.2, and
6.5.6.3 to read as follows:
6. Certification Tests and Procedures
* * * * *
6.2 Linearity Check (General Procedures)
Check the linearity of each SO2, NOX,
CO2, and O2 monitor while the unit, or group
of units for a common stack, is combusting fuel at conditions of
typical stack temperature and pressure; it is not necessary for the
unit to be generating electricity during this test. 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 test requirements of this part.
For units using emission controls and other units using both a high
and a low span, perform a linearity check on both the low- and high-
scales for initial certification. For on-going quality assurance of
the CEMS, perform linearity checks, using the procedures in this
section, on the range(s) and at the frequency specified in section
2.2.1 of appendix B to this part. Challenge each monitor with
calibration gas, as defined in section 5.1 of this appendix, at the
low-, mid-, and high-range concentrations specified in section 5.2
of this appendix. Introduce the calibration gas at the gas injection
port, as specified in section 2.2.1 of this appendix. Operate each
monitor at its normal operating temperature and conditions. For
extractive and dilution type monitors, pass the calibration gas
through all filters, scrubbers, conditioners, and other monitor
components used during normal sampling and through as much of the
sampling probe as is practical. For in-situ type monitors, perform
calibration checking all active electronic and optical components,
including the transmitter, receiver, and analyzer. Challenge the
monitor three times with each reference gas (see example data sheet
in Figure 1). Do not use the same gas twice in succession. To the
extent practicable, the duration of each linearity test, from the
hour of the first injection to the hour of the last injection, shall
not exceed 24 unit operating hours. Record the monitor response from
the data acquisition and handling system. For each concentration,
use the average of the responses to determine the error in linearity
using Equation A-4 in this appendix. Linearity checks are acceptable
for monitor or monitoring system certification, recertification, or
quality assurance if none of the test results exceed the applicable
performance specifications in section 3.2 of this appendix. The
status of emission data from a CEMS prior to and during a linearity
test period shall be determined as follows:
(a) For the initial certification of a CEMS, data from the
monitoring system are considered invalid until all certification
tests, including the linearity test, have been successfully
completed, unless the data validation procedures in Sec. 75.20(b)(3)
are used. When the procedures in Sec. 75.20(b)(3) are followed, the
words ``initial certification'' apply instead of
``recertification,'' and complete all of the initial certification
tests by the applicable deadline in Sec. 75.4, rather than within
the time periods specified in Sec. 75.20(b)(3)(iv) for the
individual tests.
(b) For the routine quality assurance linearity checks required
by section 2.2.1 of appendix B to this part, use the data validation
procedures in section 2.2.3 of appendix B to this part.
(c) When a linearity test is required as a diagnostic test or
for recertification, use the data validation procedures in
Sec. 75.20(b)(3).
(d) For linearity tests of non-redundant backup monitoring
systems, use the data validation procedures in
Sec. 75.20(d)(2)(iii).
(e) For linearity tests performed during a grace period and
after the expiration of a grace period, use the data validation
procedures in sections 2.2.3 and 2.2.4, respectively, of appendix B
to this part.
[[Page 28639]]
(f) For all other linearity checks, use the data validation
procedures in section 2.2.3 of appendix B to this part.
6.3 * * *
6.3.1 Gas Monitor 7-day Calibration Error Test
Measure the calibration error of each SO2 monitor,
each NOX monitor and each CO2 or O2
monitor while the unit is combusting fuel (but not necessarily
generating electricity) once each day for 7 consecutive operating
days according to the following procedures. (In the event that
extended unit outages occur after the commencement of the test, the
7 consecutive unit operating days need not be 7 consecutive calendar
days.) Units using dual span monitors must perform the calibration
error test on both high- and low-scales of the pollutant
concentration monitor. The calibration error test procedures in this
section and in section 6.3.2 of this appendix shall also be used to
perform the daily assessments and additional calibration error tests
required under sections 2.1.1 and 2.1.3 of appendix B to this part.
Do not make manual or automatic adjustments to the monitor settings
until after taking measurements at both zero and high concentration
levels for that day during the 7-day test. If automatic adjustments
are made following both injections, conduct the calibration error
test such that the magnitude of the adjustments can be determined
and recorded. Record and report test results for each day using the
unadjusted concentration measured in the calibration error test
prior to making any manual or automatic adjustments (i.e., resetting
the calibration). The calibration error tests should be
approximately 24 hours apart, (unless the 7-day test is performed
over non-consecutive days). Perform calibration error tests at both
the zero-level concentration and high-level concentration, as
specified in section 5.2 of this appendix. Alternatively, a mid-
level concentration gas (50.0 to 60.0 percent of the span value) may
be used in lieu of the high-level gas, provided that the mid-level
gas is more representative of the actual stack gas concentrations.
In addition, repeat the procedure for SO2 and
NOX pollutant concentration monitors using the low-scale
for units equipped with emission controls or other units with dual
span monitors. Use only calibration gas, as specified in section 5.1
of this appendix. Introduce the calibration gas at the gas injection
port, as specified in section 2.2.1 of this appendix. Operate each
monitor in its normal sampling mode. For extractive and dilution
type monitors, pass the calibration gas through all filters,
scrubbers, conditioners, and other monitor components used during
normal sampling and through as much of the sampling probe as is
practical. For in-situ type monitors, perform calibration, checking
all active electronic and optical components, including the
transmitter, receiver, and analyzer. Challenge the pollutant
concentration monitors and CO2 or O2 monitors
once with each calibration gas. Record the monitor response from the
data acquisition and handling system. Using Equation A-5 of this
appendix, determine the calibration error at each concentration once
each day (at approximately 24-hour intervals) for 7 consecutive days
according to the procedures given in this section. The results of a
7-day calibration error test are acceptable for monitor or
monitoring system certification, recertification or diagnostic
testing if none of these daily calibration error test results exceed
the applicable performance specifications in section 3.1 of this
appendix.The status of emission data from a gas monitor prior to and
during a 7-day calibration error test period shall be determined as
follows:
(a) For initial certification, data from the monitor are
considered invalid until all certification tests, including the 7-
day calibration error test, have been successfully completed, unless
the data validation procedures in Sec. 75.20(b)(3) are used. When
the procedures in Sec. 75.20(b)(3) are followed, the words ``initial
certification'' apply instead of ``recertification,'' and complete
all of the initial certification tests by the applicable deadline in
Sec. 75.4, rather than within the time periods specified in
Sec. 75.20(b)(3)(iv) for the individual tests.
(b) When a 7-day calibration error test is required as a
diagnostic test or for recertification, use the data validation
procedures in Sec. 75.20(b)(3).
6.3.2 Flow Monitor 7-day Calibration Error Test
Perform the 7-day calibration error test of a flow monitor, when
required for certification, recertification or diagnostic testing,
according to the following procedures. Introduce the reference
signal corresponding to the values specified in section 2.2.2.1 of
this appendix to the probe tip (or equivalent), or to the
transducer. During the 7-day certification test period, conduct the
calibration error test while the unit is operating once each unit
operating day (as close to 24-hour intervals as practicable). In the
event that extended unit outages occur after the commencement of the
test, the 7 consecutive operating days need not be 7 consecutive
calendar days. Record the flow monitor responses by means of the
data acquisition and handling system. Calculate the calibration
error using Equation A-6 of this appendix. Do not perform any
corrective maintenance, repair, or replacement upon the flow monitor
during the 7-day test period other than that required in the quality
assurance/quality control plan required by appendix B to this part.
Do not make adjustments between the zero and high reference level
measurements on any day during the 7-day test. If the flow monitor
operates within the calibration error performance specification
(i.e., less than or equal to 3.0 percent error each day and
requiring no corrective maintenance, repair, or replacement during
the 7-day test period), the flow monitor passes the calibration
error test. Record all maintenance activities and the magnitude of
any adjustments. Record output readings from the data acquisition
and handling system before and after all adjustments. Record and
report all calibration error test results using the unadjusted flow
rate measured in the calibration error test prior to resetting the
calibration. Record all adjustments made during the 7-day period at
the time the adjustment is made, and report them in the
certification or recertification application. The status of
emissions data from a flow monitor prior to and during a 7-day
calibration error test period shall be determined as follows:
(a) For initial certification, data from the monitor are
considered invalid until all certification tests, including the 7-
day calibration error test, have been successfully completed, unless
the data validation procedures in Sec. 75.20(b)(3) are used. When
the procedures in Sec. 75.20(b)(3) are followed, the words ``initial
certification'' apply instead of ``recertification,'' and complete
all of the initial certification tests by the applicable deadline in
Sec. 75.4, rather than within the time periods specified in
Sec. 75.20(b)(3)(iv) for the individual tests.
(b) When a 7-day calibration error test is required as a
diagnostic test or for recertification, use the data validation
procedures in Sec. 75.20(b)(3).
6.4 Cycle Time Test
Perform cycle time tests for each pollutant concentration
monitor and continuous emission monitoring system while the unit is
operating, according to the following procedures (see also Figure 6
at the end of this appendix). Use a zero-level and a high-level
calibration gas (as defined in section 5.2 of this appendix)
alternately. To determine the upscale elapsed time, inject a zero-
level concentration calibration gas into the probe tip (or injection
port leading to the calibration cell, for in situ systems with no
probe). Record the stable starting gas value and start time, using
the data acquisition and handling system (DAHS). Next, allow the
monitor to measure the concentration of flue gas emissions until the
response stabilizes. Record the stable ending stack emissions value
and the end time of the test using the DAHS. Determine the upscale
elapsed time as the time it takes for 95.0 percent of the step
change to be achieved between the stable starting gas value and the
stable ending stack emissions value. Then repeat the procedure,
starting by injecting the high-level gas concentration to determine
the downscale elapsed time, which is the time it takes for 95.0
percent of the step change to be achieved between the stable
starting gas value and the stable ending stack emissions value. End
the downscale test by measuring the stable concentration of flue gas
emissions. Record the stable starting and ending monitor values, the
start and end times, and the downscale elapsed time for the monitor
using the DAHS. A stable value is equivalent to a reading with a
change of less than 2.0 percent of the span value for 2 minutes, or
a reading with a change of less than 6.0 percent from the measured
average concentration over 6 minutes. (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
[[Page 28640]]
longest possible cycle time. Report the slower of the two elapsed
times (upscale or downscale) as the cycle time for the analyzer.
(See Figure 5 at the end of this appendix.) For the NOx-diluent
continuous emission monitoring system test and SO2-
diluent continuous emission monitoring system test, record and
report the longer cycle time of the two component analyzers as the
system cycle time. For time-shared systems, this procedure must be
done at all 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, add together the longest cycle
time obtained at each of the probe locations. Report the sum of the
longest cycle time at each of the probe locations 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 as the cycle time for each of the time-shared
systems. For monitors with dual ranges, report the test results from
on the range giving the longer cycle time. Cycle time test results
are acceptable for monitor or monitoring system certification,
recertification or diagnostic testing if none of the cycle times
exceed 15 minutes. The status of emissions data from a monitor prior
to and during a cycle time test period shall be determined as
follows:
(a) For initial certification, data from the monitor are
considered invalid until all certification tests, including the
cycle time test, have been successfully completed, unless the data
validation procedures in Sec. 75.20(b)(3) are used. When the
procedures in Sec. 75.20(b)(3) are followed, the words ``initial
certification'' apply instead of ``recertification,'' and complete
all of the initial certification tests by the applicable deadline in
Sec. 75.4, rather than within the time periods specified in
Sec. 75.20(b)(3)(iv) for the individual tests.
(b) When a cycle time test is required as a diagnostic test or
for recertification, use the data validation procedures in
Sec. 75.20(b)(3).
6.5 Relative Accuracy and Bias Tests (General Procedures)
Perform the required relative accuracy test audits (RATAs) as
follows for each CO2 pollutant concentration monitor
(including O2 monitors used to determine CO2
pollutant concentration), each SO2 pollutant
concentration monitor, each NOX concentration monitoring
system used to determine NOX mass emissions, each flow
monitor, each NOX-diluent continuous emission monitoring
system, each O2 or CO2 diluent monitor used to
calculate heat input, each moisture monitoring system and each
SO2-diluent continuous emission monitoring system. For
NOX concentration monitoring systems used to determine
NOX mass emissions, as defined in Sec. 75.71(a)(2), use
the same general RATA procedures as for SO2 pollutant
concentration monitors; however, use the reference methods for
NOX concentration specified in section 6.5.10 of this
appendix:
(a) Except as provided in Sec. 75.21(a)(5), perform each RATA
while the unit (or units, if more than one unit exhausts into the
flue) is combusting the fuel that is normal for that unit (for some
units, more than one type of fuel may be considered normal, e.g., a
unit that combusts gas or oil on a seasonal basis). When relative
accuracy test audits are performed on continuous emission monitoring
systems or component(s) on bypass stacks/ducts, use the fuel
normally combusted by the unit (or units, if more than one unit
exhausts into the flue) when emissions exhaust through the bypass
stack/ducts.
(b) Perform each RATA at the load level(s) specified in section
6.5.1 or 6.5.2 of this appendix or in section 2.3.1.3 of appendix B
to this part, as applicable.
(c) For monitoring systems with dual ranges, perform the
relative accuracy test on the range normally used for measuring
emissions. For units with add-on SO2 or NOx
controls or for units that need a dual range to record high
concentration ``spikes'' during startup conditions, the low range is
considered normal. However, for some dual span units (e.g., for
units that use fuel switching or for which the emission controls are
operated seasonally), either of the two measurement ranges may be
considered normal; in such cases, perform the RATA on the range that
is in use at the time of the scheduled test.
(d) Record monitor or monitoring system output from the data
acquisition and handling system.
(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). 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.
(f) The status of emission data from the CEMS prior to and
during the RATA test period shall be determined as follows:
(1) For the initial certification of a CEMS, data from the
monitoring system are considered invalid until all certification
tests, including the RATA, have been successfully completed, unless
the data validation procedures in Sec. 75.20(b)(3) are used. When
the procedures in Sec. 75.20(b)(3) are followed, the words ``initial
certification'' apply instead of ``recertification,'' and complete
all of the initial certification tests by the applicable deadline in
Sec. 75.4, rather than within the time periods specified in
Sec. 75.20(b)(3)(iv) for the individual tests.
(2) For the routine quality assurance RATAs required by section
2.3.1 of appendix B to this part, use the data validation procedures
in section 2.3.2 of appendix B to this part.
(3) For recertification RATAs, use the data validation
procedures in Sec. 75.20(b)(3).
(4) For quality assurance RATAs of non-redundant backup
monitoring systems, use the data validation procedures in
Secs. 75.20(d)(2)(v) and (vi).
(5) For RATAs performed during and after the expiration of a
grace period, use the data validation procedures in sections 2.3.2
and 2.3.3, respectively, of appendix B to this part.
(6) For all other RATAs, use the data validation procedures in
section 2.3.2 of appendix B to this part.
(g) For each SO2 or CO2 pollutant
concentration monitor, each flow monitor, each CO2 or
O2 diluent monitor used to determine heat input, each
NOX concentration monitoring system used to determine
NOX mass emissions, as defined in Sec. 75.71(a)(2), each
moisture monitoring system and each NOX-diluent
continuous emission monitoring system, calculate the relative
accuracy, in accordance with section 7.3 or 7.4 of this appendix, as
applicable. In addition (except for CO2, O2,
SO2-diluent or moisture monitors), test for bias and
determine the appropriate bias adjustment factor, in accordance with
sections 7.6.4 and 7.6.5 of this appendix, using the data from the
relative accuracy test audits.
6.5.1 Gas Monitoring System RATAs (Special Considerations)
(a) Perform the required relative accuracy test audits for each
SO2 or CO2 pollutant concentration monitor,
each CO2 or O2 diluent monitor used to determine heat
input, each NOX-diluent continuous emission monitoring
system, each NOX concentration monitoring system used to
determine NOX mass emissions, as defined in
Sec. 75.71(a)(2), and each SO2-diluent continuous
emission monitoring system, at the normal load level for the unit
(or combined units, if common stack), as defined in section 6.5.2.1
of this appendix. If two load levels have been designated as normal,
the RATAs may be done at either load level.
(b) For the initial certification of a gas monitoring system and
for recertifications in which, in addition to a RATA, one or more
other tests are required (i.e., a linearity test, cycle time test,
or 7-day calibration error test), EPA recommends that the RATA not
be commenced until the other required tests of the CEMS have been
passed.
6.5.2 Flow Monitor RATAs (Special Considerations)
(a) Except for flow monitors on bypass stacks/ducts and peaking
units, perform relative accuracy test audits for the initial
certification of each flow monitor at three different exhaust gas
velocities (low, mid, and high), corresponding to three different
load levels within the range of operation, as defined in section
6.5.2.1 of this appendix. For a common stack/duct, the three
different exhaust gas velocities may be obtained from frequently
used unit/load combinations for the units exhausting to the common
stack. Select the three exhaust gas velocities such that the audit
points at adjacent load levels (i.e., low and mid or mid and high),
in megawatts (or in thousands of lb/hr of steam production), are
separated by no less than 25.0 percent of the range of operation, as
defined in section 6.5.2.1 of this appendix.
(b) For flow monitors on bypass stacks/ducts and peaking units,
the flow monitor relative accuracy test audits for initial
certification and recertification shall be single-load tests,
performed at the normal load, as defined in section 6.5.2.1 of this
appendix.
[[Page 28641]]
(c) Flow monitor recertification RATAs shall be done at three
load level(s), unless otherwise specified in paragraph (b) of this
section or unless otherwise specified or approved by the
Administrator.
(d) The semiannual and annual quality assurance flow monitor
RATAs required under appendix B to this part shall be done at the
load level(s) specified in section 2.3.1.3 of appendix B to this
part.
6.5.2.1 Range of Operation and Normal Load Level(s)
(a) The owner or operator shall determine the upper and lower
boundaries of the ``range of operation'' for each unit (or
combination of units, for common stack configurations) 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. The lower boundary of the range of
operation of a unit shall be the minimum safe, stable load. For
common stacks, the minimum safe, stable load shall be the lowest of
the minimum safe, stable loads for any of the units discharging
through the stack. Alternatively, for a group of frequently-operated
units that serve a common stack, the sum of the minimum safe, stable
loads for the individual units may be used as the lower boundary of
the range of operation. The upper boundary of the range of operation
of a unit shall be the maximum sustainable load. The ``maximum
sustainable load'' is the higher of either: the nameplate or rated
capacity of the unit, less any physical or regulatory limitations or
other deratings; or the highest sustainable unit load, based on at
least four quarters of representative historical operating data. For
common stacks, the maximum sustainable load is the sum of all of the
maximum sustainable loads of the individual units discharging
through the stack, unless this load is unattainable in practice, in
which case use the highest sustainable combined load for the units
that discharge through the stack, based on at least four quarters of
representative historical operating data. The load values for the
unit(s) shall be expressed either in units of megawatts or thousands
of lb/hr of steam load.
(b) The operating levels for relative accuracy test audits
shall, except for peaking units, be defined as follows: the ``low''
operating level shall be the first 30.0 percent of the range of
operation; the ``mid'' operating level shall be the middle portion
(30.0 to 60.0 percent) of the range of operation; and the ``high''
operating level shall be the upper end (60.0 to 100.0 percent) of
the range of operation. For example, if the upper and lower
boundaries of the range of operation are 100 and 1100 megawatts,
respectively, then the low, mid, and high operating levels would be
100 to 400 megawatts, 400 to 700 megawatts, and 700 to 1100
megawatts, respectively.
(c) The owner or operator shall identify, for each affected unit
or common stack (except for peaking units), the ``normal'' load
level or levels (low, mid or high), based on the operating history
of the unit(s). This requirement becomes effective on April 1, 2000;
however, the owner or operator may choose to comply with this
requirement prior to April 1, 2000. To identify the normal load
level(s), the owner or operator shall, at a minimum, determine the
relative number of operating hours at each of the three load levels,
low, mid and high over the past four representative operating
quarters. The owner or operator shall determine, to the nearest 0.1
percent, the percentage of the time that each load level (low, mid,
high) has been used during that time period. A summary of the data
used for this determination and the calculated results shall be kept
on-site in a format suitable for inspection.
(d) Based on the analysis of the historical load data the owner
or operator shall designate the most frequently used load level as
the normal load level for the unit (or combination of units, for
common stacks). The owner or operator may also designate the second
most frequently used load level as an additional normal load level
for the unit or stack. For peaking units, normal load designations
are unnecessary; the entire operating load range shall be considered
normal. If the manner of operation of the unit changes
significantly, such that the designated normal load(s) or the two
most frequently used load levels change, the owner or operator shall
repeat the historical load analysis and shall redesignate the normal
load(s) and the two most frequently used load levels, as
appropriate. A minimum of two representative quarters of historical
load data are required to document that a change in the manner of
unit operation has occurred.
(e) Beginning on April 1, 2000, 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 of steam production, in the
electronic quarterly report required under Sec. 75.64. Except for
peaking units, the owner or operator shall indicate, in the
electronic quarterly report (as part of 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..
6.5.2.2 Multi-Load Flow RATA Results
For each multi-load flow RATA, calculate the flow monitor
relative accuracy at each operating level. If a flow monitor
relative accuracy test is failed or aborted due to a problem with
the monitor on any level of a 2-level (or 3-level) relative accuracy
test audit, the RATA must be repeated at that load level. However,
the entire 2-level (or 3-level) relative accuracy test audit does
not have to be repeated unless the flow monitor polynomial
coefficients or K-factor(s) are changed, in which case a 3-level
RATA is required.
* * * * *
6.5.6 Reference Method Traverse Point Selection
Select traverse points that ensure acquisition of representative
samples of pollutant and diluent concentrations, moisture content,
temperature, and flue gas flow rate over the flue cross section. To
achieve this, the reference method traverse points shall meet the
requirements of section 3.2 of Performance Specification 2 (``PS No.
2'') in appendix B to part 60 of this chapter (for SO2,
NOX, and moisture monitoring system RATAs), Performance
Specification 3 in appendix B to part 60 of this chapter (for
O2 and CO2 monitor RATAs), Method 1 (or 1A)
(for volumetric flow rate monitor RATAs), Method 3 (for molecular
weight), and Method 4 (for moisture determination) in appendix A to
part 60 of this chapter. Unless otherwise specified, use only
codified versions of PS No. 2 revised as of July 1, 1995, July 1,
1996 or July 1, 1997. The following alternative reference method
traverse point locations are permitted for moisture and gas monitor
RATAs:
(a) For moisture determinations where the moisture data are used
only to determine stack gas molecular weight, a single reference
method point, located at least 1.0 meter from the stack wall, may be
used. For moisture monitoring system RATAs and for gas monitor RATAs
in which moisture data are used to correct pollutant or diluent
concentrations from a dry basis to a wet basis (or vice-versa),
single-point moisture sampling may only be used if the 12-point
stratification test described in section 6.5.6.1 of this appendix is
performed prior to the RATA for at least one pollutant or diluent
gas, and if the test is passed according to the acceptance criteria
in section 6.5.6.3(b) of this appendix.
(b) For gas monitoring system RATAs, the owner or operator may
use any of the following options:
(1) At any location (including locations where stratification is
expected), use a minimum of six traverse points along a diameter, in
the direction of any expected stratification. The points shall be
located in accordance with Method 1 in appendix A to part 60 of this
chapter.
(2) At locations where section 3.2 of PS No. 2 allows the use of
a short reference method measurement line (with three points located
at 0.4, 1.0, and 2.0 meters from the stack wall), the owner or
operator may use an alternative 3-point measurement line, locating
the three points at 4.4, 14.6, and 29.6 percent of the way across
the stack, in accordance with Method 1 in appendix A to part 60 of
this chapter.
(3) At locations where stratification is likely to occur (e.g.,
following a wet scrubber or when dissimilar gas streams are
combined), the short measurement line from section 3.2 of PS No. 2
(or the alternative line described in paragraph (b)(2) of this
section) may be used in lieu of the prescribed ``long'' measurement
line in section 3.2 of PS No. 2, provided that the 12-point
stratification test described in section 6.5.6.1 of this appendix is
performed and passed one time at the location (according to the
acceptance criteria of section 6.5.6.3(a) of this appendix) and
provided that either the 12-point stratification test or the
alternative (abbreviated) stratification test in section 6.5.6.2 of
this appendix is performed and passed prior to each subsequent RATA
at the location (according to the acceptance criteria of section
6.5.6.3(a) of this appendix).
(4) A single reference method measurement point, located no less
than 1.0 meter from the stack wall and situated along one of the
measurement lines used for the stratification test, may be used at
any sampling location if
[[Page 28642]]
the 12-point stratification test described in section 6.5.6.1 of
this appendix is performed and passed prior to each RATA at the
location (according to the acceptance criteria of section 6.5.6.3(b)
of this appendix).
6.5.6.1 Stratification Test
(a) With the unit(s) operating under steady-state conditions at
normal load, as defined in section 6.5.2.1 of this appendix, use a
traversing gas sampling probe to measure the pollutant
(SO2 or NOX) and diluent (CO2 or
O2) concentrations at a minimum of twelve (12) points,
located according to Method 1 in appendix A to part 60 of this
chapter.
(b) Use Methods 6C, 7E, and 3A in appendix A to part 60 of this
chapter to make the measurements. Data from the reference method
analyzers must be quality assured by performing analyzer calibration
error and system bias checks before the series of measurements and
by conducting system bias and calibration drift checks after the
measurements, in accordance with the procedures of Methods 6C, 7E,
and 3A.
(c) Measure for a minimum of 2 minutes at each traverse point.
To the extent practicable, complete the traverse within a 2-hour
period.
(d) If the load has remained constant (3.0 percent)
during the traverse and if the reference method analyzers have
passed all of the required quality assurance checks, proceed with
the data analysis.
(e) Calculate the average NOX, SO2, and
CO2 (or O2) concentrations at each of the
individual traverse points. Then, calculate the arithmetic average
NOX, SO2, and CO2 (or
O2) concentrations for all traverse points.
6.5.6.2 Alternative (Abbreviated) Stratification Test
(a) With the unit(s) operating under steady-state conditions at
normal load, as defined in section 6.5.2.1 of this appendix, use a
traversing gas sampling probe to measure the pollutant
(SO2 or NOX) and diluent (CO2 or
O2) concentrations at three points. The points shall be
located according to the specifications for the long measurement
line in section 3.2 of PS No. 2 (i.e., locate the points 16.7
percent, 50.0 percent, and 83.3 percent of the way across the
stack). Alternatively, the concentration measurements may be made at
six traverse points along a diameter. The six points shall be
located in accordance with Method 1 in appendix A to part 60 of this
chapter.
(b) Use Methods 6C, 7E, and 3A in appendix A to part 60 of this
chapter to make the measurements. Data from the reference method
analyzers must be quality assured by performing analyzer calibration
error and system bias checks before the series of measurements and
by conducting system bias and calibration drift checks after the
measurements, in accordance with the procedures of Methods 6C, 7E,
and 3A.
(c) Measure for a minimum of 2 minutes at each traverse point.
To the extent practicable, complete the traverse within a 1-hour
period.
(d) If the load has remained constant (3.0 percent)
during the traverse and if the reference method analyzers have
passed all of the required quality assurance checks, proceed with
the data analysis.
(e) Calculate the average NOX, SO2, and
CO2 (or O2) concentrations at each of the
individual traverse points. Then, calculate the arithmetic average
NOX, SO2, and CO2 (or
O2) concentrations for all traverse points.
6.5.6.3 Stratification Test Results and Acceptance Criteria
(a) For each pollutant or diluent gas, the short reference
method measurement line described in section 3.2 of PS No. 2 may be
used in lieu of the long measurement line prescribed in section 3.2
of PS No. 2 if the results of a stratification test, conducted in
accordance with section 6.5.6.1 or 6.5.6.2 of this appendix (as
appropriate; see section 6.5.6(b)(3) of this appendix), show that
the concentration at each individual traverse point differs by no
more than 10.0 percent from the arithmetic average
concentration for all traverse points. The results are also
acceptable if the concentration at each individual traverse point
differs by no more than 5ppm or 0.5 percent
CO2 (or O2) from the arithmetic average
concentration for all traverse points.
(b) For each pollutant or diluent gas, a single reference method
measurement point, located at least 1.0 meter from the stack wall
and situated along one of the measurement lines used for the
stratification test, may be used for that pollutant or diluent gas
if the results of a stratification test, conducted in accordance
with section 6.5.6.1 of this appendix, show that the concentration
at each individual traverse point differs by no more than
5.0 percent from the arithmetic average concentration
for all traverse points. The results are also acceptable if the
concentration at each individual traverse point differs by no more
than 3 ppm or 0.3 percent CO2 (or
O2) from the arithmetic average concentration for all
traverse points.
(c) The owner or operator shall keep the results of all
stratification tests on-site, in a format suitable for inspection,
as part of the supplementary RATA records required under
Sec. 75.56(a)(7) or Sec. 75.59(a)(7), as applicable.
6.5.7 Sampling Strategy
(a) Conduct the reference method tests so they will yield
results representative of the pollutant concentration, emission
rate, moisture, temperature, and flue gas flow rate from the unit
and can be correlated with the pollutant concentration monitor,
CO2 or O2 monitor, flow monitor, and
SO2 or NOX continuous emission monitoring
system measurements. The minimum acceptable time for a gas
monitoring system RATA run or for a moisture monitoring system RATA
run is 21 minutes. For each run of a gas monitoring system RATA, all
necessary pollutant concentration measurements, diluent
concentration measurements, and moisture measurements (if
applicable) must, to the extent practicable, be made within a 60-
minute period. For NOX-diluent or SO2-diluent
monitoring system RATAs, the pollutant and diluent concentration
measurements must be made simultaneously. For flow monitor RATAs,
the minimum time per run shall be 5 minutes. Flow rate reference
method measurements may be made either sequentially from port to
port or simultaneously at two or more sample ports. The velocity
measurement probe may be moved from traverse point to traverse point
either manually or automatically. If, during a flow RATA,
significant pulsations in the reference method readings are
observed, be sure to allow enough measurement time at each traverse
point to obtain an accurate average reading when a manual readout
method is used (e.g., a ``sight-weighted'' average from a
manometer). A minimum of one set of auxiliary measurements for stack
gas molecular weight determination (i.e., diluent gas data and
moisture data) is required for every clock hour of a flow RATA or
for every three test runs (whichever is less restrictive).
Successive flow RATA runs may be performed without waiting in-
between runs. If an O2-diluent monitor is used as a
CO2 continuous emission monitoring system, perform a
CO2 system RATA (i.e., measure CO2, rather
than O2, with the reference method). For moisture
monitoring systems, an appropriate coefficient, ``K'' factor or
other suitable mathematical algorithm may be developed prior to the
RATA, to adjust the monitoring system readings with respect to the
reference method. If such a coefficient, K-factor or algorithm is
developed, it shall be applied to the CEMS readings during the RATA
and (if the RATA is passed), to the subsequent CEMS data, by means
of the automated data acquisition and handling system. The owner or
operator shall keep records of the current coefficient, K factor or
algorithm, as specified in Secs. 75.56(a)(5)(ix) and
75.59(a)(5)(vii). Whenever the coefficient, K factor or algorithm is
changed, a RATA of the moisture monitoring system is required.
(b) To properly correlate individual SO2 or
NOX continuous emission monitoring system data (in lb/
mmBtu) and volumetric flow rate data with the reference method data,
annotate the beginning and end of each reference method test run
(including the exact time of day) on the individual chart
recorder(s) or other permanent recording device(s).
* * * * *
6.5.9 Number of Reference Method Tests
Perform a minimum of nine sets of paired monitor (or monitoring
system) and reference method test data for every required (i.e.,
certification, recertification, diagnostic, semiannual, or annual)
relative accuracy test audit. For 2-level and 3-level relative
accuracy test audits of flow monitors, perform a minimum of nine
sets at each of the operating levels.
Note: The tester may choose to perform more than nine sets of
reference method tests. If this option is chosen, the tester may
reject a maximum of three sets of the test results, as long as the
total number of test results used to determine the relative accuracy
or bias is greater than or equal to nine. Report all data, including
the rejected CEMS data and corresponding reference method test
results.
6.5.10 Reference Methods
The following methods from appendix A to part 60 of this chapter
or their approved alternatives are the reference methods for
performing relative accuracy test audits: Method 1 or 1A for siting;
Method 2 or its
[[Page 28643]]
allowable alternatives in appendix A to part 60 of this chapter
(except for Methods 2B and 2E) for stack gas velocity and volumetric
flow rate; Methods 3, 3A, or 3B for O2 or CO2;
Method 4 for moisture; Methods 6, 6A, or 6C for SO2;
Methods 7, 7A, 7C, 7D or 7E for NOX, excluding the
exception in section 5.1.2 of Method 7E. When using Method 7E for
measuring NOX concentration, total NOX, both
NO and NO2, must be measured.
59. Appendix A to part 75 is amended by revising in sections
7.2.1, and 7.2.2, the text following each section's equation,
beginning with the word ``where''; by revising sections 7.6, 7.6.4,
and 7.6.5 and by adding new sections 7.7 and 7.8 (without revising
the Figures for Appendix A that appear at the end of section 7 to
Appendix A) to read as follows:
7. Calculations
* * * * *
7.2.1 Pollutant Concentration and Diluent Monitors
* * * * *
Where:
CE = Calibration error as a percentage of the span of the
instrument.
R = Reference value of zero or upscale (high-level or mid-level, as
applicable) calibration gas introduced into the monitoring system.
A = Actual monitoring system response to the calibration gas.
S = Span of the instrument, as specified in section 2 of this
appendix.
7.2.2 Flow Monitor Calibration Error
* * * * *
Where:
CE = Calibration error as a percentage of span.
R = Low or high level reference value specified in section 2.2.2.1
of this appendix.
A = Actual flow monitor response to the reference value.
S = Flow monitor calibration span value as determined under section
2.1.4.2 of this appendix.
* * * * *
7.6 Bias Test and Adjustment Factor
Test the following relative accuracy test audit data sets for
bias: SO2 pollutant concentration monitors; flow
monitors; NOX concentration monitoring systems used to
determine NOX mass emissions, as defined in
Sec. 75.71(a)(2); and NOX-diluent continuous emission
monitoring systems, using the procedures outlined in section 7.6.1
through 7.6.5 of this appendix. For multiple-load flow RATAs,
perform a bias test at each load level designated as normal under
section 6.5.2.1 of this appendix.
* * * * *
7.6.4 Bias Test
If, for the relative accuracy test audit data set being tested,
the mean difference, d, is less than or equal to the absolute value
of the confidence coefficient, | cc |, the monitor or monitoring
system has passed the bias test. If the mean difference, d, is
greater than the absolute value of the confidence coefficient, | cc
|, the monitor or monitoring system has failed to meet the bias test
requirement.
7.6.5 Bias Adjustment
(a) If the monitor or monitoring system fails to meet the bias
test requirement, adjust the value obtained from the monitor using
the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.005
Where:
CEMi Monitor = Data (measurement) provided by
the monitor at time i.
CEMi Adjusted = Data value, adjusted for bias,
at time i.
BAF = Bias adjustment factor, defined by:
[GRAPHIC] [TIFF OMITTED] TR26MY99.006
Where:
BAF = Bias adjustment factor, calculated to the nearest thousandth.
d = Arithmetic mean of the difference obtained during the failed
bias test using Equation A-7.
CEMavg = Mean of the data values provided by the monitor
during the failed bias test.
(b) For single-load RATAs of SO2 pollutant
concentration monitors, NOX concentration monitoring
systems, and NOX-diluent monitoring systems and for the
single-load flow RATAs required or allowed under section 6.5.2 of
this appendix and sections 2.3.1.3(b) and 2.3.1.3(c) of appendix B
to this part, the appropriate BAF is determined directly from the
RATA results at normal load, using Equation A-12. Notwithstanding,
when a NOX concentration CEMS or an SO2 CEMS
or a NOX-diluent CEMS installed on a low-emitting
affected unit (i.e., average SO2 or NOX
concentration during the RATA 250 ppm or average
NOX emission rate 0.200 lb/mmBtu) meets the
normal 10.0 percent relative accuracy specification (as calculated
using Equation A-10) or the alternate relative accuracy
specification in section 3.3 of this appendix for low-emitters, but
fails the bias test, the BAF may either be determined using Equation
A-12, or a default BAF of 1.111 may be used.
(c) For 2-load or 3-load flow RATAs, when only one load level
(low, mid or high) has been designated as normal under section
6.5.2.1 of this appendix and the bias test is passed at the normal
load level, apply a BAF of 1.000 to the subsequent flow rate data.
If the bias test is failed at the normal load level, use Equation A-
12 to calculate the normal load BAF and then perform an additional
bias test at the second most frequently-used load level, as
determined under section 6.5.2.1 of this appendix. If the bias test
is passed at this second load level, apply the normal load BAF to
the subsequent flow rate data. If the bias test is failed at this
second load level, use Equation A-12 to calculate the BAF at the
second load level and apply the higher of the two BAFs (either from
the normal load level or from the second load level) to the
subsequent flow rate data.
(d) For 2-load or 3-load flow RATAs, when two load levels have
been designated as normal under section 6.5.2.1 of this appendix and
the bias test is passed at both normal load levels, apply a BAF of
1.000 to the subsequent flow rate data. If the bias test is failed
at one of the normal load levels but not at the other, use Equation
A-12 to calculate the BAF for the normal load level at which the
bias test was failed and apply that BAF to the subsequent flow rate
data. If the bias test is failed at both designated normal load
levels, use Equation A-12 to calculate the BAF at each normal load
level and apply the higher of the two BAFs to the subsequent flow
rate data.
(e) Each time a RATA is passed and the appropriate bias
adjustment factor has been determined, apply the BAF prospectively
to all monitoring system data, beginning with the first clock hour
following the hour in which the RATA was completed. For a 2-load
flow RATA, the ``hour in which the RATA was completed'' refers to
the hour in which the testing at both loads was completed; for a 3-
load RATA, it refers to the hour in which the testing at all three
loads was completed.
(f) Use the bias-adjusted values in computing substitution
values in the missing data procedure, as specified in subpart D of
this part, and in reporting the concentration of SO2, the
flow rate, the average NOX emission rate, the unit heat
input, and the calculated mass emissions of SO2 and
CO2 during the quarter and calendar year, as specified in
subpart G of this part. In addition, when using a NOX
concentration monitoring system and a flow monitor to calculate
NOX mass emissions under subpart H of this part, use
bias-adjusted values for NOX concentration and flow rate
in the mass emission calculations and use bias-adjusted
NOX concentrations to compute the appropriate
substitution values for NOX concentration in the missing
data routines under subpart D of this part.
* * * * *
7.7 Reference Flow-to-Load Ratio or Gross Heat Rate
(a) Except as provided in section 7.8 of this appendix, the
owner or operator shall determine Rref, the reference
value of the ratio of flow rate to unit load, each time that a
passing flow RATA is performed at a load level designated as normal
in section 6.5.2.1 of this appendix. The owner or operator shall
report the current value of Rref in the electronic
quarterly report required under Sec. 75.64 and shall also report the
completion date of the associated RATA. If two load levels have been
designated as normal under
[[Page 28644]]
section 6.5.2.1 of this appendix, the owner or operator shall
determine a separate Rref value for each of the normal
load levels. The requirements of this section shall become effective
as of April 1, 2000. The reference flow-to-load ratio shall be
calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR26MY99.007
Where:
Rref = Reference value of the flow-to-load ratio, from
the most recent normal-load flow RATA, scfh/megawatts or scfh/1000
lb/hr of steam.
Qref = Average stack gas volumetric flow rate measured by
the reference method during the normal-load RATA, scfh.
Lavg = Average unit load during the normal-load flow
RATA, megawatts or 1000 lb/hr of steam.
(b) In Equation A-13, for a common stack, Lavg shall
be the sum of the operating loads of all units that discharge
through the stack. For a unit that discharges its emissions through
multiple stacks (except for a discharge configuration consisting of
a main stack and a bypass stack), Qref will be the sum of
the total volumetric flow rates that discharge through all of the
stacks. For a unit with a multiple stack discharge configuration
consisting of a main stack and a bypass stack (e.g., a unit with a
wet SO2 scrubber), determine Qref separately
for each stack at the time of the normal load flow RATA. Round off
the value of Rref to two decimal places.
(c) In addition to determining Rref or as an
alternative to determining Rref, a reference value of the
gross heat rate (GHR) may be determined. In order to use this
option, quality assured diluent gas (CO2 or
O2) must be available for each hour of the most recent
normal-load flow RATA. The reference value of the GHR shall be
determined as follows:
[GRAPHIC] [TIFF OMITTED] TR26MY99.008
Where:
(GHR)ref = Reference value of the gross heat rate at the
time of the most recent normal-load flow RATA, Btu/kwh or Btu/lb
steam load.
(Heat Input)avg = Average hourly heat input during the
normal-load flow RATA, as determined using the applicable equation
in appendix F to this part, mmBtu/hr.
Lavg = Average unit load during the normal-load flow
RATA, megawatts or 1000 lb/hr of steam.
(d) In the calculation of (Heat Input)avg, use
Qref, the average volumetric flow rate measured by the
reference method during the RATA, and use the average diluent gas
concentration measured during the flow RATA.
7.8 Flow-to-Load Test Exemptions
The requirements of this section apply beginning on April 1,
2000. For complex stack configurations (e.g., when the effluent from
a unit is divided and discharges through multiple stacks in such a
manner that the flow rate in the individual stacks cannot be
correlated with unit load), the owner or operator may petition the
Administrator under Sec. 75.66 for an exemption from the
requirements of section 7.7 of this appendix. The petition must
include sufficient information and data to demonstrate that a flow-
to-load or gross heat rate evaluation is infeasible for the complex
stack configuration.
Appendix B to Part 75--Quality Assurance and Quality Control Procedures
60. Appendix B to part 75 is amended by revising sections 1 and
1.1; adding sections 1.1.1 through 1.1.3; revising section 1.2;
adding sections 1.2.1 through 1.2.4; revising section 1.3; adding
sections 1.3.1 through 1.3.6; revising section 1.4; adding sections
1.4.1 through 1.4.3; and removing sections 1.5 and 1.6 to read as
follows:
1. Quality Assurance/Quality Control Program
Develop and implement a quality assurance/quality control (QA/
QC) program for the continuous emission monitoring systems, excepted
monitoring systems approved under appendix D or E to this part, and
alternative monitoring systems under subpart E of this part, and
their components. At a minimum, include in each QA/QC program a
written plan that describes in detail (or that refers to separate
documents containing) complete, step-by-step procedures and
operations for each of the following activities. Upon request from
regulatory authorities, the source shall make all procedures,
maintenance records, and ancillary supporting documentation from the
manufacturer (e.g., software coefficients and troubleshooting
diagrams) available for review during an audit.
1.1 Requirements for All Monitoring Systems
1.1.1 Preventive Maintenance
Keep a written record of procedures needed to maintain the
monitoring system in proper operating condition and a schedule for
those procedures. This shall, at a minimum, include procedures
specified by the manufacturers of the equipment and, if applicable,
additional or alternate procedures developed for the equipment.
1.1.2 Recordkeeping and Reporting
Keep a written record describing procedures that will be used to
implement the recordkeeping and reporting requirements in subparts
E, F, and G and appendices D and E to this part, as applicable.
1.1.3 Maintenance Records
Keep a record of all testing, maintenance, or repair activities
performed on any monitoring system or component in a location and
format suitable for inspection. A maintenance log may be used for
this purpose. The following records should be maintained: date,
time, and description of any testing, adjustment, repair,
replacement, or preventive maintenance action performed on any
monitoring system and records of any corrective actions associated
with a monitor's outage period. Additionally, any adjustment that
recharacterizes a system's ability to record and report emissions
data must be recorded (e.g., changing of flow monitor or moisture
monitoring system polynomial coefficients, K factors or mathematical
algorithms, changing of temperature and pressure coefficients and
dilution ratio settings), and a written explanation of the
procedures used to make the adjustment(s) shall be kept.
1.2 Specific Requirements for Continuous Emissions Monitoring Systems
1.2.1 Calibration Error Test and Linearity Check Procedures
Keep a written record of the procedures used for daily
calibration error tests and linearity checks (e.g., how gases are to
be injected, adjustments of flow rates and pressure, introduction of
reference values, length of time for injection of calibration gases,
steps for obtaining calibration error or error in linearity,
determination of interferences, and when calibration adjustments
should be made). Identify any calibration error test and linearity
check procedures specific to the continuous emission monitoring
system that vary from the procedures in appendix A to this part.
1.2.2 Calibration and Linearity Adjustments
Explain how each component of the continuous emission monitoring
system will be adjusted to provide correct responses to calibration
gases, reference values, and/or indications of interference both
initially and after repairs or corrective action. Identify
equations, conversion factors and other factors affecting
calibration of each continuous emission monitoring system.
1.2.3 Relative Accuracy Test Audit Procedures
Keep a written record of procedures and details peculiar to the
installed continuous emission monitoring systems that are to be used
for relative accuracy test audits, such as sampling and analysis
methods.
1.2.4 Parametric Monitoring for Units With Add-on Emission Controls
The owner or operator shall keep a written (or electronic)
record including a list of operating parameters for the add-on
SO2 or NOX emission controls, including
parameters in Sec. 75.55(b) or Sec. 75.58(b), as applicable, and the
range of each operating parameter that
[[Page 28645]]
indicates the add-on emission controls are operating properly. The
owner or operator shall keep a written (or electronic) record of the
parametric monitoring data during each SOX or
NO2 missing data period.
1.3 Specific Requirements for Excepted Systems Approved Under
Appendices D and E
1.3.1 Fuel Flowmeter Accuracy Test Procedures
Keep a written record of the specific fuel flowmeter accuracy
test procedures. These may include: standard methods or
specifications listed in and section 2.1.5.1 of appendix D to this
part and incorporated by reference under Sec. 75.6; the procedures
of sections 2.1.5.2 or 2.1.7 of appendix D to this part; or other
methods approved by the Administrator through the petition process
of Sec. 75.66(c).
1.3.2 Transducer or Transmitter Accuracy Test Procedures
Keep a written record of the procedures for testing the accuracy
of transducers or transmitters of an orifice-, nozzle-, or venturi-
type fuel flowmeter under section 2.1.6 of appendix D to this part.
These procedures should include a description of equipment used,
steps in testing, and frequency of testing.
1.3.3 Fuel Flowmeter, Transducer, or Transmitter Calibration and
Maintenance Records
Keep a record of adjustments, maintenance, or repairs performed
on the fuel flowmeter monitoring system. Keep records of the data
and results for fuel flowmeter accuracy tests and transducer
accuracy tests, consistent with appendix D to this part.
1.3.4 Primary Element Inspection Procedures
Keep a written record of the standard operating procedures for
inspection of the primary element (i.e., orifice, venturi, or
nozzle) of an orifice-, venturi-, or nozzle-type fuel flowmeter.
Examples of the types of information to be included are: what to
examine on the primary element; how to identify if there is
corrosion sufficient to affect the accuracy of the primary element;
and what inspection tools (e.g., baroscope), if any, are used.
1.3.5 Fuel Sampling Method and Sample Retention
Keep a written record of the standard procedures used to perform
fuel sampling, either by utility personnel or by fuel supply company
personnel. These procedures should specify the portion of the ASTM
method used, as incorporated by reference under Sec. 75.6, or other
methods approved by the Administrator through the petition process
of Sec. 75.66(c). These procedures should describe safeguards for
ensuring the availability of an oil sample (e.g., procedure and
location for splitting samples, procedure for maintaining sample
splits on site, and procedure for transmitting samples to an
analytical laboratory). These procedures should identify the ASTM
analytical methods used to analyze sulfur content, gross calorific
value, and density, as incorporated by reference under Sec. 75.6, or
other methods approved by the Administrator through the petition
process of Sec. 75.66(c).
1.3.6 Appendix E Monitoring System Quality Assurance Information
Identify the unit manufacturer's recommended range of quality
assurance- and quality control-related operating parameters. Keep
records of these operating parameters for each hour of unit
operation (i.e., fuel combustion). Keep a written record of the
procedures used to perform NOX emission rate testing.
Keep a copy of all data and results from the initial and from the
most recent NOX emission rate testing, including the
values of quality assurance parameters specified in section 2.3 of
appendix E to this part.
1.4 Requirements for Alternative Systems Approved Under Subpart E
1.4.1 Daily Quality Assurance Tests
Explain how the daily assessment procedures specific to the
alternative monitoring system are to be performed.
1.4.2 Daily Quality Assurance Test Adjustments
Explain how each component of the alternative monitoring system
will be adjusted in response to the results of the daily
assessments.
1.4.3 Relative Accuracy Test Audit Procedures
Keep a written record of procedures and details peculiar to the
installed alternative monitoring system that are to be used for
relative accuracy test audits, such as sampling and analysis
methods.
61. Appendix B to part 75 is amended by:
a. Revising the first paragraph of section 2.1.1, revising
sections 2.1.3 and 2.1.4; revising paragraph (1) of section 2.1.5.1;
revising sections 2.2 through 2.2.3; adding sections 2.2.4 through
2.2.5.3; revising sections 2.3 and 2.3.1; adding sections 2.3.1.1
through 2.3.1.4; revising sections 2.3.2 and 2.3.3; and adding
section 2.3.4;
b. Redesignating existing section 2.4 as section 2.5;
c. Adding new section 2.4; and
d. Revising Figures 1 and 2 at the end of appendix B to read as
follows:
2. Frequency of Testing
* * * * *
2.1 * * *
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.
* * * * *
2.1.3 Additional Calibration Error Tests and Calibration Adjustments
(a) In addition to the daily calibration error tests required
under section 2.1.1 of this appendix, a calibration error test of a
monitor shall be performed in accordance with section 2.1.1 of this
appendix, as follows: whenever a daily calibration error test is
failed; whenever a monitoring system is returned to service
following repair or corrective maintenance that could affect the
monitor's ability to accurately measure and record emissions data;
or after making certain calibration adjustments, as described in
this section. Except in the case of the routine calibration
adjustments described in this section, data from the monitor are
considered invalid until the required additional calibration error
test has been successfully completed.
(b) Routine calibration adjustments of a monitor are permitted
after any successful calibration error test. These routine
adjustments shall be made so as to bring the monitor readings as
close as practicable to the known tag values of the calibration
gases or to the actual value of the flow monitor reference signals.
An additional calibration error test is required following routine
calibration adjustments where the monitor's calibration has been
physically adjusted (e.g., by turning a potentiometer) to verify
that the adjustments have been made properly. An additional
calibration error test is not required, however, if the routine
calibration adjustments are made by means of a mathematical
algorithm programmed into the data acquisition and handling system.
The EPA recommends that routine calibration adjustments be made, at
a minimum, whenever the daily calibration error exceeds the limits
of the applicable performance specification in appendix A to this
part for the pollutant concentration monitor, CO2 or
O2 monitor, or flow monitor.
(c) Additional (non-routine) calibration adjustments of a
monitor are permitted prior to (but not during) linearity checks and
RATAs and at other times, provided that an appropriate technical
justification is included in the quality control program required
under section 1 of this appendix. The allowable non-routine
adjustments are as follows. The owner or operator may physically
adjust the calibration of a monitor (e.g., by means of a
potentiometer), provided that the post-adjustment zero and upscale
responses of the monitor are within the performance specifications
of the instrument given in section 3.1 of appendix A to this part.
An additional calibration error test is required following such
adjustments to verify that the monitor is operating within the
performance specifications at both the zero and upscale calibration
levels.
2.1.4 Data Validation
(a) An out-of-control period occurs when the calibration error
of an SO2 or NOX pollutant concentration
monitor exceeds 5.0 percent of the span value (or exceeds 10 ppm,
for span values <200 ppm), when the calibration error of a
CO2 or O2 monitor (including O2
monitors used to measure CO2 emissions or percent
moisture) exceeds 1.0 percent O2 or CO2, or
when the calibration
[[Page 28646]]
error of a flow monitor or a moisture sensor exceeds 6.0 percent of
the span value, which is twice the applicable specification of
appendix A to this part. Notwithstanding, a differential pressure-
type flow monitor for which the calibration error exceeds 6.0
percent of the span value shall not be considered out-of-control if
R-A, the absolute value of the difference between
the monitor response and the reference value in Equation A-6, is
0.02 inches of water. The out-of-control period begins
upon failure of the calibration error test and ends upon completion
of a successful calibration error test. Note, that if a failed
calibration, corrective action, and successful calibration error
test occur within the same hour, emission data for that hour
recorded by the monitor after the successful calibration error test
may be used for reporting purposes, provided that two or more valid
readings are obtained as required by Sec. 75.10. A NOX-
diluent continuous emission monitoring system is considered out-of-
control if the calibration error of either component monitor exceeds
twice the applicable performance specification in appendix A to this
part. Emission data shall not be reported from an out-of-control
monitor.
(b) An out-of-control period also occurs whenever interference
of a flow monitor is identified. The out-of-control period begins
with the hour of completion of the failed interference check and
ends with the hour of completion of an interference check that is
passed.
2.1.5 * * *
2.1.5.1 * * *
(1) Data from a monitoring system are invalid, beginning with
the first hour following the expiration of a 26-hour data validation
period or beginning with the first hour following the expiration of
an 8-hour start-up grace period (as provided under section 2.1.5.2
of this appendix), if the required subsequent daily assessment has
not been conducted.
* * * * *
2.2 Quarterly Assessments
For each primary and redundant backup monitor or monitoring
system, perform the following quarterly assessments. This
requirement is applies as of the calendar quarter following the
calendar quarter in which the monitor or continuous emission
monitoring system is provisionally certified.
2.2.1 Linearity Check
Perform a linearity check, in accordance with the procedures in
section 6.2 of appendix A to this part, for each primary and
redundant backup SO2 and NOX pollutant
concentration monitor and each primary and redundant backup
CO2 or O2 monitor (including O2
monitors used to measure CO2 emissions or to continuously
monitor moisture) at least once during each QA operating quarter, as
defined in Sec. 72.2 of this chapter. For units using both a low and
high span value, a linearity check is required only on the range(s)
used to record and report emission data during the QA operating
quarter. Conduct the linearity checks no less than 30 days apart, to
the extent practicable. The data validation procedures in section
2.2.3(e) of this appendix shall be followed.
2.2.2 Leak Check
For differential pressure flow monitors, perform a leak check of
all sample lines (a manual check is acceptable) at least once during
each QA operating quarter. For this test, the unit does not have to
be in operation. Conduct the leak checks no less than 30 days apart,
to the extent practicable. If a leak check is failed, follow the
applicable data validation procedures in section 2.2.3(f) of this
appendix.
2.2.3 Data Validation
(a) A linearity check shall not be commenced if the monitoring
system is operating out-of-control with respect to any of the daily
or semiannual quality assurance assessments required by sections 2.1
and 2.3 of this appendix or with respect to the additional
calibration error test requirements in section 2.1.3 of this
appendix.
(b) Each required linearity check shall be done according to
paragraph (b)(1), (b)(2) or (b)(3) of this section:
(1) The linearity check may be done ``cold,'' i.e., with no
corrective maintenance, repair, calibration adjustments, re-
linearization or reprogramming of the monitor prior to the test.
(2) The linearity check may be done after performing only the
routine or non-routine calibration adjustments described in section
2.1.3 of this appendix at the various calibration gas levels (zero,
low, mid or high), but no other corrective maintenance, repair, re-
linearization or reprogramming of the monitor. Trial gas injection
runs may be performed after the calibration adjustments and
additional adjustments within the allowable limits in section 2.1.3
of this appendix may be made prior to the linearity check, as
necessary, to optimize the performance of the monitor. The trial gas
injections need not be reported, provided that they meet the
specification for trial gas injections in
Sec. 75.20(b)(3)(vii)(E)(1). However, if, for any trial injection,
the specification in Sec. 75.20(b)(3)(vii)(E)(1) is not met, the
trial injection shall be counted as an aborted linearity check.
(3) The linearity check may be done after repair, corrective
maintenance or reprogramming of the monitor. In this case, the
monitor shall be considered out-of-control from the hour in which
the repair, corrective maintenance or reprogramming is commenced
until the linearity check has been passed. Alternatively, the data
validation procedures and associated timelines in
Secs. 75.20(b)(3)(ii) through (ix) may be followed upon completion
of the necessary repair, corrective maintenance, or reprogramming.
If the procedures in Sec. 75.20(b)(3) are used, the words ``quality
assurance'' apply instead of the word ``recertification''.
(c) Once a linearity check has been commenced, the test shall be
done hands-off. That is, no adjustments of the monitor are permitted
during the linearity test period, other than the routine calibration
adjustments following daily calibration error tests, as described in
section 2.1.3 of this appendix.
(d) If a daily calibration error test is failed during a
linearity test period, prior to completing the test, the linearity
test 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 linearity test shall not be commenced until the
monitor has successfully completed a calibration error test.
(e) An out-of-control period occurs when a linearity test is
failed (i.e., when the error in linearity at any of the three
concentrations in the quarterly linearity check (or any of the six
concentrations, when both ranges of a single analyzer with a dual
range are tested) exceeds the applicable specification in section
3.2 of appendix A to this part) or when a linearity test is aborted
due to a problem with the monitor or monitoring system. For a
NOX-diluent or SO2-diluent continuous emission
monitoring system, the system is considered out-of-control if either
of the component monitors exceeds the applicable specification in
section 3.2 of appendix A to this part or if the linearity test of
either component is aborted due to a problem with the monitor. The
out-of-control period begins with the hour of the failed or aborted
linearity check and ends with the hour of completion of a
satisfactory linearity check following corrective action and/or
monitor repair, 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 (ix) has been selected, in
which case the beginning and end of the out-of-control period shall
be determined in accordance with Secs. 75.20(b)(3)(vii)(A) and (B).
Note that a monitor shall not be considered out-of-control when a
linearity test is aborted for a reason unrelated to the monitor's
performance (e.g., a forced unit outage).
(f) No more than four successive calendar quarters shall elapse
after the quarter in which a linearity check of a monitor or
monitoring system (or range of a monitor or monitoring system) was
last performed without a subsequent linearity test having been
conducted. If a linearity test has not been completed by the end of
the fourth calendar quarter since the last linearity test, then the
linearity test must be completed within a 168 unit operating hour or
stack operating hour ``grace period'' (as provided in section 2.2.4
of this appendix) following the end of the fourth successive elapsed
calendar quarter, or data from the CEMS (or range) will become
invalid.
(g) An out-of-control period also occurs when a flow monitor
sample line leak is detected. The out-of-control period begins with
the hour of the failed leak check and ends with the hour of a
satisfactory leak check following corrective action.
(h) For each monitoring system, report the results of all
completed and partial linearity tests that affect data validation
(i.e., all completed, passed linearity checks; all completed, failed
linearity checks; and all linearity checks aborted due to a problem
with the monitor, including trial gas injections counted as failed
test attempts under paragraph (b)(2) of this section or
[[Page 28647]]
under Sec. 75.20(b)(3)(vii)(F)), in the quarterly report required
under Sec. 75.64. Note that linearity attempts which are aborted or
invalidated due to problems with the reference calibration gases or
due to operational problems with the affected unit(s) need not be
reported. Such partial tests do not affect the validation status of
emission data recorded by the monitor. A record of all linearity
tests, trial gas injections and test attempts (whether reported or
not) must be kept on-site as part of the official test log for each
monitoring system.
2.2.4 Linearity and Leak Check Grace Period
(a) When a required linearity test or flow monitor leak check
has not been completed by the end of the QA operating quarter in
which it is due or if, due to infrequent operation of a unit or
infrequent use of a required high range of a monitor or monitoring
system, four successive calendar quarters have elapsed after the
quarter in which a linearity check of a monitor or monitoring system
(or range) was last performed without a subsequent linearity test
having been done, the owner or operator has a grace period of 168
consecutive unit operating hours, as defined in Sec. 72.2 of this
chapter (or, for monitors installed on common stacks or bypass
stacks, 168 consecutive stack operating hours, as defined in
Sec. 72.2 of this chapter) in which to perform a linearity test or
leak check of that monitor or monitoring system (or range). The
grace period begins with the first unit or stack operating hour
following the calendar quarter in which the linearity test was due.
Data validation during a linearity or leak check grace period shall
be done in accordance with the applicable provisions in section
2.2.3 of this appendix.
(b) If, at the end of the 168 unit (or stack) operating hour
grace period, the required linearity test or leak check has not been
completed, data from the monitoring system (or range) shall be
invalid, beginning with the hour following the expiration of the
grace period. Data from the monitoring system (or range) remain
invalid until the hour of completion of a subsequent successful
hands-off linearity test or leak check of the monitor or monitoring
system (or range). Note that when a linearity test or a leak check
is conducted within a grace period for the purpose of satisfying the
linearity test or leak check requirement from a previous QA
operating quarter, the results of that linearity test or leak check
may only be used to meet the linearity check or leak check
requirement of the previous quarter, not the quarter in which the
missed linearity test or leak check is completed.
2.2.5 Flow-to-Load Ratio or Gross Heat Rate Evaluation
(a) Applicability and methodology. The provisions of this
section apply beginning on April 1, 2000. Unless exempted by an
approved petition in accordance with section 7.8 of appendix A to
this part, the owner or operator shall, for each flow rate
monitoring system installed on each unit, common stack or multiple
stack, evaluate the flow-to-load ratio quarterly, i.e., for each QA
operating quarter (as defined in Sec. 72.2 of this chapter). At the
end of each QA operating quarter, the owner or operator shall use
Equation B-1 to calculate the flow-to-load ratio for every hour
during the quarter in which: the unit (or combination of units, for
a common stack) operated within 10.0 percent of
Lavg, the average load during the most recent normal-load
flow RATA; and a quality assured hourly average flow rate was
obtained with a certified flow rate monitor.
[GRAPHIC] [TIFF OMITTED] TR26MY99.009
Where:
Rh = Hourly value of the flow-to-load ratio, scfh/
megawatts or scfh/1000 lb/hr of steam load.
Qh = Hourly stack gas volumetric flow rate, as measured
by the flow rate monitor, scfh.
Lh = Hourly unit load, megawatts or 1000 lb/hr of steam;
must be within 10.0 percent of Lavg during
the most recent normal-load flow RATA.
(1) In Equation B-1, the owner or operator may use either bias-
adjusted flow rates or unadjusted flow rates, provided that all of
the ratios are calculated the same way. For a common stack,
Lh shall be the sum of the hourly operating loads of all
units that discharge through the stack. For a unit that discharges
its emissions through multiple stacks (except when one of the stacks
is a bypass stack) or that monitors its emissions in multiple
breechings, Qh will be the combined hourly volumetric
flow rate for all of the stacks or ducts. For a unit with a multiple
stack discharge configuration consisting of a main stack and a
bypass stack, each of which has a certified flow monitor (e.g., a
unit with a wet SO2 scrubber), calculate the hourly flow-
to-load ratios separately for each stack. Round off each value of
Rh to two decimal places.
(2) Alternatively, the owner or operator may calculate the
hourly gross heat rates (GHR) in lieu of the hourly flow-to-load
ratios. The hourly GHR shall be determined only for those hours in
which quality assured flow rate data and diluent gas (CO2
or O2) concentration data are both available from a
certified monitor or monitoring system or reference method. If this
option is selected, calculate each hourly GHR value as follows:
[GRAPHIC] [TIFF OMITTED] TR26MY99.010
where:
(GHR)h = Hourly value of the gross heat rate, Btu/kwh or
Btu/lb steam load.
(Heat Input)h = Hourly heat input, as determined from the
quality assured flow rate and diluent data, using the applicable
equation in appendix F to this part, mmBtu/hr.
Lh = Hourly unit load, megawatts or 1000 lb/hr of steam;
must be within 10.0 percent of Lavg during
the most recent normal-load flow RATA.
(3) In Equation B-1a, the owner or operator may either use bias-
adjusted flow rates or unadjusted flow rates in the calculation of
(Heat Input)h, provided that all of the heat input values
are determined in the same manner.
(4) The owner or operator shall evaluate the calculated hourly
flow-to-load ratios (or gross heat rates) as follows. A separate
data analysis shall be performed for each primary and each redundant
backup flow rate monitor used to record and report data during the
quarter. Each analysis shall be based on a minimum of 168 recorded
hourly average flow rates. When two RATA load levels are designated
as normal, the analysis shall be performed at the higher load level,
unless there are fewer than 168 data points available at that load
level, in which case the analysis shall be performed at the lower
load level. If, for a particular flow monitor, fewer than 168 hourly
flow-to-load ratios (or GHR values) are available at any of the load
levels designated as normal, a flow-to-load (or GHR) evaluation is
not required for that monitor for that calendar quarter.
(5) For each flow monitor, use Equation B-2 in this appendix to
calculate Eh, the absolute percentage difference between
each hourly Rh value and Rref, the reference
value of the flow-to-load ratio, as determined in accordance with
section 7.7 of appendix A to this part. Note that Rref
shall always be based upon the most recent normal-load RATA, even if
that RATA was performed in the calendar quarter being evaluated.
[[Page 28648]]
[GRAPHIC] [TIFF OMITTED] TR26MY99.011
where:
Eh = Absolute percentage difference between the hourly
average flow-to-load ratio and the reference value of the flow-to-
load ratio at normal load.
Rh = The hourly average flow-to-load ratio, for each flow
rate recorded at a load level within # 10.0 percent of
Lavg.
Rref = The reference value of the flow-to-load ratio from
the most recent normal-load flow RATA, determined in accordance with
section 7.7 of appendix A to this part.
(6) Equation B-2 shall be used in a consistent manner. That is,
use Rref and Rh if the flow-to-load ratio is
being evaluated, and use (GHR)ref and (GHR)h
if the gross heat rate is being evaluated. Finally, calculate
Ef, the arithmetic average of all of the hourly
Eh values. The owner or operator shall report the results
of each quarterly flow-to-load (or gross heat rate) evaluation, as
determined from Equation B-2, in the electronic quarterly report
required under Sec. 75.64.
(b) Acceptable results. The results of a quarterly flow-to-load
(or gross heat rate) evaluation are acceptable, and no further
action is required, if the calculated value of Ef is less
than or equal to: (1) 15.0 percent, if Lavg for the most
recent normal-load flow RATA is 60 megawatts (or
500 klb/hr of steam) and if unadjusted flow rates were
used in the calculations; or (2) 10.0 percent, if Lavg
for the most recent normal-load flow RATA is 60 megawatts
(or 500 klb/hr of steam) and if bias-adjusted flow rates
were used in the calculations; or (3) 20.0 percent, if
Lavg for the most recent normal-load flow RATA is <60
megawatts (or <500 klb/hr of steam) and if unadjusted flow rates
were used in the calculations; or (4) 15.0 percent, if
Lavg for the most recent normal-load flow RATA is <60
megawatts (or <500 klb/hr of steam) and if bias-adjusted flow rates
were used in the calculations. If Ef is above these
limits, the owner or operator shall either: implement Option 1 in
section 2.2.5.1 of this appendix; or perform a RATA in accordance
with Option 2 in section 2.2.5.2 of this appendix; or re-examine the
hourly data used for the flow-to-load or GHR analysis and
recalculate Ef, after excluding all non-representative
hourly flow rates.
(c) Recalculation of Ef. If the owner or operator
chooses to recalculate Ef, the flow rates for the
following hours are considered non-representative and may be
excluded from the data analysis:
(1) Any hour in which the type of fuel combusted was different
from the fuel burned during the most recent normal-load RATA. For
purposes of this determination, the type of fuel is different if the
fuel is in a different state of matter (i.e., solid, liquid, or gas)
than is the fuel burned during the RATA or if the fuel is a
different classification of coal (e.g., bituminous versus sub-
bituminous);
(2) For a unit that is equipped with an SO2 scrubber
and which always discharges its flue gases to the atmosphere through
a single stack, any hour in which the SO2 scrubber was
bypassed;
(3) Any hour in which ``ramping'' occurred, i.e., the hourly
load differed by more than 15.0 percent from the load
during the preceding hour or the subsequent hour;
(4) For a unit with a multiple stack discharge configuration
consisting of a main stack and a bypass stack, any hour in which the
flue gases were discharged through both stacks;
(5) If a normal-load flow RATA was performed and passed during
the quarter being analyzed, any hour prior to completion of that
RATA; and
(6) If a problem with the accuracy of the flow monitor was
discovered during the quarter and was corrected (as evidenced by
passing the abbreviated flow-to-load test in section 2.2.5.3 of this
appendix), any hour prior to completion of the abbreviated flow-to-
load test.
(7) After identifying and excluding all non-representative
hourly data in accordance with paragraphs (c)(1) through (6) of this
section, the owner or operator may analyze the remaining data a
second time. At least 168 representative hourly ratios or GHR values
must be available to perform the analysis; otherwise, the flow-to-
load (or GHR) analysis is not required for that monitor for that
calendar quarter.
(8) If, after re-analyzing the data, Ef meets the
applicable limit in paragraph (b)(1), (b)(2), (b)(3), or (b)(4) of
this section, no further action is required. If, however,
Ef is still above the applicable limit, the monitor shall
be declared out-of-control, beginning with the first hour of the
quarter following the quarter in which Ef exceeded the
applicable limit. The owner or operator shall then either implement
Option 1 in section 2.2.5.1 of this appendix or Option 2 in section
2.2.5.2 of this appendix.
2.2.5.1 Option 1
Within two weeks of the end of the calendar quarter for which
the Ef value is above the applicable limit, investigate
and troubleshoot the applicable flow monitor(s). Evaluate the
results of each investigation as follows:
(a) If the investigation fails to uncover a problem with the
flow monitor, a RATA shall be performed in accordance with Option 2
in section 2.2.5.2 of this appendix.
(b) If a problem with the flow monitor is identified through the
investigation (including the need to re-linearize the monitor by
changing the polynomial coefficients or K factor(s)), corrective
actions shall be taken. All corrective actions (e.g., non-routine
maintenance, repairs, major component replacements, re-linearization
of the monitor, etc.) shall be documented in the operation and
maintenance records for the monitor. Data from the monitor shall
remain invalid until a probationary calibration error test of the
monitor is passed following completion of all corrective actions, at
which point data from the monitor are conditionally valid. The owner
or operator then either may complete the abbreviated flow-to-load
test in section 2.2.5.3 of this appendix, or, if the corrective
action taken has required relinearization of the flow monitor, shall
perform a 3-level RATA.
2.2.5.2 Option 2
Perform a single-load RATA (at a load designated as normal under
section 6.5.2.1 of appendix A to this part) of each flow monitor for
which Ef is outside of the applicable limit. Data from
the monitor remain invalid until the required RATA has been passed.
2.2.5.3 Abbreviated Flow-to-Load Test
(a) The following abbreviated flow-to-load test may be performed
after any documented repair, component replacement, or other
corrective maintenance to a flow monitor (except for changes
affecting the linearity of the flow monitor, such as adjusting the
flow monitor coefficients or K factor(s)) to demonstrate that the
repair, replacement, or other maintenance has not significantly
affected the monitor's ability to accurately measure the stack gas
volumetric flow rate. Data from the monitoring system are considered
invalid from the hour of commencement of the repair, replacement, or
maintenance until the hour in which a probationary calibration error
test is passed following completion of the repair, replacement, or
maintenance and any associated adjustments to the monitor. The
abbreviated flow-to-load test shall be completed within 168 unit
operating hours of the probationary calibration error test (or, for
peaking units, within 30 unit operating days, if that is less
restrictive). Data from the monitor are considered to be
conditionally valid (as defined in Sec. 72.2 of this chapter),
beginning with the hour of the probationary calibration error test.
(b) Operate the unit(s) in such a way as to reproduce, as
closely as practicable, the exact conditions at the time of the most
recent normal-load flow RATA. To achieve this, it is recommended
that the load be held constant to within 5.0 percent of
the average load during the RATA and that the diluent gas
(CO2 or O2) concentration be maintained within
0.5 percent CO2 or O2 of the
average diluent concentration during the RATA. For common stacks, to
the extent practicable, use the same combination of units and load
levels that were used during the RATA. When the process parameters
have been set, record a minimum of six and a maximum of 12
consecutive hourly average flow rates, using the flow monitor(s) for
which Ef was outside the applicable limit. For peaking
units, a minimum of three and a maximum of 12 consecutive hourly
average flow rates are required. Also record the corresponding
hourly load values and, if applicable, the hourly diluent gas
concentrations. Calculate the flow-to-load ratio (or GHR) for each
hour in the test hour period, using Equation B-1 or B-1a. Determine
Eh for each hourly flow-
[[Page 28649]]
to-load ratio (or GHR), using Equation B-2 of this appendix and then
calculate Ef, the arithmetic average of the Eh
values.
(c) The results of the abbreviated flow-to-load test shall be
considered acceptable, and no further action is required if the
value of Ef does not exceed the applicable limit
specified in section 2.2.5 of this appendix. All conditionally valid
data recorded by the flow monitor shall be considered quality
assured, beginning with the hour of the probationary calibration
error test that preceded the abbreviated flow-to-load test. However,
if Ef is outside the applicable limit, all conditionally
valid data recorded by the flow monitor shall be considered invalid
back to the hour of the probationary calibration error test that
preceded the abbreviated flow-to-load test, and a single-load RATA
is required in accordance with section 2.2.5.2 of this appendix. If
the flow monitor must be re-linearized, however, a 3-load RATA is
required.
2.3 Semiannual and Annual Assessments
For each primary and redundant backup monitoring system, perform
relative accuracy assessments either semiannually or annually, as
specified in section 2.3.1.1 or 2.3.1.2 of this appendix, for the
type of test and the performance achieved. This requirement applies
as of the calendar quarter following the calendar quarter in which
the monitoring system is provisionally certified. A summary chart
showing the frequency with which a relative accuracy test audit must
be performed, depending on the accuracy achieved, is located at the
end of this appendix in Figure 2.
2.3.1 Relative Accuracy Test Audit (RATA)
2.3.1.1 Standard RATA Frequencies
(a) Except as otherwise specified in Sec. 75.21(a)(6) or (a)(7)
or in section 2.3.1.2 of this appendix, perform relative accuracy
test audits semiannually, i.e., once every two successive QA
operating quarters (as defined in Sec. 72.2 of this chapter) for
each primary and redundant backup SO2 pollutant
concentration monitor, flow monitor, CO2 pollutant
concentration monitor (including O2 monitors used to
determine CO2 emissions), CO2 or O2
diluent monitor used to determine heat input, moisture monitoring
system, NOX concentration monitoring system,
NOX-diluent continuous emission monitoring system, or
SO2-diluent continuous emission monitoring system. A
calendar quarter that does not qualify as a QA operating quarter
shall be excluded in determining the deadline for the next RATA. No
more than eight successive calendar quarters shall elapse after the
quarter in which a RATA was last performed without a subsequent RATA
having been conducted. If a RATA has not been completed by the end
of the eighth calendar quarter since the quarter of the last RATA,
then the RATA must be completed within a 720 unit (or stack)
operating hour grace period (as provided in section 2.3.3 of this
appendix) following the end of the eighth successive elapsed
calendar quarter, or data from the CEMS will become invalid.
(b) The relative accuracy test audit frequency of a CEMS may be
reduced, as specified in section 2.3.1.2 of this appendix, for primary
or redundant backup monitoring systems which qualify for less frequent
testing. Perform all required RATAs in accordance with the applicable
procedures and provisions in sections 6.5 through 6.5.2.2 of appendix A
to this part and sections 2.3.1.3 and 2.3.1.4 of this appendix.
2.3.1.2 Reduced RATA Frequencies
Relative accuracy test audits of primary and redundant backup
SO2 pollutant concentration monitors, CO2
pollutant concentration monitors (including O2 monitors
used to determine CO2 emissions), CO2 or
O2 diluent monitors used to determine heat input,
moisture monitoring systems, NOX concentration monitoring
systems, flow monitors, NOX-diluent monitoring systems or
SO2-diluent monitoring systems may be performed annually
(i.e., once every four successive QA operating quarters, rather than
once every two successive QA operating quarters) if any of the
following conditions are met for the specific monitoring system
involved:
(a) The relative accuracy during the audit of an SO2
or CO2 pollutant concentration monitor (including an
O2 pollutant monitor used to measure CO2 using
the procedures in appendix F to this part), or of a CO2
or O2 diluent monitor used to determine heat input, or of
a NOX concentration monitoring system, or of a
NOX-diluent monitoring system, or of an SO2-
diluent continuous emissions monitoring system is 7.5
percent;
(b) Prior to January 1, 2000, the relative accuracy during the
audit of a flow monitor is 10.0 percent at each
operating level tested;
(c) On and after January 1, 2000, the relative accuracy during
the audit of a flow monitor is 7.5 percent at each
operating level tested;
(d) For low flow ( 10.0 fps) stacks/ducts, when the
flow monitor fails to achieve a relative accuracy 7.5
percent (10.0 percent if prior to January 1, 2000) during the audit,
but the monitor mean value, calculated using Equation A-7 in
appendix A to this part and converted back to an equivalent velocity
in standard feet per second (fps), is within 1.5 fps of
the reference method mean value, converted to an equivalent velocity
in fps;
(e) For low SO2 or NOX emitting units
(average SO2 or NOX concentrations
250 ppm, when an SO2 pollutant concentration monitor or
NOX concentration monitoring system fails to achieve a
relative accuracy 7.5 percent during the audit, but the
monitor mean value from the RATA is within 12 ppm of
the reference method mean value;
(f) For units with low NOX emission rates (average
NOX emission rate 0.200 lb/mmBtu), when a
NOX-diluent continuous emission monitoring system fails
to achieve a relative accuracy 7.5 percent, but the
monitoring system mean value from the RATA, calculated using
Equation A-7 in appendix A to this part, is within
0.015 lb/mmBtu of the reference method mean value;
(g) For units with low SO2 emission rates (average
SO2 emission rate 0.500 lb/mmBtu), when an
SO2-diluent continuous emission monitoring system fails
to achieve a relative accuracy 7.5 percent, but the
monitoring system mean value from the RATA, calculated using
Equation A-7 in appendix A to this part, is within
0.025 lb/mmBtu of the reference method mean value;
(h) For a CO2 or O2 monitor, when the mean
difference between the reference method values from the RATA and the
corresponding monitor values is within 0.7 percent
CO2 or O2; and
(i) When the relative accuracy of a continuous moisture
monitoring system is 7.5 percent or when the mean
difference between the reference method values from the RATA and the
corresponding monitoring system values is within 1.0
percent H2O.
2.3.1.3 RATA Load Levels and Additional RATA Requirements
(a) For SO2 pollutant concentration monitors,
CO2 pollutant concentration monitors (including
O2 monitors used to determine CO2 emissions),
CO2 or O2 diluent monitors used to determine
heat input, NOX concentration monitoring systems,
moisture monitoring systems, SO2-diluent monitoring
systems and NOX-diluent monitoring systems, the required
semiannual or annual RATA tests shall be done at the load level
designated as normal under section 6.5.2.1 of appendix A to this
part. If two load levels are designated as normal, the required
RATA(s) may be done at either load level.
(b) For flow monitors installed on peaking units and bypass
stacks, all required semiannual or annual relative accuracy test
audits shall be single-load audits at the normal load, as defined in
section 6.5.2.1 of appendix A to this part.
(c) For all other flow monitors, the RATAs shall be performed as
follows:
(1) An annual 2-load flow RATA shall be done at the two most
frequently used load levels, as determined under section 6.5.2.1 of
appendix A to this part.
(2) If the flow monitor is on a semiannual RATA frequency, 2-
load flow RATAs and single-load flow RATAs at normal load may be
performed alternately.
(3) A single-load annual flow RATA, at the most frequently used
load level, may be performed in lieu of the 2-load RATA if the
results of an historical load data analysis show that in the time
period extending from the ending date of the last annual flow RATA
to a date that is no more than 7 days prior to the date of the
current annual flow RATA, the unit has operated at a single load
level (low, mid or high) for 85.0 percent of the time. *
* *
(4) A 3-load RATA, at the low-, mid-, and high-load levels,
determined under section 6.5.2.1 of appendix A to this part, shall
be performed at least once in every period of five consecutive
calendar years.
(5) A 3-load RATA is required whenever a flow monitor is re-
linearized, i.e., when its polynomial coefficients or K factor(s)
are changed.
(6) For all multi-level flow audits, the audit points at
adjacent load levels (e.g., mid and high) shall be separated by no
less than 25.0 percent of the ``range of operation,'' as defined in
section 6.5.2.1 of appendix A to this part.
[[Page 28650]]
(d) A RATA of a moisture monitoring system shall be performed
whenever the coefficient, K factor or mathematical algorithm
determined under section 6.5.7 of appendix A to this part is
changed.
2.3.1.4 Number of RATA Attempts
The owner or operator may perform as many RATA attempts as are
necessary to achieve the desired relative accuracy test audit
frequencies and/or bias adjustment factors. However, the data
validation procedures in section 2.3.2 of this appendix must be
followed.
2.3.2 Data Validation
(a) A RATA shall not commence if the monitoring system is
operating out-of-control with respect to any of the daily and
quarterly quality assurance assessments required by sections 2.1 and
2.2 of this appendix or with respect to the additional calibration
error test requirements in section 2.1.3 of this appendix.
(b) Each required RATA shall be done according to paragraphs
(b)(1), (b)(2) or (b)(3) of this section:
(1) The RATA may be done ``cold,'' i.e., with no corrective
maintenance, repair, calibration adjustments, re-linearization or
reprogramming of the monitoring system prior to the test.
(2) The RATA may be done after performing only the routine or
non-routine calibration adjustments described in section 2.1.3 of
this appendix at the zero and/or upscale calibration gas levels, but
no other corrective maintenance, repair, re-linearization or
reprogramming of the monitoring system. Trial RATA runs may be
performed after the calibration adjustments and additional
adjustments within the allowable limits in section 2.1.3 of this
appendix may be made prior to the RATA, as necessary, to optimize
the performance of the CEMS. The trial RATA runs need not be
reported, provided that they meet the specification for trial RATA
runs in Sec. 75.20(b)(3)(vii)(E)(2). However, if, for any trial run,
the specification in Sec. 75.20(b)(3)(vii)(E)(2) is not met, the
trial run shall be counted as an aborted RATA attempt.
(3) The RATA may be done after repair, corrective maintenance,
re-linearization or reprogramming of the monitoring system. In this
case, the monitoring system shall be considered out-of-control from
the hour in which the repair, corrective maintenance, re-
linearization or reprogramming is commenced until the RATA has been
passed. Alternatively, the data validation procedures and associated
timelines in Secs. 75.20(b)(3)(ii) through (ix) may be followed upon
completion of the necessary repair, corrective maintenance, re-
linearization or reprogramming. If the procedures in
Sec. 75.20(b)(3) are used, the words ``quality assurance'' apply
instead of the word ``recertification.''
(c) Once a RATA is commenced, the test must be done hands-off.
No adjustment of the monitor's calibration is permitted during the
RATA test period, other than the routine calibration adjustments
following daily calibration error tests, as described in section
2.1.3 of this appendix. For 2-level and 3-level flow monitor audits,
no linearization or reprogramming of the monitor is permitted in
between load levels.
(d) For single-load 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. For multiple-load
flow RATAs, each load 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, only the RATA at that load level must be
repeated; the results of any previously-passed RATA(s) at the other
load 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 RATA is required).
(e) If a RATA is failed (that is, if the relative accuracy
exceeds the applicable specification in section 3.3 of appendix A to
this part) or if the RATA is aborted prior to completion due to a
problem with the CEMS, then the CEMS is out-of-control and all
emission data from the CEMS are invalidated prospectively from the
hour in which the RATA is failed or aborted. Data from the CEMS
remain invalid until the hour of completion of a subsequent RATA
that meets the applicable specification in section 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
Secs. 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). Note
that a monitoring system shall not be considered out-of-control when
a RATA is aborted for a reason other than monitoring system
malfunction (see paragraph (h) of this section).
(f) For a 2-level or 3-level flow RATA, if, at any load level, a
RATA is failed or aborted due to a problem with the flow monitor,
the RATA at that load level must be repeated. The flow monitor is
considered out-of-control and data from the monitor are invalidated
from the hour in which the test is failed or aborted and remain
invalid until the passing of a RATA at the failed load level, 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). Flow
RATA(s) that were previously passed at the other load level(s) do
not have to be repeated unless the flow monitor must be re-
linearized following the failed or aborted test. If the flow monitor
is re-linearized, a subsequent 3-load RATA is required.
(g) 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 (or SO2-diluent) monitoring system, if the
CO2 (or O2) RATA is failed, then both the
CO2 (or O2) monitor and the associated
NOX-diluent (or SO2-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 Secs. 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 Secs. 75.20(b)(3)(vii)
(A) and (B).
(h) For each monitoring system, report the results of all
completed and partial RATAs that affect data validation (i.e., all
completed, passed RATAs; all completed, failed RATAs; and all RATAs
aborted due to a problem with the CEMS, including trial RATA runs
counted as failed test attempts under paragraph (b)(2) of this
section or under Sec. 75.20(b)(3)(vii)(F)) in the quarterly report
required under Sec. 75.64. Note that RATA attempts that are aborted
or invalidated due to problems with the reference method or due to
operational problems with the affected unit(s) need not be reported.
Such runs do not affect the validation status of emission data
recorded by the CEMS. However, a record of all RATAs, trial RATA
runs and RATA attempts (whether reported or not) must be kept on-
site as part of the official test log for each monitoring system.
(i) Each time that a hands-off RATA of an SO2
pollutant concentration monitor, a NOX-diluent monitoring
system, a NOX concentration monitoring system or a flow
monitor is passed, perform a bias test in accordance with section
7.6.4 of appendix A to this part. Apply the appropriate bias
adjustment factor to the reported SO2, NOX, or
flow rate data, in accordance with section 7.6.5 of appendix A to
this part.
(j) Failure of the bias test does not result in the monitoring
system being out-of-control.
2.3.3 RATA Grace Period
(a) The owner or operator has a grace period of 720 consecutive
unit operating hours, as defined in Sec. 72.2 of this chapter (or,
for CEMS installed on common stacks or bypass stacks, 720
consecutive stack operating hours, as defined in Sec. 72.2 of this
chapter), in which to complete the required RATA for a particular
CEMS whenever: a required RATA has not been performed by the end of
the QA operating quarter in which it is due; or five consecutive
calendar years have elapsed without a required 3-load flow RATA
having been conducted; or for a unit which is conditionally exempted
under Sec. 75.21(a)(7) from the SO2 RATA requirements of
this part, an SO2 RATA has not been completed by the end
of the calendar quarter in which the annual usage of fuel(s) with a
sulfur content higher than very low sulfur fuel(as defined in
Sec. 72.2 of this chapter) exceeds 480 hours; or eight
[[Page 28651]]
successive calendar quarters have elapsed, following the quarter in
which a RATA was last performed, without a subsequent RATA having
been done, due either to infrequent operation of the unit(s) or
frequent combustion of very low sulfur fuel, as defined in Sec. 72.2
of this chapter (SO2 monitors, only), or a combination of
these factors.
(b) Except for SO2 monitoring system RATAs, the grace
period shall begin with the first unit (or stack) operating hour
following the calendar quarter in which the required RATA was due.
For SO2 monitor RATAs, the grace period shall begin with
the first unit (or stack) operating hour in which fuel with a total
sulfur content higher than that of very low sulfur fuel (as defined
in Sec. 72.2 of this chapter) is burned in the unit(s), following
the quarter in which the required RATA is due. Data validation
during a RATA grace period shall be done in accordance with the
applicable provisions in section 2.3.2 of this appendix.
(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. Note that when a RATA (or RATAs, if more
than one attempt is made) is done during a grace period in order to
satisfy a RATA requirement from a previous quarter, the deadline for
the next RATA shall be determined from the quarter in which the RATA
was due, not from the quarter in which the RATA is actually
completed. However, if a RATA deadline determined in this manner is
less than two QA operating quarters from the quarter in which the
missed RATA is completed , the RATA deadline shall be re-set at two
QA operating quarters from the quarter in which the missed RATA is
completed .
2.3.4 Bias Adjustment Factor
Except as otherwise specified in section 7.6.5 of appendix A to
this part, if an SO2 pollutant concentration monitor,
flow monitor, NOX continuous emission monitoring system,
or NOX concentration monitoring system used to calculate
NOX mass emissions fails the bias test specified in
section 7.6 of appendix A to this part, use the bias adjustment
factor given in Equations A-11 and A-12 of appendix A to this part
to adjust the monitored data.
2.4 Recertification, Quality Assurance, RATA Frequency and Bias
Adjustment Factors (Special Considerations)
(a) When a significant change is made to a monitoring system
such that recertification of the monitoring system is required in
accordance with Sec. 75.20(b), a recertification test (or tests)
must be performed to ensure that the CEMS continues to generate
valid data. In all recertifications, a RATA will be one of the
required tests; for some recertifications, other tests will also be
required. A recertification test may be used to satisfy the quality
assurance test requirement of this appendix. For example, if, for a
particular change made to a CEMS, one of the required
recertification tests is a linearity check and the linearity check
is successful, then, unless another such recertification event
occurs in that same QA operating quarter, it would not be necessary
to perform an additional linearity test of the CEMS in that quarter
to meet the quality assurance requirement of section 2.2.1 of this
appendix. For this reason, EPA recommends that owners or operators
coordinate component replacements, system upgrades, and other events
that may require recertification, to the extent practicable, with
the periodic quality assurance testing required by this appendix.
When a quality assurance test is done for the dual purpose of
recertification and routine quality assurance, the applicable data
validation procedures in Sec. 75.20(b)(3) shall be followed.
(b) Except as provided in section 2.3.3 of this appendix,
whenever a passing RATA of a gas monitor or a passing 2-load or 3-
load RATA of a flow monitor is performed (irrespective of whether
the RATA is done to satisfy a recertification requirement or to meet
the quality assurance requirements of this appendix, or both), the
RATA frequency (semi-annual or annual) shall be established based
upon the date and time of completion of the RATA and the relative
accuracy percentage obtained. For 2-load and 3-load flow RATAs, use
the highest percentage relative accuracy at any of the loads to
determine the RATA frequency. The results of a single-load flow RATA
may be used to establish the RATA frequency when the single-load
flow RATA is specifically required under section 2.3.1.3(b) of this
appendix (for flow monitors installed on peaking units and bypass
stacks) or when the single-load RATA is allowed under section
2.3.1.3(c) of this appendix for a unit that has operated at the most
frequently used load level for 85.0 percent of the time
since the last annual flow RATA. No other single-load flow RATA may
be used to establish an annual RATA frequency; however, a 2-load or
3-load flow RATA may be performed at any time or in place of any
required single-load RATA, in order to establish an annual RATA
frequency.
2.5 Other Audits
* * * * *
Figure 1 to Appendix B of Part 75--Quality Assurance Test Requirements.
----------------------------------------------------------------------------------------------------------------
QA test frequency requirements
Test --------------------------------------------------
Daily* Quarterly* Semiannual*
----------------------------------------------------------------------------------------------------------------
Calibration Error (2 pt.).................................... ............... ............... ...............
Interference (flow).......................................... ............... ............... ...............
Flow-to-Load Ratio........................................... ............... ............... ...............
Leak Check (DP flow monitors)................................ ............... ............... ...............
Linearity (3 pt.)............................................ ............... ............... ...............
RATA (SO2, NOX, CO2, H2O)1................................... ............... ............... ...............
RATA (flow)1,2............................................... ............... ............... ...............
----------------------------------------------------------------------------------------------------------------
-For monitors on bypass stack/duct, ``daily'' means bypass operating days, only. ``Quarterly'' means once every
QA operating quarter. ``Semiannual'' means once every two QA operating quarters.
\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 and bypass stacks, conduct all RATAs at a single, normal load.
For other flow monitors, conduct annual RATAs at the two load levels used most frequently since the last
annual RATA. Alternating single-load and 2-load RATAs may be done if a monitor is on a semiannual frequency. A
single-load RATA may be done in lieu of a 2-load RATA if, since the last annual flow RATA, the unit has
operated at one load level for 85.0 percent of the time. A 3-load RATA is required at least once in
every period of five consecutive calendar years and whenever a flitor is re-linearized.
Figure 2 to Appendix B of Part 75--Relative Accuracy Test Frequency Incentive System .
----------------------------------------------------------------------------------------------------------------
RATA Semiannual 1 (percent) Annual 1
----------------------------------------------------------------------------------------------------------------
SO2 or NOX3................. 7.5% 10.0% or 7.5% or 12.0
minus> 15.0 ppm2. ppm2
SO2-diluent................. 7.5% < RA 10.0% or 7.5% or
minus> 0.030. 0.025.
lb/mmBtu 2.............................. lb/mmBtu 2
NOX-diluent................. 7.5% < RA 10.0% or 7.5% or
minus> 0.020. 0.015.
[[Page 28652]]
lb/mmBtu 2.............................. lb/mmBtu 2.
Flow (Phase I).............. 10.0% < RA 15.0% or 10.0%.
minus> 1.5 fps 2.
Flow (Phase II)............. 7.5% < RA 10.0% or 7.5%.
minus> 1.5 fps 2.
CO2 or O2................... 7.5% < RA 10.0% or 7.5% or 0.7%
minus> 1.0% CO2/O22. CO2/O22.
Moisture.................... 7.5% < RA 10.0% or 7.5% or 1.0%
minus> 1.5% H2O2. H2O2.
----------------------------------------------------------------------------------------------------------------
\1\ 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.
\2\ The difference between monitor and reference method mean values applies to moisture monitors, CO2, and O2
monitors, low emitters, or low flow, only.
\3\ A NOX concentration monitoring system used to determine NO2 mass emissions under Sec. 75.71.
Appendix C To Part 75--Missing Data Statistical Estimation Procedures
62.-63. Appendix C to part 75 is amended by revising sections
2.1, 2.2.1, 2.2.2, 2.2.3, and 2.2.5, and by revising section 2.2.3.9
to read as follows:
2. Load-Based Procedure for Missing Flow Rate and NOX
Emission Rate Data
2.1 Applicability
This procedure is applicable for data from all affected units
for use in accordance with the provisions of this part to provide
substitute data for volumetric flow rate (scfh), NOX
emission rate (in lb/mmBtu) from NOX-diluent continuous
emission monitoring systems, and NOX concentration data
(in ppm) from NOx concentration monitoring systems used to determine
NOX mass emissions.
2.2 * * *
2.2.1 For a single unit, establish ten operating load ranges
defined in terms of percent of the maximum hourly average gross load
of the unit, in gross megawatts (MWge), as shown in Table C-1. (Do
not use integrated hourly gross load in MW-hr.) For units sharing a
common stack monitored with a single flow monitor, the load ranges
for flow (but not for NOX) may be broken down into 20
operating load ranges in increments of 5.0 percent of the combined
maximum hourly average gross load of all units utilizing the common
stack. If this option is selected, the twentieth (uppermost)
operating load range shall include all values greater than 95.0
percent of the maximum hourly average gross load. For a cogenerating
unit or other unit at which some portion of the heat input is not
used to produce electricity or for a unit for which hourly average
gross load in MWge is not recorded separately, use the hourly gross
steam load of the unit, in pounds of steam per hour at the measured
temperature ( deg.F) and pressure (psia) instead of MWge. Indicate a
change in the number of load ranges or the units of loads to be used
in the precertification section of the monitoring plan.
Table C-1.--Definition of Operating Load Ranges for Load-based
Substitution Data Procedures
------------------------------------------------------------------------
Percent of
maximum
hourly gross
load or
Operating load range maximum
hourly gross
steam load
(percent)
------------------------------------------------------------------------
1......................................................... 0-10
2......................................................... >10-20
3......................................................... >20-30
4......................................................... >30-40
5......................................................... >40-50
6......................................................... >50-60
7......................................................... >60-70
8......................................................... >70-80
9......................................................... >80-90
10........................................................ >90
------------------------------------------------------------------------
2.2.2 Beginning with the first hour of unit operation after
installation and certification of the flow monitor or the
NOX-diluent continuous emission monitoring system (or a
NOX concentration monitoring system used to determine
NOX mass emissions, as defined in Sec. 75.71(a)(2)), for
each hour of unit operation record a number, 1 through 10, (or 1
through 20 for flow at common stacks) that identifies the operating
load range corresponding to the integrated hourly gross load of the
unit(s) recorded for each unit operating hour.
2.2.3 Beginning with the first hour of unit operation after
installation and certification of the flow monitor or the
NOX-diluent continuous emission monitoring system (or a
NOX concentration monitoring system used to determine
NOX mass emissions, as defined in Sec. 75.71(a)(2)) and
continuing thereafter, the data acquisition and handling system must
be capable of calculating and recording the following information
for each unit operating hour of missing flow or NOX data
within each identified load range during the shorter of: (a) the
previous 2,160 quality assured monitor operating hours (on a rolling
basis), or (b) all previous quality assured monitor operating hours.
* * * * *
2.2.3.9 Average of the hourly NOX pollutant
concentrations, in ppm, reported by a NOX concentration
monitoring system used to determine NOX mass emissions,
as defined in Sec. 75.71(a)(2).
* * * * *
2.2.5 When a bias adjustment is necessary for the flow monitor
and/or the NOX-diluent continuous emission monitoring
system (and/or the NOX concentration monitoring system
used to determine NOX mass emissions, as defined in
Sec. 75.71(a)(2)), apply the adjustment factor to all monitor or
continuous emission monitoring system data values placed in the load
ranges.
* * * * *
Appendix D To Part 75--Optional SO2 Emissions Data Protocol
for Gas-Fired and Oil-Fired Units
64. Appendix D to part 75 is amended by revising section 1.1 to
read as follows:
1. Applicability
1.1 This protocol may be used in lieu of continuous
SO2 pollutant concentration and flow monitors for the
purpose of determining hourly SO2 mass emissions and heat
input from: gas-fired units, as defined in Sec. 72.2 of this
chapter, or oil-fired units, as defined in Sec. 72.2 of this
chapter. Section 2.1 of this appendix provides procedures for
measuring oil or gaseous fuel flow using a fuel flowmeter, section
2.2 of this appendix provides procedures for conducting oil sampling
and analysis to determine sulfur content and gross calorific value
(GCV) of fuel oil, and section 2.3 of this appendix provides
procedures for determining the sulfur content and GCV of gaseous
fuels.
* * * * *
65. Appendix D to part 75 is further amended by:
a. Revising sections 2.1 and 2.1.1;
b. Addding sections 2.1.1.1 through 2.1.1.3;
c. Revising sections 2.1.2 through 2.1.4;
d. Adding sections 2.1.4.1 through 2.1.4.3;
e. Revising sections 2.1.5 through 2.1.5.2;
f. Adding sections 2.1.5.3 through 2.1.5.4;
g. Revising sections 2.1.6 through 2.1.6.2;
h. Adding sections 2.1.6.3 through 2.1.7.5;
i. Revising sections 2.2 and 2.2.1;
j. Removing sections 2.2.1.1 and 2.2.1.2;
k. Removing and reserving section 2.2.2;
l. Revising sections 2.2.3 and 2.2.4;
m. Adding sections 2.2.4.1 through 2.2.4.3;
[[Page 28653]]
n. Revising the first sentence of section 2.2.6;
o. Revising sections 2.2.8 and 2.3 through 2.3.2.1;
p. Adding sections 2.3.2.1.1 and 2.3.2.1.2;
q. Revising section 2.3.2.2;
r. Adding sections 2.3.2.3 through 2.3.6;
s. Revising section 2.4.1;
t. Removing section 2.4.2, and redesignating sections 2.4.3,
2.4.3.1, 2.4.3.2, 2.4.3.3 and 2.4.4 as sections 2.4.2, 2.4.2.1,
2.4.2.2, 2.4.2.3 and 2.4.3, respectively; and
u. Revising newly redesignated sections 2.4.2, 2.4.2.1, and
2.4.2.3 to read as follows:
2. Procedure
2.1 Fuel Flowmeter Measurements
For each hour when the unit is combusting fuel, measure and
record the flow rate of fuel combusted by the unit, except as
provided in section 2.1.4 of this appendix. Measure the flow rate of
fuel with an in-line fuel flowmeter, and automatically record the
data with a data acquisition and handling system, except as provided
in section 2.1.4 of this appendix.
2.1.1 Measure the flow rate of each fuel entering and being
combusted by the unit. If, on an annual basis, more than 5.0 percent
of the fuel from the main pipe is diverted from the unit without
being burned and that diversion occurs downstream of the fuel
flowmeter, an additional in-line fuel flowmeter is required to
account for the unburned fuel. In this case, record the flow rate of
each fuel combusted by the unit as the difference between the flow
measured in the pipe leading to the unit and the flow in the pipe
diverting fuel away from the unit. However, the additional fuel
flowmeter is not required if, on an annual basis, the total amount
of fuel diverted away from the unit, expressed as a percentage of
the total annual fuel usage by the unit is demonstrated to be less
than or equal to 5.0 percent. The owner or operator may make this
demonstration in the following manner:
2.1.1.1 For existing units with fuel usage data from fuel
flowmeters, if data are submitted from a previous year demonstrating
that the total diverted yearly fuel does not exceed 5% of the total
fuel used; or
2.1.1.2 For new units which do not have historical data, if a
letter is submitted signed by the designated representative
certifying that, in the future, the diverted fuel will not exceed
5.0% of the total annual fuel usage ; or
2.1.1.3 By using a method approved by the Administrator under
Sec. 75.66(d).
2.1.2 Install and use fuel flowmeters meeting the requirements
of this appendix in a pipe going to each unit, or install and use a
fuel flowmeter in a common pipe header (i.e., a pipe carrying fuel
for multiple units). However, the use of a fuel flowmeter in a
common pipe header and the provisions of sections 2.1.2.1 and
2.1.2.2 of this appendix are not applicable to any unit that is
using the provisions of subpart H of this part to monitor, record,
and report NOX mass emissions under a state or federal
NOX mass emission reduction program. For all other units,
if the fuel flowmeter is installed in a common pipe header, do one
of the following:
2.1.2.1 Measure the fuel flow rate in the common pipe, and
combine SO2 mass emissions for the affected units for
recordkeeping and compliance purposes; or
2.1.2.2 Provide information satisfactory to the Administrator
on methods for apportioning SO2 mass emissions and heat
input to each of the affected units demonstrating that the method
ensures complete and accurate accounting of the actual emissions
from each of the affected units included in the apportionment and
all emissions regulated under this part. The information shall be
provided to the Administrator through a petition submitted by the
designated representative under Sec. 75.66. Satisfactory information
includes: the proposed apportionment, using fuel flow measurements;
the ratio of hourly integrated gross load (in MWe-hr) in each unit
to the total load for all units receiving fuel from the common pipe
header, or the ratio of hourly steam flow (in 1000 lb) at each unit
to the total steam flow for all units receiving fuel from the common
pipe header (see section 3.4.3 of this appendix); and documentation
that shows the provisions of sections 2.1.5 and 2.1.6 of this
appendix have been met for the fuel flowmeter used in the
apportionment.
2.1.3 For a gas-fired unit or an oil-fired unit that
continuously or frequently combusts a supplemental fuel for flame
stabilization or safety purposes, measure the flow rate of the
supplemental fuel with a fuel flowmeter meeting the requirements of
this appendix.
2.1.4 Situations in Which Certified Flowmeter is Not Required
2.1.4.1 Start-up or Ignition Fuel
For an oil-fired unit that uses gas solely for start-up or
burner ignition or a gas-fired unit that uses oil solely for start-
up or burner ignition, a flowmeter for the start-up fuel is not
required. Estimate the volume of oil combusted for each start-up or
ignition either by using a fuel flowmeter or by using the dimensions
of the storage container and measuring the depth of the fuel in the
storage container before and after each start-up or ignition. A fuel
flowmeter used solely for start-up or ignition fuel is not subject
to the calibration requirements of sections 2.1.5 and 2.1.6 of this
appendix. Gas combusted solely for start-up or burner ignition does
not need to be measured separately.
2.1.4.2 Gas or Oil Flowmeter Used for Commercial Billing
A gas or oil flowmeter used for commercial billing of natural
gas or oil may be used to measure, record, and report hourly fuel
flow rate. A gas or oil flowmeter used for commercial billing of
natural gas or oil is not required to meet the certification
requirements of section 2.1.5 of this appendix or the quality
assurance requirements of section 2.1.6 of this appendix under the
following circumstances:
(a) The gas or oil flowmeter is used for commercial billing
under a contract, provided that the company providing the gas or oil
under the contract and each unit combusting the gas or oil do not
have any common owners and are not owned by subsidiaries or
affiliates of the same company;
(b) The designated representative reports hourly records of gas
or oil flow rate, heat input rate, and emissions due to combustion
of natural gas or oil;
(c) The designated representative also reports hourly records of
heat input rate for each unit, if the gas or oil flowmeter is on a
common pipe header, consistent with section 2.1.2 of this appendix;
(d) The designated representative reports hourly records
directly from the gas or oil flowmeter used for commercial billing
if these records are the values used, without adjustment, for
commercial billing, or reports hourly records using the missing data
procedures of section 2.4 of this appendix if these records are not
the values used, without adjustment, for commercial billing; and
(e) The designated representative identifies the gas or oil
flowmeter in the unit's monitoring plan.
2.1.4.3 Emergency Fuel
The designated representative of a unit that is restricted by
its Federal, State or local permit to combusting a particular fuel
only during emergencies where the primary fuel is not available is
exempt from certifying a fuel flowmeter for use during combustion of
the emergency fuel. During any hour in which the emergency fuel is
combusted, report the hourly heat input to be the maximum rated heat
input of the unit for the fuel. Additionally, begin sampling the
emergency fuel for sulfur content only using the procedures under
section 2.2 (for oil) or 2.3 (for gas) of this appendix. The
designated representative shall also provide notice under
Sec. 75.61(a)(6)(ii) for each period when the emergency fuel is
combusted.
2.1.5 Initial Certification Requirement for all Fuel Flowmeters
For the purposes of initial certification, each fuel flowmeter
used to meet the requirements of this protocol shall meet a
flowmeter accuracy of 2.0 percent of the upper range value (i.e.
maximum calibrated fuel flow rate) across the range of fuel flow
rate to be measured at the unit. Flowmeter accuracy may be
determined under section 2.1.5.1 of this appendix for initial
certification in any of the following ways (as applicable): by
design or by measurement under laboratory conditions; by the
manufacturer; by an independent laboratory; or by the owner or
operator. Flowmeter accuracy may also be determined under section
2.1.5.2 of this appendix by measurement against a NIST traceable
reference method.
2.1.5.1 Use the procedures in the following standards to verify
flowmeter accuracy or design, as appropriate to the type of
flowmeter: ASME MFC-3M-1989 with September 1990 Errata
(``Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and
Venturi''); ASME MFC-4M-1986 (Reaffirmed 1990), ``Measurement of Gas
Flow by Turbine Meters;'' American Gas Association Report No. 3,
``Orifice Metering of Natural Gas and Other Related Hydrocarbon
Fluids Part 1: General Equations and Uncertainty Guidelines''
[[Page 28654]]
(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 (``Measurement of Liquid Flow in Closed Conduits
Using Transit-Time Ultrasonic Flowmeters''); ASME MFC-6M-1987 with
June 1987 Errata (``Measurement of Fluid Flow in Pipes Using Vortex
Flow Meters''); 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) Section 2, ``Conventional Pipe Provers'', Section 3,
``Small Volume Provers'', and Section 5, ``Master-Meter Provers'',
from Chapter 4 of the Manual of Petroleum Measurement Standards,
October 1988 (Reaffirmed 1993); or ASME MFC-9M-1988 with December
1989 Errata (``Measurement of Liquid Flow in Closed Conduits by
Weighing Method''), for all other flowmeter types (incorporated by
reference under Sec. 75.6). The Administrator may also approve other
procedures that use equipment traceable to National Institute of
Standards and Technology standards. Document such procedures, the
equipment used, and the accuracy of the procedures in the monitoring
plan for the unit, and submit a petition signed by the designated
representative under Sec. 75.66(c). If the flowmeter accuracy
exceeds 2.0 percent of the upper range value, the flowmeter does not
qualify for use under this part.
2.1.5.2 (a) Alternatively, determine the flowmeter accuracy of
a fuel flowmeter used for the purposes of this part by comparing it
to the measured flow from a reference flowmeter which has been
either designed according to the specifications of American Gas
Association Report No. 3 or ASME MFC-3M-1989, as cited in section
2.1.5.1 of this appendix, or tested for accuracy during the previous
365 days, using a standard listed in section 2.1.5.1 of this
appendix or other procedure approved by the Administrator under
Sec. 75.66 (all standards incorporated by reference under
Sec. 75.6). Any secondary elements, such as pressure and temperature
transmitters, must be calibrated immediately prior to the
comparison. Perform the comparison over a period of no more than
seven consecutive unit operating days. Compare the average of three
fuel flow rate readings over 20 minutes or longer for each meter at
each of three different flow rate levels. The three flow rate levels
shall correspond to:
(1) Normal full unit operating load,
(2) Normal minimum unit operating load,
(3) A load point approximately equally spaced between the full
and minimum unit operating loads, and
(4) Calculate the flowmeter accuracy at each of the three flow
levels using the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.012
Where:
ACC=Flowmeter accuracy at a particular load level, as a percentage
of the upper range value.
R=Average of the three flow measurements of the reference flowmeter.
A=Average of the three measurements of the flowmeter being tested.
URV=Upper range value of fuel flowmeter being tested (i.e. maximum
measurable flow).
(c) Notwithstanding the requirement for calibration of the
reference flowmeter within 365 days prior to an accuracy test, when
an in-place reference meter or prover is used for quality assurance
under section 2.1.6 of this appendix, the reference meter
calibration requirement may be waived if, during the previous in-
place accuracy test with that reference meter, the reference
flowmeter and the flowmeter being tested agreed to within
1.0 percent of each other at all levels tested. This
exception to calibration and flowmeter accuracy testing requirements
for the reference flowmeter shall apply for periods of no longer
than five consecutive years (i.e., 20 consecutive calendar
quarters).
2.1.5.3 If the flowmeter accuracy exceeds the specification in
section 2.1.5 of this appendix, the flowmeter does not qualify for
use for this appendix. Either recalibrate the flowmeter until the
flowmeter accuracy is within the performance specification, or
replace the flowmeter with another one that is demonstrated to meet
the performance specification. Substitute for fuel flow rate using
the missing data procedures in section 2.4.2 of this appendix until
quality assured fuel flow data become available.
2.1.5.4 For purposes of initial certification, when a flowmeter
is tested against a reference fuel flow rate (i.e., fuel flow rate
from another fuel flowmeter under section 2.1.5.2 of this appendix
or flow rate from a procedure performed according to a standard
incorporated by reference under section 2.1.5.1 of this appendix),
report the results of flowmeter accuracy tests using the following
Table D-1.
Table D-1.--Table of Flowmeter Accuracy Results
------------------------------------------------------------------------
-------------------------------------------------------------------------
Test number:________ Test completion date \1\:____________________ Test
completion time \1\:____________
Reinstallation date \2\ (for testing under 2.1.5.1
only):____________________ Reinstallation time \2\:____________
Unit or pipe ID: Component/System ID:
Flowmeter serial number: Upper range value:
Units of measure for flowmeter and reference flow readings:
------------------------------------------------------------------------
Percent
Time of run Candidate Reference accuracy
Measurement level (percent of URV) Run No. (HHMM) flowmeter flow (percent of
reading reading URV)
----------------------------------------------------------------------------------------------------------------
Low (Minimum) level................ 1 ........... ........... ........... ...........
____ percent \3\ of URV............ 2 ........... ........... ........... ...........
3 ........... ........... ........... ...........
Average ........... ........... ........... ...........
Mid-level.......................... 1 ........... ........... ........... ...........
____ percent \3\ of URV............ 2 ........... ........... ........... ...........
3 ........... ........... ........... ...........
Average ........... ........... ........... ...........
High (Maximum) level............... 1 ........... ........... ........... ...........
____ percent \3\ of URV............ 2 ........... ........... ........... ...........
3 ........... ........... ........... ...........
Average ........... ........... ........... ...........
----------------------------------------------------------------------------------------------------------------
\1\ Report the date, hour, and minute that all test runs were completed.
\2\ For laboratory tests not performed inline, report the date and hour that the fuel flowmeter was reinstalled
following the test.
\3\ It is required to test at least at three different levels: (1) normal full unit operating load, (2) normal
minimum unit operating load, and (3) a load point approximately equally spaced between the full and minimum
unit operating loads.
[[Page 28655]]
2.1.6 Quality Assurance
(a) Test the accuracy of each fuel flowmeter prior to use under
this part and at least once every four fuel flowmeter QA operating
quarters, as defined in Sec. 72.2 of this chapter, thereafter.
Notwithstanding these requirements, no more than 20 successive
calendar quarters shall elapse after the quarter in which a fuel
flowmeter was last tested for accuracy without a subsequent
flowmeter accuracy test having been conducted. Test the flowmeter
accuracy more frequently if required by manufacturer specifications.
(b) Except for orifice-, nozzle-, and venturi-type flowmeters,
perform the required flowmeter accuracy testing using the procedures
in either section 2.1.5.1 or section 2.1.5.2 of this appendix. Each
fuel flowmeter must meet the accuracy specification in section 2.1.5
of this appendix.
(c) For orifice-, nozzle-, and venturi-type flowmeters, either
perform the required flowmeter accuracy testing using the procedures
in section 2.1.5.1 or 2.1.5.2 of this appendix or perform a
transmitter accuracy test once every four fuel flowmeter QA
operating quarters and a primary element visual inspection once
every 12 calendar quarters, according to the procedures in sections
2.1.6.1 through 2.1.6.4 of this appendix for periodic quality
assurance.
(d) Notwithstanding the requirements of this section, if the
procedures of section 2.1.7 (fuel flow-to-load test) of this
appendix are performed during each fuel flowmeter QA operating
quarter, subsequent to a required flowmeter accuracy test or
transmitter accuracy test and primary element inspection, where
applicable, those procedures may be used to meet the requirement for
periodic quality assurance testing for a period of up to 20 calendar
quarters from the previous accuracy test or transmitter accuracy
test and primary element inspection, where applicable.
2.1.6.1 Transmitter or Transducer Accuracy Test for Orifice-, Nozzle-,
and Venturi-Type Flowmeters
(a) Calibrate the differential pressure transmitter or
transducer, static pressure transmitter or transducer, and
temperature transmitter or transducer, as applicable, using
equipment that has a current certificate of traceability to NIST
standards. Check the calibration of each transmitter or transducer
by comparing its readings to that of the NIST traceable equipment at
least once at each of the following levels: the zero-level and at
least two other levels (e.g., ``mid'' and ``high''), such that the
full range of transmitter or transducer readings corresponding to
normal unit operation is represented.
(b) Calculate the accuracy of each transmitter or transducer at
each level tested, using the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.013
Where:
ACC = Accuracy of the transmitter or transducer as a percentage of
full-scale.
R = Reading of the NIST traceable reference value (in milliamperes,
inches of water, psi, or degrees).
T = Reading of the transmitter or transducer being tested (in
milliamperes, inches of water, psi, or degrees, consistent with the
units of measure of the NIST traceable reference value).
FS = Full-scale range of the transmitter or transducer being tested
(in milliamperes, inches of water, psi, or degrees, consistent with
the units of measure of the NIST traceable reference value).
(c) If each transmitter or transducer meets an accuracy of
1.0 percent of its full-scale range at each level
tested, the fuel flowmeter accuracy of 2.0 percent is considered to
be met at all levels. If, however, one or more of the transmitters
or transducers does not meet an accuracy of 1.0 percent
of full-scale at a particular level, then the owner or operator may
demonstrate that the fuel flowmeter meets the total accuracy
specification of 2.0 percent at that level by using one of the
following alternative methods. If, at a particular level, the sum of
the individual accuracies of the three transducers is less than or
equal to 4.0 percent, the fuel flowmeter accuracy specification of
2.0 percent is considered to be met for that level. Or, if at a
particular level, the total fuel flowmeter accuracy is 2.0 percent
or less, when calculated in accordance with Part 1 of American Gas
Association Report No. 3, General Equations and Uncertainty
Guidelines, the flowmeter accuracy requirement is considered to be
met for that level.
2.1.6.2 Recordkeeping and Reporting of Transmitter or Transducer
Accuracy Results
(a) Record the accuracy of the orifice, nozzle, or venturi meter
or its individual transmitters or transducers and keep this
information in a file at the site or other location suitable for
inspection. When testing individual orifice, nozzle, or venturi
meter transmitters or transducers for accuracy, include the
information displayed in the following Table D-2. At a minimum,
record results for each transmitter or transducer at the zero-level
and at least two other levels across the range of the transmitter or
transducer readings that correspond to normal unit operation.
Table D-2.--Table of Flowmeter Transmitter or Transducer Accuracy
Results
Test number:________ Test completion date: ____________________ Unit or
pipe ID: ____________
Flowmeter serial number: Component/System ID:
Full-scale value: Units of measure: \3\
Transducer/Transmitter Type (check one):
____ Differential Pressure
____ Static Pressure
____ Temperature
------------------------------------------------------------------------
Expected
Run number Transmitter/ transmitter/ Actual Percent
Measurement level (percent of (if Run time transducer transducer transmitter/ accuracy
full-scale) multiple (HHMM) input (pre- output transducer (percent of
runs) \2\ calibration) (reference) output \3\ full-scale)
----------------------------------------------------------------------------------------------------------------
Low (Minimum) level
____ percent \1\ of full- ...........
scale
Mid-level
____ percent\1\ of full- ...........
scale
(If tested at more than 3
levels)
2nd Mid-level
____ percent \1\ of full- ...........
scale
(If tested at more than 3
levels)
3rd Mid-level
____ percent \1\ of full- ...........
scale
High (Maximum) level
____ percent \1\ of full- ...........
scale
----------------------------------------------------------------------------------------------------------------
\1\ At a minimum, it is required to test at zero-level and at least two other levels across the range of the
transmitter or transducer readings corresponding to normal unit operation.
\2\ It is required to test at least once at each level.
\3\ Use the same units of measure for all readings (e.g., use degrees ( deg.), inches of water (in H2O), pounds
per square inch (psi), or milliamperes (ma) for both transmitter or transducer readings and reference
readings).
[[Page 28656]]
(b) When accuracy testing of the orifice, nozzle, or venturi
meter is performed according to section 2.1.5.2 of this appendix,
record the information displayed in Table D-1 in this section. At a
minimum, record the overall flowmeter accuracy results for the fuel
flowmeter at the three flow rate levels specified in section 2.1.5.2
of this appendix.
(c) Report the results of all fuel flowmeter accuracy tests,
transmitter or transducer accuracy tests, and primary element
inspections, as applicable, in the emissions report for the quarter
in which the quality assurance tests are performed, using the
electronic format specified by the Administrator under Sec. 75.64.
2.1.6.3 Failure of Transducer(s) or Transmitter(s)
If, during a transmitter or transducer accuracy test conducted
according to section 2.1.6.1 of this appendix, the flowmeter
accuracy specification of 2.0 percent is not met at any of the
levels tested, repair or replace transmitter(s) or transducer(s) as
necessary until the flowmeter accuracy specification has been
achieved at all levels. (Note that only transmitters or transducers
which are repaired or replaced need to be re-tested; however, the
re-testing is required at all three measurement levels, to ensure
that the flowmeter accuracy specification is met at each level). The
fuel flowmeter is ``out-of-control'' and data from the flowmeter are
considered invalid, beginning with the date and hour of the failed
accuracy test and continuing until the date and hour of completion
of a successful transmitter or transducer accuracy test at all
levels. In addition, if, during normal operation of the fuel
flowmeter, one or more transmitters or transducers malfunction, data
from the fuel flowmeter shall be considered invalid from the hour of
the transmitter or transducer failure until the hour of completion
of a successful 3-level transmitter or transducer accuracy test.
During fuel flowmeter out-of-control periods, provide data from
another fuel flowmeter that meets the requirements of Sec. 75.20(d)
and section 2.1.5 of this appendix, or substitute for fuel flow rate
using the missing data procedures in section 2.4.2 of this appendix.
Record and report test data and results, consistent with sections
2.1.6.1 and 2.1.6.2 of this appendix and Sec. 75.56 or Sec. 75.59,
as applicable.
2.1.6.4 Primary Element Inspection
(a) Conduct a visual inspection of the orifice, nozzle, or
venturi meter at least once every twelve calendar quarters.
Notwithstanding this requirement, the procedures of section 2.1.7 of
this appendix may be used to reduce the inspection frequency of the
orifice, nozzle, or venturi meter to at least once every twenty
calendar quarters. The inspection may be performed using a
baroscope. If the visual inspection indicates that the orifice,
nozzle, or venturi meter has become damaged or corroded, then:
(1) Replace the primary element with another primary element
meeting the requirements of American Gas Association Report No. 3 or
ASME MFC-3M-1989, as cited in section 2.1.5.1 of this appendix (both
standards incorporated by reference under Sec. 75.6);
(2) Replace the primary element with another primary element,
and demonstrate that the overall flowmeter accuracy meets the
accuracy specification in section 2.1.5 of this appendix under the
procedures of section 2.1.5.2 of this appendix; or
(3) Restore the damaged or corroded primary element to ``as
new'' condition; determine the overall accuracy of the flowmeter,
using either the specifications of American Gas Association Report
No. 3 or ASME MFC-3M-1989, as cited in section 2.1.5.1 of this
appendix (both standards incorporated by reference under Sec. 75.6);
and retest the transmitters or transducers prior to providing
quality assured data from the flowmeter.
(b) If the primary element size is changed, calibrate the
transmitter or transducers consistent with the new primary element
size. Data from the fuel flowmeter are considered invalid, beginning
with the date and hour of a failed visual inspection and continuing
until the date and hour when:
(1) The damaged or corroded primary element is replaced with
another primary element meeting the requirements of American Gas
Association Report No. 3 or ASME MFC-3M-1989, as cited in section
2.1.5.1 of this appendix (both standards incorporated by reference
under Sec. 75.6);
(2) The damaged or corroded primary element is replaced, and the
overall accuracy of the flowmeter is demonstrated to meet the
accuracy specification in section 2.1.5 of this appendix under the
procedures of section 2.1.5.2 of this appendix; or
(3) The restored primary element is installed to meet the
requirements of American Gas Association Report No. 3 or ASME MFC-
3M-1989, as cited in section 2.1.5.1 of this appendix (both
standards incorporated by reference under Sec. 75.6) and its
transmitters or transducers are retested to meet the accuracy
specification in section 2.1.6.1 of this appendix.
(c) During this period, provide data from another fuel flowmeter
that meets the requirements of Sec. 75.20(d) and section 2.1.5 of
this appendix, or substitute for fuel flow rate using the missing
data procedures in section 2.4.2 of this appendix.
2.1.7 Fuel Flow-to-Load Quality Assurance Testing for Certified
Fuel Flowmeters
The procedures of this section may be used as an optional
supplement to the quality assurance procedures in section 2.1.5.1,
2.1.5.2, 2.1.6.1, or 2.1.6.4 of this appendix when conducting
periodic quality assurance testing of a certified fuel flowmeter.
Note, however, that these procedures may not be used unless the 168-
hour baseline data requirement of section 2.1.7.1 of this appendix
has been met. If, following a flowmeter accuracy test or flowmeter
transmitter test and primary element inspection, where applicable,
the procedures of this section are performed during each subsequent
fuel flowmeter QA operating quarter, as defined in Sec. 72.2 of this
chapter (excluding the quarter(s) in which the baseline data are
collected), then these procedures may be used to meet the
requirement for periodic quality assurance for a period of up to 20
calendar quarters from the previous periodic quality assurance
procedure(s) performed according to sections 2.1.5.1, 2.1.5.2, or
2.1.6.1 through 2.1.6.4 of this appendix. The procedures of this
section are not required for any quarter in which a flowmeter
accuracy test or a transmitter accuracy test and a primary element
inspection, where applicable, are conducted. Notwithstanding the
requirements of Sec. 75.54(a) or Sec. 75.57(a), as applicable, when
using the procedures of this section, keep records of the test data
and results from the previous flowmeter accuracy test under section
2.1.5.1 or 2.1.5.2 of this appendix, records of the test data and
results from the previous transmitter or transducer accuracy test
under section 2.1.6.1 of this appendix for orifice-, nozzle-, and
venturi-type fuel flowmeters, and records of the previous visual
inspection of the primary element required under section 2.1.6.4 of
this appendix for orifice-, nozzle-, and venturi-type fuel
flowmeters until the next flowmeter accuracy test, transmitter
accuracy test, or visual inspection is performed, even if the
previous flowmeter accuracy test, transmitter accuracy test, or
visual inspection was performed more than three years previously.
2.1.7.1 Baseline Flow Rate-to-Load Ratio or Heat Input-to-Load Ratio
(a) Determine Rbase, the baseline value of the ratio
of fuel flow rate to unit load, following each successful periodic
quality assurance procedure performed according to sections 2.1.5.1,
2.1.5.2, or 2.1.6.1 and 2.1.6.4 of this appendix. Establish a
baseline period of data consisting, at a minimum, of 168 hours of
quality assured fuel flowmeter data. Baseline data collection shall
begin with the first hour of fuel flowmeter operation following
completion of the most recent quality assurance procedure(s), during
which only the fuel measured by the fuel flowmeter is combusted
(i.e., only gas, only residual oil, or only diesel fuel is combusted
by the unit). During the baseline data collection period, the owner
or operator may exclude as non-representative any hour in which the
unit is ``ramping'' up or down, (i.e., the load during the hour
differs by more than 15.0 percent from the load in the previous or
subsequent hour) and may exclude any hour in which the unit load is
in the lower 25.0 percent of the range of operation, as defined in
section 6.5.2.1 of appendix A to this part (unless operation in this
lower 25.0 percent of the range is considered normal for the unit).
The baseline data must be obtained no later than the end of the
fourth calendar quarter following the calendar quarter of the most
recent quality assurance procedure for that fuel flowmeter. For
orifice-, nozzle-, and venturi-type fuel flowmeters, if the fuel
flow-
[[Page 28657]]
to-load ratio is to be used as a supplement both to the transmitter
accuracy test under section 2.1.6.1 of this appendix and to primary
element inspections under section 2.1.6.4 of this appendix, then the
baseline data must be obtained after both procedures are completed
and no later than the end of the fourth calendar quarter following
the calendar quarter of both the most recent transmitter or
transducer test and the most recent primary element inspection for
that fuel flowmeter. From these 168 (or more) hours of baseline
data, calculate the baseline fuel flow rate-to-load ratio as
follows:
[GRAPHIC] [TIFF OMITTED] TR26MY99.014
where:
Rbase = Value of the fuel flow rate-to-load ratio during
the baseline period; 100 scfh/MWe or 100 scfh/klb per hour steam
load for gas-firing; (lb/hr)/MWe or (lb/hr)/klb per hour steam load
for oil-firing.
Qbase = Average fuel flow rate measured by the fuel
flowmeter during the baseline period, 100 scfh for gas-firing and
lb/hr for oil-firing.
Lavg = Average unit load during the baseline period,
megawatts or 1000 lb/hr of steam.
(b) In Equation D-1b, for a common pipe header, Lavg
is the sum of the operating loads of all units that receive fuel
through the common pipe header. For a unit that receives its fuel
through multiple pipes, Qbase is the sum of the fuel flow
rates for a particular fuel (i.e., gas, diesel fuel, or residual
oil) from each of the pipes. Round off the value of Rbase
to the nearest tenth.
(c) Alternatively, a baseline value of the gross heat rate (GHR)
may be determined in lieu of Rbase. The baseline value of
the GHR, GHRbase, shall be determined as follows:
[GRAPHIC] [TIFF OMITTED] TR26MY99.015
Where:
(GHR)base = Baseline value of the gross heat rate during
the baseline period, Btu/kwh or Btu/lb steam load.
(Heat Input)avg = Average (mean) hourly heat input rate
recorded by the fuel flowmeter during the baseline period, as
determined using the applicable equation in appendix F to this part,
mmBtu/hr.
Lavg = Average (mean) unit load during the baseline
period, megawatts or 1000 lb/hr of steam.
(d) Report the current value of Rbase (or
GHRbase) and the completion date of the associated
quality assurance procedure in each electronic quarterly report
required under Sec. 75.64.
2.1.7.2 Data Preparation and Analysis
(a) Evaluate the fuel flow rate-to-load ratio (or GHR) for each
fuel flowmeter QA operating quarter, as defined in Sec. 72.2 of this
chapter. At the end of each fuel flowmeter QA operating quarter, use
Equation D-1d in this appendix to calculate Rh, the
hourly fuel flow-to-load ratio, for every quality assured hourly
average fuel flow rate obtained with a certified fuel flowmeter.
[GRAPHIC] [TIFF OMITTED] TR26MY99.016
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, or
(lb/hr)/1000 lb/hr of steam load.
Qh = Hourly fuel flow rate, as measured by the fuel
flowmeter, 100 scfh for gas-firing or lb/hr for oil-firing.
Lh = Hourly unit load, megawatts or 1000
lb/hr of steam.
(b) For a common pipe header, Lh shall be the sum of
the hourly operating loads of all units that receive fuel through
the common pipe header. For a unit that receives its fuel through
multiple pipes, Qh will be the sum of the fuel flow rates
for a particular fuel (i.e., gas, diesel fuel, or residual oil) from
each of the pipes. Round off each value of Rh to the
nearest tenth.
(c) Alternatively, calculate the hourly gross heat rates (GHR)
in lieu of the hourly flow-to-load ratios. If this option is
selected, calculate each hourly GHR value as follows:
[GRAPHIC] [TIFF OMITTED] TR26MY99.017
Where:
(GHR)h = Hourly value of the gross heat rate, Btu/kwh or
Btu/lb steam load.
(Heat Input)h = Hourly heat input rate, as determined
using the applicable equation in appendix F to this part, mmBtu/hr.
Lh = Hourly unit load, megawatts or 1000
lb/hr of steam.
(d) Evaluate the calculated flow rate-to-load ratios (or gross
heat rates) as follows. Perform a separate data analysis for each
fuel flowmeter following the procedures of this section. Base each
analysis on a minimum of 168 hours of data. If, for a particular
fuel flowmeter, fewer than 168 hourly flow-to-load ratios (or GHR
values) are available, a flow-to-load (or GHR) evaluation is not
required for that flowmeter for that calendar quarter.
(e) For each hourly flow-to-load ratio or GHR value, calculate
the percentage difference (percent Dh) from the baseline
fuel flow-to-load ratio using Equation D-1f.
[GRAPHIC] [TIFF OMITTED] TR26MY99.018
Where:
%Dh = Absolute value of the percentage difference between
the hourly fuel flow rate-to-load ratio and the baseline value of
the fuel flow rate-to-load ratio (or hourly and baseline GHR).
Rh = The hourly fuel flow rate-to-load ratio (or GHR).
Rbase = The value of the fuel flow rate-to-load ratio (or
GHR) from the baseline period, determined in accordance with section
2.1.7.1 of this appendix.
(f) Consistently use Rbase and Rh in
Equation D-1f if the fuel flow-to-load ratio is being evaluated, and
consistently use (GHR)base and (GHR)h in
Equation D-1f if the gross heat rate is being evaluated.
(g) Next, determine the arithmetic average of all of the hourly
percent difference (percent Dh) values using Equation D-
1g, as follows:
[GRAPHIC] [TIFF OMITTED] TR26MY99.019
Where:
Ef = Quarterly average percentage difference between
hourly flow rate-to-load ratios and the baseline value of the fuel
flow rate-to-load ratio (or hourly and baseline GHR).
%Dh = Percentage difference between the hourly fuel flow
rate-to-load ratio and the baseline value of the fuel flow rate-to-
load ratio (or hourly and baseline GHR).
q = Number of hours used in fuel flow-to-load (or GHR) evaluation.
(h) When the quarterly average load value used in the data
analysis is greater than 50 MWe (or 500 klb steam per hour), the
results of a quarterly fuel flow rate-to-load (or GHR) evaluation
are acceptable and no further action is required if the quarterly
average percentage difference (Ef) is no greater than
10.0 percent. When the arithmetic average of the hourly load values
used in the data analysis is 50 MWe (or 500 klb steam per
hour), the results of the analysis are
[[Page 28658]]
acceptable if the value of Ef is no greater than 15.0
percent.
2.1.7.3 Optional Data Exclusions
(a) If Ef is outside the limits in section 2.1.7.2 of
this appendix, the owner or operator may re-examine the hourly fuel
flow rate-to-load ratios (or GHRs) that were used for the data
analysis and identify and exclude fuel flow-to-load ratios or GHR
values for any non-representative fuel flow-to-load ratios or GHR
values. Specifically, the Rh or (GHR)h values
for the following hours may be considered non-representative: any
hour in which the unit combusted another fuel in addition to the
fuel measured by the fuel flowmeter being tested; or any hour for
which the load differed by more than 15.0 percent from
the load during either the preceding hour or the subsequent hour; or
any hour for which the unit load was in the lower 25.0 percent of
the range of operation, as defined in section 6.5.2.1 of appendix A
to this part (unless operation in the lower 25.0 percent of the
range is considered normal for the unit).
(b) After identifying and excluding all non-representative
hourly fuel flow-to-load ratios or GHR values, analyze the quarterly
fuel flow rate-to-load data a second time.
2.1.7.4 Consequences of Failed Fuel Flow-to-Load Ratio Test
(a) If Ef is outside the applicable limit in section
2.1.7.2 of this appendix (after analysis using any optional data
exclusions under section 2.1.7.3 of this appendix), perform
transmitter accuracy tests according to section 2.1.6.1 of this
appendix for orifice-, nozzle-, and venturi-type flowmeters, or
perform a fuel flowmeter accuracy test, in accordance with section
2.1.5.1 or 2.1.5.2 of this appendix, for each fuel flowmeter for
which Ef is outside of the applicable limit. In addition,
for an orifice-, nozzle-, or venturi-type fuel flowmeter, repeat the
fuel flow-to-load ratio comparison of section 2.1.7.2 of this
appendix using six to twelve hours of data following a passed
transmitter accuracy test in order to verify that no significant
corrosion has affected the primary element. If, for the abbreviated
6-to-12 hour test, the orifice-, nozzle-, or venturi-type fuel
flowmeter is not able to meet the limit in section 2.1.7.2 of this
appendix, then perform a visual inspection of the primary element
according to section 2.1.6.4 of this appendix, and repair or replace
the primary element, as necessary.
(b) Substitute for fuel flow rate, for any hour when that fuel
is combusted, using the missing data procedures in section 2.4.2 of
this appendix, beginning with the first hour of the calendar quarter
following the quarter for which Ef was found to be
outside the applicable limit and continuing until quality assured
fuel flow data become available. Following a failed flow rate-to-
load or GHR evaluation, data from the flowmeter shall not be
considered quality assured until the hour in which all required
flowmeter accuracy tests, transmitter accuracy tests, visual
inspections and diagnostic tests have been passed. Additionally, a
new value of Rbase or (GHR)base shall be
established no later than two flowmeter QA operating quarters after
the quarter in which the required quality assurance tests are
completed (note that for orifice-, nozzle-, or venturi-type fuel
flowmeters, establish a new value of Rbase or
(GHR)base only if both a transmitter accuracy test and a
primary element inspection have been performed).
2.1.7.5 Test Results
Report the results of each quarterly flow rate-to-load (or GHR)
evaluation, as determined from Equation D-1g, in the electronic
quarterly report required under Sec. 75.64. Table D-3 is provided as
a reference on the type of information to be recorded under
Sec. 75.59 and reported under Sec. 75.64.
Table D-3.--Baseline Information and Test Results for Fuel Flow-to-Load
Test
------------------------------------------------------------------------
-------------------------------------------------------------------------
Plant name:____________________State:______ORIS
code:____________________
Unit/pipe ID #:____________Fuel flowmeter component and system ID
#s:________-________Calendar quarter (1st, 2nd, 3rd, 4th) and
year:____________
Range of operation:____________ to ____________ MWe or klb steam/hr
(indicate units)
------------------------------------------------------------------------
Time period
-------------------------------------------------------------------------
Baseline period Quarter
------------------------------------------------------------------------
Completion date and time of most recent Number of hours excluded
primary element inspection (orifice-, nozzle- from quarterly average
, and venturi-type flowmeters only). due to co-firing
different fuels:________
hrs.
____/____/____ ____:____
Completion date and time of the most recent Number of hours excluded
flowmeter or transmitter accuracy test. from quarterly average
due to ramping load:
________ hrs.
____/____/____ ____:____
Beginning date and time of baseline period... Number of hours in the
lower 25.0 percent of
the range of operation
excluded from quarterly
average: ________ hrs.
____/____/____ ____:____
End date and time of baseline period......... Number of hours included
in quarterly average:
________ hrs.
____/____/____ ____:____
Average fuel flow rate____________________ Quarterly percentage
(100 scfh for gas and lb/hr for oil). difference between
hourly ratios and
baseline ratio: ________
percent.
Average load;____________________ (MWe or Test result: pass, fail.
1000 lb steam/hr).
Baseline fuel flow-to-load
ratio____________________
Units of fuel flow-to-
load:____________________
Baseline GHR: ____________________
Units of fuel flow-to-
load:____________________
Number of hours excluded from baseline ratio
or GHR due to ramping load:________
Number of hours in the lower 25.0 percent of
the range of operation excluded from
baseline ration or GHR: ________ hrs.
------------------------------------------------------------------------
2.2 Oil Sampling and Analysis
Perform sampling and analysis of oil to determine the following
fuel properties for each type of oil combusted by a unit: percentage
of sulfur by weight in the oil; gross calorific value (GCV) of the
oil; and, if necessary, the density of the oil. Use the sulfur
content, density, and gross calorific value, determined under the
provisions of this section, to calculate SO2 mass
emission rate and heat input rate for each fuel using the applicable
procedures of section 3 of this appendix. The designated
representative may petition for reduced GCV and or density sampling
under Sec. 75.66 if the fuel combusted
[[Page 28659]]
has a consistent and relatively non-variable GCV or density.
Table D-4.--Oil Sampling Methods and Sulfur, Density and Gross Calorific Value Used in Calculations
----------------------------------------------------------------------------------------------------------------
Parameter Sampling technique/frequency Value used in calculations
----------------------------------------------------------------------------------------------------------------
Oil Sulfur Content.................... Daily manual sampling......... 1. Highest sulfur content from previous
30 daily samples; or
2. Actual daily value.
Flow proportional/weekly Actual measured value.
composite.
In storage tank (after 1. Actual measured value; or
addition of fuel to tank). 2. Highest of all sampled values in
previous calendar year; or
3. Maximum value allowed by contract.\1\
As delivered (in delivery 1. Highest of all sampled values in
truck or barge).\1\. previous calendar year; or
2. Maximum value allowed by contract.\1\
Oil Density........................... Daily manual sampling......... 1. Use the highest density from the
previous 30 daily samples; or
2. Actual measured value.
Flow proportional/weekly Actual measured value.
composite.
In storage tank (after 1. Actual measured value; or
addition of fuel to tank). 2. Highest of all sampled values in
previous calendar year; or
3. Maximum value allowed by contract.\1\
As delivered (in delivery 1. Highest of all sampled values in
truck or barge).\1\. previous calendar year; or
2. Maximum value allowed by contract.\1\
Oil GCV............................... Daily manual sampling......... 1. Highest fuel GCV from the previous 30
daily samples; or
2. Actual measured value.
Flow proportional/weekly Actual measured value.
composite.
In storage tank (after 1. Actual measured value; or
addition of fuel to tank). 2. Highest of all sampled values in
previous calendar year; or
3. Maximum value allowed by contract.\1\
As delivered (in delivery 1. Highest of all sampled values in
truck or barge).\1\. previous calendar year; or
2. Maximum value allowed by contract.\1\
----------------------------------------------------------------------------------------------------------------
\1\ Assumed values may only be used if sulfur content, gross calorific value, or density of each sample is no
greater than the assumed value used to calculate emissions or heat input.
2.2.1 When combusting oil, use one of the following methods to
sample the oil (see Table D-4): sample from the storage tank for the
unit after each addition of oil to the storage tank, in accordance
with section 2.2.4.2 of this appendix; or sample from the fuel lot
in the shipment tank or container upon receipt of each oil delivery
or from the fuel lot in the oil supplier's storage container, in
accordance with section 2.2.4.3 of this appendix; or use the flow
proportional sampling methodology in section 2.2.3 of this appendix;
or use the daily manual sampling methodology in section 2.2.4.1 of
this appendix. For purposes of this appendix, a fuel lot of oil is
the mass or volume of product oil from one source (supplier or
pretreatment facility), intended as one shipment or delivery (e.g.,
ship load, barge load, group of trucks, discrete purchase of diesel
fuel through pipeline, etc.). A storage tank is a container at a
plant holding oil that is actually combusted by the unit, such that
no blending of any other fuel with the fuel in the storage tank
occurs from the time that the fuel lot is transferred to the storage
tank to the time when the fuel is combusted in the unit.
2.2.2 [Reserved]
2.2.3 Flow Proportional Sampling
Conduct flow proportional oil sampling or continuous drip oil
sampling in accordance with ASTM D4177-82 (Reapproved 1990),
``Standard Practice for Automatic Sampling of Petroleum and
Petroleum Products'' (incorporated by reference under Sec. 75.6),
every day the unit is combusting oil. Extract oil at least once
every hour and blend into a composite sample. The sample compositing
period may not exceed 7 calendar days (168 hrs). Use the actual
sulfur content (and where density data are required, the actual
density) from the composite sample to calculate the hourly
SO2 mass emission rates for each operating day
represented by the composite sample. Calculate the hourly heat input
rates for each operating day represented by the composite sample,
using the actual gross calorific value from the composite sample.
2.2.4 Manual Sampling
2.2.4.1 Daily Samples
Representative oil samples may be taken from the storage tank or
fuel flow line manually every day that the unit combusts oil
according to ASTM D4057-88, ``Standard Practice for Manual Sampling
of Petroleum and Petroleum Products'' (incorporated by reference
under Sec. 75.6). Use either the actual daily sulfur content or the
highest fuel sulfur content recorded at that unit from the most
recent 30 daily samples for the purpose of calculating
SO2 emissions under section 3 of this appendix. Use
either the gross calorific value measured from that day's sample or
the highest GCV from the previous 30 days' samples to calculate heat
input. If oil supplies with different sulfur contents are combusted
on the same day, sample the highest sulfur fuel combusted that day.
2.2.4.2 Sampling From a Unit's Storage Tank
Take a manual sample after each addition of oil to the storage
tank. Do not blend additional fuel with the sampled fuel prior to
combustion. Sample according to the single tank composite sampling
procedure or all-levels sampling procedure in ASTM D4057-88,
``Standard Practice for Manual Sampling of Petroleum and Petroleum
Products'' (incorporated by reference under Sec. 75.6). Use the
sulfur content (and where required, the density) of either the most
recent sample or one of the conservative assumed values described in
section 2.2.4.3 of this appendix to calculate SO2 mass
emission rate. Calculate heat input rate using the gross calorific
value from either:
(a) The most recent oil sample taken or
(b) One of the conservative assumed values described in section
2.2.4.3 of this appendix.
2.2.4.3 Sampling From Each Delivery
(a) Alternatively, an oil sample may be taken from--
(1) The shipment tank or container upon receipt of each lot of
fuel oil or
(2) The supplier's storage container which holds the lot of fuel
oil. (Note: a supplier need only sample the storage container once
for sulfur content, GCV and, where required, the density so long as
the fuel sulfur content and GCV do not change and no fuel is added
to the supplier's storage container.)
(b) For the purpose of this section, a lot is defined as a
shipment or delivery (e.g., ship load, barge load, group of trucks,
discrete purchase of diesel fuel through a pipeline, etc.) of a
single fuel.
(c) Oil sampling may be performed either by the owner or
operator of an affected unit, an outside laboratory, or a fuel
supplier, provided that samples are representative and that sampling
is performed according to either the single tank composite sampling
procedure or the all-levels sampling procedure in ASTM D4057-88,
``Standard Practice for Manual Sampling of Petroleum and Petroleum
Products'' (incorporated by reference under Sec. 75.6). Except as
otherwise provided in this section, calculate SO2 mass
[[Page 28660]]
emission rate using the sulfur content (and where required, the
density) from one of the two following values, and calculate heat
input using the gross calorific value from one of the two following
values:
(1) The highest value sampled during the previous calendar year
(this option is allowed for any consistent fuel which comes from a
single source whether or not the fuel is supplied under a
contractual agreement) or
(2) The maximum value indicated in the contract with the fuel
supplier. Continue to use this assumed contract value unless and
until the actual sampled sulfur content, density, or gross calorific
value of a delivery exceeds the assumed value.
(d) If the actual sampled sulfur content, gross calorific value,
or density of an oil sample is greater than the assumed value for
that parameter, then use the actual sampled value for sulfur
content, gross calorific value, or density of fuel to calculate
SO2 mass emission rate or heat input rate as the new
assumed sulfur content, gross calorific value, or density. Continue
to use this new assumed value to calculate SO2 mass
emission rate or heat input rate unless and until: it is superseded
by a higher value from an oil sample; or it 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 (if applicable) both the calendar
year in which the sampled value exceeded the assumed value and the
subsequent calendar year have elapsed.
* * * * *
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. * * *
* * * * *
2.2.8 Results from the oil sample analysis must be available no
later than thirty calendar days after the sample is composited or
taken. However, during an audit, the Administrator may require that
the results of the analysis be available as soon as practicable, and
no later than 5 business days after receipt of a request from the
Administrator.
2.3 SO2 Emissions From Combustion of Gaseous Fuels
(a) Account for the hourly SO2 mass emissions due to
combustion of gaseous fuels for each hour when gaseous fuels are
combusted by the unit using the procedures in this section.
(b) The procedures in sections 2.3.1 and 2.3.2 of this appendix,
respectively, may be used to determine SO2 mass emissions
from combustion of pipeline natural gas and natural gas, as defined
in Sec. 72.2 of this chapter. The procedures in section 2.3.3 of
this appendix may be used to account for SO2 mass
emissions from any gaseous fuel combusted by a unit. For each type
of gaseous fuel, the appropriate sampling frequency and the sulfur
content and GCV values used for calculations of SO2 mass
emission rates are summarized in the following Table D-5.
Table D-5.--Gas Sulfur and GCV Values Used in Calculations for Various
Fuel Types
------------------------------------------------------------------------
Fuel type and Value used in
Parameter sampling frequency calculations
------------------------------------------------------------------------
Pipeline Natural Gas 0.0006 lb/mmBtu.
with H2S content
less than or equal
to 0.3 grains/
100scf when using
the provisions of
section 2.3.1 to
determine SO2 mass
emissions.
Gas Sulfur Content.......... Natural Gas with H2S Default SO2 emission
content less than rate calculated
or equal to 1.0 from Eq. D-1h,
grain/100scf when using either the
using the fuel contract
provisions of maximum H2S or the
section 2.3.2 to maximum H2S from
determine SO2 mass historical sampling
emissions. data.
Any gaseous fuel Actual % sulfur from
delivered in most recent
shipments or lots-- shipment or
Sample each lot or 1. Highest % sulfur
shipment. from previous
year's samples \1\;
or
2. Maximum % sulfur
value allowed by
contract \1\.
Any gaseous fuel Actual % sulfur from
transmitted by daily sample; or
pipeline and having Highest % sulfur
a demonstrated from previous 30
``low sulfur daily samples.
variability'' using
the provisions of
section 2.3.6--
Sample daily.
Any gaseous fuel-- Actual hourly sulfur
Sample hourly. content of the gas.
Gas GCV..................... Pipeline Natural 1. GCV from most
Gas--Sample monthly. recent monthly
sample (with 48
operating hours in
the month); or
2. Maximum GCV from
contract \1\; or
3. Highest GCV from
previous year's
samples.\1\
Natural Gas--Sample 1. GCV from most
monthly. recent monthly
sample (with 48
operating hours in
the month); or
2. Maximum GCV from
contract \1\; or
3. Highest GCV from
previous year's
samples.\1\
Any gaseous fuel Actual GCV from most
delivered in recent shipment or
shipments or lots-- lot or
Sample each lot or 1. Highest GCV from
shipment. previous year's
samples1; or
2. Maximum GCV value
allowed by
contract.\1\
Any gaseous fuel 1. GCV from most
transmitted by recent monthly
pipeline and having sample (with 48
``low GCV operating hours in
variability'' using the month); or
the provisions of 2. Highest GCV from
section 2.3.5-- previous year's
Sample monthly. samples.\1\
Any other gaseous Actual daily or
fuel not having a hourly GCV of the
``low GCV gas.
variability''--Samp
le at least daily.
(Note that the use
of an on-line GCV
calorimeter or gas
chromatograph is
allowed).
------------------------------------------------------------------------
\1\ Assumed sulfur content and GCV values (i.e., contract values or
highest values from previous year) may only continue to be used if the
sulfur content or GCV of each sample is no greater than the assumed
value used to calculate SO2 emissions or heat input.
2.3.1 Pipeline Natural Gas Combustion
The owner or operator may determine the SO2 mass
emissions from the combustion of a fuel that meets the definition of
pipeline natural gas, in Sec. 72.2 of this chapter, using the
procedures of this section.
2.3.1.1 SO2 Emission Rate
For a fuel that meets the definition of pipeline natural gas
under Sec. 72.2 of this chapter, the owner or operator may determine
the SO2 mass emissions using either a default
SO2 emission rate of 0.0006 lb/mmBtu and the procedures
of this section, the procedures in section 2.3.2 for natural
[[Page 28661]]
gas, or the procedures of section 2.3.3 for any gaseous fuel. For
each affected unit using the default rate of 0.0006 lb/mmBtu, the
owner or operator must document that the fuel combusted is actually
pipeline natural gas, using the procedures in section 2.3.1.4 of
this appendix.
2.3.1.2 Hourly Heat Input Rate
Calculate hourly heat input rate, in mmBtu/hr, for a unit
combusting pipeline natural gas, using the procedures of section
3.4.1 of this appendix. Use the measured fuel flow rate from section
2.1 of this appendix and the gross calorific value from section
2.3.4.1 of this appendix in the calculations.
2.3.1.3 SO2 Hourly Mass Emission Rate and Hourly Mass
Emissions
For pipeline natural gas combustion, calculate the SO2 mass
emission rate, in lb/hr, using Equation D-5 in section 3.3.2 of this
appendix (when the default SO2 emission rate is used).
Then, use the calculated SO2 mass emission rate and the
unit operating time to determine the hourly SO2 mass
emissions from pipeline natural gas combustion, in lb, using
Equation D-12 in section 3.5.1 of this appendix.
2.3.1.4 Documentation That a Fuel Is Pipeline Natural Gas
(a) For pipeline natural gas, provide information in the
monitoring plan required under Sec. 75.53, demonstrating that the
definition of pipeline natural gas in Sec. 72.2 of this chapter has
been met. The information must demonstrate that the fuel has a
hydrogen sulfide content of less than 0.3 grain/100scf. The
demonstration must be made using one of the following sources of
information:
(1) The gas quality characteristics specified by a purchase
contract or by a pipeline transportation contract;
(2) A certification of the gas vendor, based on routine vendor
sampling and analysis (minimum of one year of data with samples
taken monthly or more frequently);
(3) At least one year's worth of analytical data on the fuel
hydrogen sulfide content from samples taken monthly or more
frequently;
(4) For fuels delivered in shipments or lots, the sulfur content
from all shipments or lots received in a one year period; or
(5) Data from a 720-hour demonstration conducted using the
procedures of section 2.3.6 of this appendix.
(b) When a 720-hour test is used for initial qualification as
pipeline natural gas, the owner or operator is required to continue
sampling the fuel for hydrogen sulfide at least once per month for
one year after the initial qualification period. The use of the
default natural gas SO2 emission rate under 2.3.1.1 is
not allowed if any sample during the one year period has a hydrogen
sulfide content greater than 0.3 gr/100 scf.
2.3.2 Natural Gas Combustion
The owner or operator may determine the SO2 mass
emissions from the combustion of a fuel that meets the definition of
natural gas, in Sec. 72.2 of this chapter, using the procedures of
this section.
2.3.2.1 SO2 Emission Rate
The owner or operator may account for SO2 emissions
either by using a default SO2 emission rate, as
determined under section 2.3.2.1.1 of this appendix, or by daily
sampling of the gas sulfur content using the procedures of section
2.3.3 of this appendix. For each affected unit using a default
SO2 emission rate, the owner or operator must provide
documentation that the fuel combusted is actually natural gas
according to the procedures in section 2.3.2.4 of this appendix.
2.3.2.1.1 In lieu of daily sampling of the sulfur content of
the natural gas, an SO2 default emission rate may be
determined using Equation D-1h. Round off the calculated
SO2 default emission rate to the nearest 0.0001 lb/mmBtu.
[GRAPHIC] [TIFF OMITTED] TR26MY99.020
Where:
ER = Default SO2 emission rate for natural gas
combustion, lb/mmBtu.
H2S = Hydrogen sulfide content of the natural gas, gr/
100scf.
2.3.2.1.2 The hydrogen sulfide value used in Equation D-1h may
be obtained from one of the following sources of information:
(a) The highest hydrogen sulfide content specified by a purchase
contract or by a pipeline transportation contract;
(b) The highest hydrogen sulfide content from a certification of
the gas vendor, based on routine vendor sampling and analysis
(minimum of one year of data with samples taken monthly or more
frequently);
(c) The highest hydrogen sulfide content from at least one
year's worth of analytical data on the fuel hydrogen sulfide content
from samples taken monthly or more frequently;
(d) For fuels delivered in shipments or lots, the highest
hydrogen sulfide content from all shipments or lots received in a
one year period; or (5) the highest hydrogen sulfide content
measured during a 720-hour demonstration conducted using the
procedures of section 2.3.6 of this appendix.
2.3.2.2 Hourly Heat Input Rate
Calculate hourly heat input rate for natural gas combustion, in
mmBtu/hr, using the procedures in section 3.4.1 of this appendix.
Use the measured fuel flow rate from section 2.1 of this appendix
and the gross calorific value from section 2.3.4.2 of this appendix
in the calculations.
2.3.2.3 SO2 Mass Emission Rate and Hourly Mass Emissions
For natural gas combustion, calculate the SO2 mass
emission rate, in lb/hr, using Equation D-5 in section 3.3.2 of this
appendix, when the default SO2 emission rate is used.
Then, use the calculated SO2 mass emission rate and the
unit operating time to determine the hourly SO2 mass
emissions from natural gas combustion, in lb, using Equation D-12 in
section 3.5.1 of this appendix.
2.3.2.4 Documentation that a Fuel Is Natural Gas
(a) For natural gas, provide information in the monitoring plan
required under Sec. 75.53, demonstrating that the definition of
natural gas in Sec. 72.2 of this chapter has been met. The
information must demonstrate that the fuel has a hydrogen sulfide
content of less than 1.0 grain/100 scf. This demonstration must be
made using one of the following sources of information:
(1) The gas quality characteristics specified by a purchase
contract or by a transportation contract;
(2) A certification of the gas vendor, based on routine vendor
sampling and analysis (minimum of one year of data with samples
taken monthly or more frequently);
(3) At least one year's worth of analytical data on the fuel
hydrogen sulfide content from samples taken monthly or more
frequently;
(4) For fuels delivered in shipments or lots, sulfur content
from all shipments or lots received in a one year period; or
(5) Data from a 720-hour demonstration conducted using the
procedures of section 2.3.6 of this appendix.
(b) When a 720-hour test is used for initial qualification as
natural gas, the owner or operator shall continue sampling the fuel
for hydrogen sulfide at least once per month for one year after the
initial qualification period. The use of the default natural gas
SO2 emission rate under 2.3.2.1.1 is not allowed if any
sample during the one year period has a hydrogen sulfide content
greater than 1.0 grain/100 scf.
2.3.3 SO2 Mass Emissions From Any Gaseous Fuel
The owner or operator of a unit may determine SO2
mass emissions using this section for any gaseous fuel (including
fuels such as refinery gas, landfill gas, digester gas, coke oven
gas, blast furnace gas, coal-derived gas, producer gas or any other
gas which may have a variable sulfur content).
2.3.3.1 Sulfur Content Determination
2.3.3.1.1 Analyze the total sulfur content of the gaseous fuel
in grain/100 scf, at the frequency specified in Table D-5 of this
appendix. That is: for fuel delivered in discrete shipments or lots,
sample each shipment or lot; for fuel transmitted by pipeline, if a
demonstration is provided under section 2.3.6 of this appendix
showing that the gaseous fuel has a ``low sulfur variability,''
determine the sulfur content daily using either manual sampling or a
gas chromatograph; and for all other gaseous fuels, determine the
sulfur content on an hourly basis using a gas chromatograph.
2.3.3.1.2 Use one of the following methods when using manual
sampling (as applicable to the type of gas combusted) to determine
the sulfur content of the fuel: ASTM D1072-90, ``Standard Test
Method for Total Sulfur in Fuel Gases'', ASTM D4468-85 (Reapproved
1989) ``Standard Test Method for Total Sulfur in Gaseous Fuels by
Hydrogenolysis and Radiometric Colorimetry,'' ASTM D5504-94
``Standard Test Method for Determination of Sulfur Compounds in
Natural Gas and Gaseous Fuels by Gas Chromatography and
Chemiluminescence,'' or ASTM D3246-81 (Reapproved 1987) ``Standard
Test Method for Sulfur in Petroleum Gas By Oxidative
Microcoulometry'' (incorporated by reference under Sec. 75.6).
[[Page 28662]]
2.3.3.1.3 The sampling and analysis of daily manual samples may
be performed by the owner or operator, an outside laboratory, or the
gas supplier. If hourly sampling with a gas chromatograph is
required, or a source chooses to use an online gas chromatograph to
determine daily fuel sulfur content, the owner or operator shall
develop and implement a program to quality assure the data from the
gas chromatograph, in accordance with the manufacturer's recommended
procedures. The quality assurance procedures shall be kept on-site,
in a form suitable for inspection.
2.3.3.1.4 Results of all sample analyses must be available no
later than thirty calendar days after the sample is taken.
2.3.3.2 SO2 Mass Emission Rate
Calculate the SO2 mass emission rate for the gaseous
fuel, in lb/hr, using equation D-4 in section 3.3.1 of this
appendix. Use the appropriate sulfur content, in equation D-4, as
specified in Table D-5 of this appendix. That is, for fuels
delivered by pipeline which demonstrate a low sulfur variability
(under section 2.3.6 of this appendix) use either the daily value or
the highest value in the previous 30 days or for fuels requiring
hourly sulfur content sampling with a gas chromatograph use the
actual hourly sulfur content).
2.3.3.3 Hourly Heat Input Rate
Calculate the hourly heat input rate for combustion of the
gaseous fuel, using the provisions in section 3.4.1 of this
appendix. Use the measured fuel flow rate from section 2.1 of this
appendix and the gross calorific value from section 2.3.4.3 of this
appendix in the calculations.
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
D1826-88, ASTM D3588-91, ASTM D4891-89, GPA Standard 2172-86
``Calculation of Gross Heating Value, Relative Density and
Compressibility Factor for Natural Gas Mixtures from Compositional
Analysis,'' or GPA Standard 2261-90 ``Analysis for Natural Gas and
Similar Gaseous Mixtures by Gas Chromatography'' (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.
2.3.4.1 GCV of Pipeline Natural Gas
Determine the GCV of fuel that is pipeline natural gas, as
defined in Sec. 72.2 of this chapter, at least once per calendar
month. For GCV used in calculations use the specifications in Table
D-5: either the value from the most recent monthly sample, the
highest value specified in a contract or tariff sheet, or the
highest value from the previous year. The fuel GCV value from the
most recent monthly sample shall be used for any month in which that
value is higher than a contract limit. If a unit combusts pipeline
natural gas for less than 48 hours during a calendar month, the
sampling and analysis requirement for GCV is waived for that
calendar month. The preceding waiver is limited by the condition
that at least one analysis for GCV must be performed for each
quarter the unit operates for any amount of time.
2.3.4.2 GCV of Natural Gas
Determine the GCV of fuel that is natural gas, as defined in
Sec. 72.2 of this chapter, on a monthly basis, in the same manner as
described for pipeline natural gas in section 2.3.4.1 of this
appendix.
2.3.4.3 GCV of Other Gaseous Fuels
For gaseous fuels other than natural gas or pipeline natural
gas, determine the GCV as specified in section 2.3.4.3.1, 2.3.4.3.2
or 2.3.4.3.3, as applicable. 2.3.4.3.1 For a gaseous fuel that is
delivered in discrete shipments or lots, determine the GCV for each
shipment or lot. The determination may be made by sampling each
delivery or by sampling the supply tank after each delivery. For
sampling of each delivery, use the highest GCV in the previous
year's samples. For sampling from the tank after each delivery, use
either the most recent GCV sample or the highest GCV in the previous
year. 2.3.4.3.2 For any gaseous fuel that does not qualify as
pipeline natural gas or natural gas and which is not delivered in
shipments or lots which performs the required 720 hour test under
section 2.3.5 of this appendix, and the results of the test
demonstrate that the gaseous fuel has a low GCV variability,
determine the GCV at least monthly. In calculations of hourly heat
input for a unit, use either the most recent monthly sample or the
highest fuel GCV from the previous year's samples. 2.3.4.3.3 For any
other gaseous fuel, determine the GCV at least daily and use the
actual fuel GCV in calculations of unit hourly heat input. If an
online gas chromatograph or on-line calorimeter is used to determine
fuel GCV each day, the owner or operator shall develop and implement
a program to quality assure the data from the gas chromatograph or
on-line calorimeter, in accordance with the manufacturer's
recommended procedures. The quality assurance procedures shall be
kept on-site, in a form suitable for inspection.
2.3.5 Demonstration of Fuel GCV Variability
(a) This demonstration is required of any fuel which does not
qualify as pipeline natural gas or natural gas, and is not delivered
only in shipments or lots. The demonstration data shall be used to
determine whether daily or monthly sampling of the GCV of the
gaseous fuel or blend is required.
(b) To make this demonstration, proceed as follows. Provide a
minimum of 720 hours of data, indicating the GCV of the gaseous fuel
or blend (in Btu/100 scf). The demonstration data shall be obtained
using either: hourly sampling and analysis using the methods in
section 2.3.4 to determine GCV of the fuel; an on-line gas
chromatograph capable of determining fuel GCV on an hourly basis; or
an on-line calorimeter. For gaseous fuel produced by a variable
process, the data shall be representative of and include all process
operating conditions including seasonal and yearly variations in
process which may affect fuel GCV.
(c) The data shall be reduced to hourly averages. The mean GCV
value and the standard deviation from the mean shall be calculated
from the hourly averages. Specifically, the gaseous fuel is
considered to have a low GCV variability, and monthly gas sampling
for GCV may be used, if the mean value of the GCV multiplied by
1.075 is less than the sum of the mean value and one standard
deviation. If the gaseous fuel or blend does not meet this
requirement, then daily fuel sampling and analysis for GCV, using
manual sampling, a gas chromatograph or an on-line calorimeter is
required.
2.3.6 Demonstration of Fuel Sulfur Variability
(a) This demonstration is required for any fuel which does not
qualify as pipeline natural gas or natural gas and is not delivered
in shipments or lots. The results of the demonstration will be used
to determine whether daily or hourly sampling for sulfur in the fuel
is required. To make this demonstration, proceed as follows. Provide
a minimum of 720 hours of data, indicating the total sulfur content
(and hydrogen sulfide content, if needed to define a fuel as either
pipeline natural gas or natural gas) of the gaseous fuel or blend
(in gr/100 scf). The demonstration data shall be obtained using
either manual hourly sampling or an on-line gas chromatograph
capable of determining fuel total sulfur content (and, if
applicable, H2S content) on an hourly basis. For gaseous
fuel produced by a variable process, additional data shall be
provided which is representative of all process operating conditions
including seasonal or annual variations which may affect fuel sulfur
content.
(b) Reduce the data to hourly averages of the total sulfur
content (and hydrogen sulfide content, if applicable) of the fuel.
Then, calculate the mean value of the total sulfur content and
standard deviation in order to determine whether daily sampling of
the sulfur content of the gaseous fuel or blend is sufficient or
whether hourly sampling with a gas chromatograph is required.
Specifically, daily gas sampling and analysis for total sulfur
content, using either manual sampling or an online gas
chromatograph, shall be sufficient, provided that the standard
deviation of the hourly average values from the mean value does not
exceed 5.0 grains per 100 scf. If the gaseous fuel or blend does not
meet this requirement, then hourly sampling of the fuel with a gas
chromatograph and hourly reporting of the average sulfur content of
the fuel is required.
2.4 * * *
2.4.1 Missing Data for Oil and Gas Samples
When fuel sulfur content, gross calorific value or, when
necessary, density data are missing or invalid for an oil or gas
sample taken according to the procedures in section 2.2.3, 2.2.4.1,
2.2.4.2, 2.2.4.3, 2.2.5, 2.2.6, 2.2.7, 2.3.3.1, 2.3.3.1.2, or 2.3.4
of this appendix, then substitute the maximum potential sulfur
content, density, or gross calorific value of that fuel from Table
D-6 of this appendix. Irrespective of which reporting option is
selected (i.e., actual value, contract value or highest value from
the previous year, the missing data values in Table D-6 shall be
reported whenever the
[[Page 28663]]
results of a required sample of sulfur content, GCV or density is
missing or invalid in the current calendar year. The substitute data
value(s) shall be used until the next valid sample for the missing
parameter(s) is obtained. Note that only actual sample results shall
be used to determine the ``highest value from the previous year''
when that reporting option is used; missing data values shall not be
used in the determination.
Table D-6.--Missing Data Substitution Procedures for Sulfur, Density,
and Gross Calorific Value Data
------------------------------------------------------------------------
Missing data substitution maximum
Parameter potential value
------------------------------------------------------------------------
Oil Sulfur Content........... 3.5 percent for residual oil, or
1.0 percent for diesel fuel.
Oil Density.................. 8.5 lb/gal for residual oil, or
7.4 lb/gal for diesel fuel.
Oil GCV...................... 19,500 Btu/lb for residual oil, or 20,000
Btu/lb for diesel fuel.
Gas Sulfur Content........... 0.3 gr/100 scf for pipeline natural gas,
or
1.0 gr/100 scf for natural gas, or
Twice the highest total sulfur content
value recorded in the previous 30 days
when sampling gaseous fuel daily or
hourly.
Gas GCV/Heat Content......... 1100 Btu/scf for pipeline natural gas,
natural gas or landfill gas, or
1500 for butane or refinery gas.
2100 Btu/scf for propane or any other
gaseous fuel.
------------------------------------------------------------------------
2.4.2 Whenever data are missing from any fuel flowmeter that is
part of an excepted monitoring system under appendix D or E to this
part, where the fuel flowmeter data are required to determine the
amount of fuel combusted by the unit, use the procedures in sections
2.4.2.2 and 2.4.2.3 of this appendix to account for the flow rate of
fuel combusted at the unit for each hour during the missing data
period. In addition, a fuel flowmeter used for measuring fuel
combusted by a peaking unit may use the simplified fuel flow missing
data procedure in section 2.4.2.1 of this appendix.
2.4.2.1 Simplified Fuel Flow Missing Data for Peaking Units
If no fuel flow rate data are available for a fuel flowmeter
system installed on a peaking unit (as defined in Sec. 72.2 of this
chapter), then substitute for each hour of missing data using the
maximum potential fuel flow rate. The maximum potential fuel flow
rate is the lesser of the following:
(a) The maximum fuel flow rate the unit is capable of combusting
or (b) the maximum flow rate that the flowmeter can measure (i.e,
upper range value of flowmeter leading to a unit).
2.4.2.2 * * *
2.4.2.3 For hours where two or more fuels are combusted,
substitute the maximum hourly fuel flow rate measured and recorded
by the flowmeter (or flowmeters, where fuel is recirculated) for the
fuel for which data are missing at the corresponding load range
recorded for each missing hour during the previous 720 hours when
the unit combusted that fuel with any other fuel. For hours where no
previous recorded fuel flow rate data are available for that fuel
during the missing data period, calculate and substitute the maximum
potential flow rate of that fuel for the unit as defined in section
2.4.2.2 of this appendix.
2.4.3 * * *
66. Appendix D to part 75 is further amended by:
a. Revising sections 3 through 3.2.1 and 3.2.3;
b. Removing section 3.2.4;
c. Revising sections 3.3 through 3.3.3;
d. Redesignating section 3.4 as 3.6 and revising the first
sentence; and
e. Adding new sections 3.4 through 3.4.3 and sections 3.5
through 3.5.6 to read as follows:
3. Calculations
Calculate hourly SO2 mass emission rate from
combustion of oil fuel using the procedures in section 3.1 of this
appendix. Calculate hourly SO2 mass emission rate from
combustion of gaseous fuel using the procedures in section 3.3 of
this appendix. (Note: the SO2 mass emission rates in
sections 3.1 and 3.3 are calculated such that the rate, when
multiplied by unit operating time, yields the hourly SO2
mass emissions for a particular fuel for the unit.) Calculate hourly
heat input rate for both oil and gaseous fuels using the procedures
in section 3.4 of this appendix. Calculate total SO2 mass
emissions and heat input for each hour, each quarter and the year to
date using the procedures under section 3.5 of this appendix. Where
an oil flowmeter records volumetric flow rate, use the calculation
procedures in section 3.2 of this appendix to calculate the mass
flow rate of oil.
3.1 SO2 Mass Emission Rate Calculation for Oil
3.1.1 Use Equation D-2 to calculate SO2 mass
emission rate per hour (lb/hr):
[GRAPHIC] [TIFF OMITTED] TR26MY99.021
Where:
SO2rate-oil = Hourly mass emission rate of
SO2 emitted from combustion of oil, lb/hr.
OILrate = Mass rate of oil consumed per hr during
combustion, lb/hr.
%Soil = Percentage of sulfur by weight measured in
the sample.
2.0 = Ratio of lb SO 2/lb S.
3.1.2 Record the SO2 mass emission rate from oil for
each hour that oil is combusted.
3.2 Mass Flow Rate Calculation for Volumetric Oil Flowmeters
3.2.1 Where the oil flowmeter records volumetric flow rate
rather than mass flow rate, calculate and record the oil mass flow
rate for each hourly period using hourly oil flow rate measurements
and the density or specific gravity of the oil sample.
* * * * *
3.2.3 Where density of the oil is determined by the applicable
ASTM procedures from section 2.2.6 of this appendix, use Equation D-
3 to calculate the rate of the mass of oil consumed (in lb/hr):
[GRAPHIC] [TIFF OMITTED] TR26MY99.022
Where:
OILrate = Mass rate of oil consumed per hr, lb/hr.
Voil-rate = Volume rate of oil consumed per hr,
measured in scf/hr, gal/hr, barrels/hr, or m \3\/hr.
Doil = Density of oil, measured in lb/scf, lb/gal, lb/
barrel, or lb/m3.
3.3 SO2 Mass Emission Rate Calculation for Gaseous Fuels
3.3.1 Use Equation D-4 to calculate the SO2 mass
emission rate when using the optional gas sampling and analysis
procedures in sections 2.3.1 and 2.3.2 of this appendix, or the
required gas sampling and analysis procedures in section 2.3.3 of
this appendix. Total sulfur content of a fuel must be determined
using the procedures of 2.3.3.1.2 of this appendix:
[[Page 28664]]
[GRAPHIC] [TIFF OMITTED] TR26MY99.023
Where:
SO2rate-gas = Hourly mass rate of
SO2 emitted due to combustion of gaseous fuel, lb/hr.
GASrate = Hourly metered flow rate of gaseous fuel
combusted, 100 scf/hr.
Sgas = Sulfur content of gaseous fuel, in grain/100 scf.
2.0 = Ratio of lb SO2/lb S.
7000 = Conversion of grains/100 scf to lb/100 scf.
3.3.2 Use Equation D-5 to calculate the SO2 mass
emission rate when using a default emission rate from section
2.3.1.1 or 2.3.2.1.1 of this appendix:
[GRAPHIC] [TIFF OMITTED] TR26MY99.024
where:
SO2rate = Hourly mass emission rate of
SO2 from combustion of a gaseous fuel, lb/hr.
ER = SO2 emission rate from section 2.3.1.1 or 2.3.2.1.1,
of this appendix, lb/mmBtu.
HIrate = Hourly heat input rate of a gaseous fuel,
calculated using procedures in section 3.4.1 of this appendix, in
mmBtu/hr.
3.3.3 Record the SO2 mass emission rate for each
hour when the unit combusts a gaseous fuel.
3.4 Calculation of Heat Input Rate
3.4.1 Heat Input Rate for Gaseous Fuels
(a) Determine total hourly gas flow or average hourly gas flow
rate with a fuel flowmeter in accordance with the requirements of
section 2.1 of this appendix and the fuel GCV in accordance with the
requirements of section 2.3.4 of this appendix. If necessary perform
the 720-hour test under section 2.3.5 to determine the appropriate
fuel GCV sampling frequency.
(b) Then, use Equation D-6 to calculate heat input rate from
gaseous fuels for each hour.
[GRAPHIC] [TIFF OMITTED] TR26MY99.025
Where:
HIrate-gas = Hourly heat input rate from combustion of
the gaseous fuel, mmBtu/hr.
GASrate = Average volumetric flow rate of fuel, for the
portion of the hour in which the unit operated, 100 scf/hr.
GCVgas = Gross calorific value of gaseous fuel, Btu/hr.
10 \6\ = Conversion of Btu to mmBtu.
(c) Note that when fuel flow is measured on an hourly totalized
basis (e.g. a fuel flowmeter reports totalized fuel flow for each
hour), before Equation D-6 can be used, the total hourly fuel usage
must be converted from units of 100 scf to units of 100 scf/hr using
Equation D-7:
[GRAPHIC] [TIFF OMITTED] TR26MY99.026
Where:
GASrate = Average volumetric flow rate of fuel for the
portion of the hour in which the unit operated, 100 scf/hr.
GASunit = Total fuel combusted during the hour, 100 scf.
t = Unit operating time, hour 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).
3.4.2 Heat Input Rate From the Combustion of Oil
(a) Determine total hourly oil flow or average hourly oil flow
rate with a fuel flowmeter, in accordance with the requirements of
section 2.1 of this appendix. Determine oil GCV according to the
requirements of section 2.2 of this appendix.
Then, use Equation D-8 to calculate hourly heat input rate from
oil for each hour:
[GRAPHIC] [TIFF OMITTED] TR26MY99.027
Where:
HIrate-oil = Hourly heat input rate from combustion of
oil, mmBtu/hr.
OILrate = Mass rate of oil consumed per hour, as
determined using procedures in section 3.2.3 of this appendix, in
lb/hr, tons/hr, or kg/hr.
GCVoil = Gross calorific value of oil, Btu/lb, Btu/ton,
Btu/kg.
106 = Conversion of Btu to mmBtu.
(b) Note that when fuel flow is measured on an hourly totalized
basis (e.g., a fuel flowmeter reports totalized fuel flow for each
hour), before equation D-8 can be used, the total hourly fuel usage
must be converted from units of lb to units of lb/hr, using equation
D-9:
[GRAPHIC] [TIFF OMITTED] TR26MY99.028
Where:
OILrate = Average fuel flow rate for the portion of the
hour which the unit operated in lb/hr.
OILunit = Total fuel combusted during the hour, lb.
t = Unit operating time, hour 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).
3.4.3 Apportioning Heat Input Rate to Multiple Units
(a) Use the procedure in this section to apportion hourly heat
input rate to two or more units using a single fuel flowmeter which
supplies fuel to the units. (This procedure is not applicable to
units calculating NOX mass emissions using the provisions
of subpart H of this part.) The designated representative may also
petition the Administrator under Sec. 75.66 to use this
apportionment procedure to calculate SO2 and
CO2 mass emissions.
(b) Determine total hourly fuel flow or flow rate through the
fuel flowmeter supplying gas or oil fuel to the units. Convert fuel
flow rates to units of 100 scf for gaseous fuels or to lb for oil,
using the procedures of this appendix. Apportion the fuel to each
unit separately based on hourly output of the unit in MWe
or 1000 lb of steam/hr (klb/hr) using Equation D-10 or D-11, as
applicable:
[GRAPHIC] [TIFF OMITTED] TR26MY99.029
Where:
GASunit = Gas flow apportioned to a unit, 100 scf.
GASmeter = Total gas flow through the fuel flowmeter, 100
scf.
Uoutput = Total unit output, MW or klb/hr.
[[Page 28665]]
[GRAPHIC] [TIFF OMITTED] TR26MY99.030
Where:
OILunit = Oil flow apportioned to a unit, lb.
OILmeter = Total oil flow through the fuel flowmeter, lb.
Uoutput = Total unit output in either MWe or
klb/hr.
(c) Use the total apportioned fuel flow calculated from Equation
D-10 or D-11 to calculate the hourly unit heat input rate, using
Equations D-6 and D-7 (for gas) or Equations D-8 and D-9 (for oil).
3.5 Conversion of Hourly Rates to Hourly, Quarterly and Year to Date
Totals
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:
[GRAPHIC] [TIFF OMITTED] TR26MY99.031
Where:
MSO2-hr = Total mass of SO2 emissions from all
fuels combusted during the hour, lb.
SO2rate-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
range from one hundredth to one quarter of an hour, at the option of
the owner or operator).
3.5.2 Quarterly Total SO2 Mass Emissions
Sum the hourly SO2 mass emissions in lb as determined
from Equation D-12 for all hours in a quarter using Equation D-13:
[GRAPHIC] [TIFF OMITTED] TR26MY99.032
Where:
MSO2-qtr = Total mass of SO2 emissions from
all fuels combusted during the quarter, tons.
MSO2-hr = Hourly SO2 mass emissions determined
using Equation D-12, lb.
2000= Conversion factor from lb to tons.
3.5.3 Year to Date SO2 Mass Emissions
Calculate and record SO2 mass emissions in the year
to date using Equation D-14:
[GRAPHIC] [TIFF OMITTED] TR26MY99.033
Where:
MSO2-YTD = Total SO2 mass emissions for the
year to date, tons.
MSO2-qtr = Total SO2 mass emissions for the
quarter, tons.
3.5.4 Hourly Total Heat Input from the Combustion of all Fuels
Determine the total heat input in mmBtu for each hour from the
combustion of all fuels using Equation D-15:
[GRAPHIC] [TIFF OMITTED] TR26MY99.034
Where:
HIhr = Total heat input from all fuels combusted during
the hour, mmBtu.
HIrate-i =Heat input rate for each type of gas or oil
combusted during the hour, mmBtu/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
range from one hundredth to one quarter of an hour, at the option of
the owner or operator).
3.5.5 Quarterly Heat Input
Sum the hourly heat input values determined from equation D-15
for all hours in a quarter using Equation D-16:
[GRAPHIC] [TIFF OMITTED] TR26MY99.035
Where:
HIqtr = Total heat input from all fuels combusted during
the quarter, mmBtu.
HIhr = Hourly heat input determined using Equation D-15,
mmBtu.
3.5.6 Year-to-Date Heat Input
Calculate and record the total heat input in the year to date
using Equation D-17.
[GRAPHIC] [TIFF OMITTED] TR26MY99.036
HIYTD = Total heat input for the year to date, mmBtu.
HIqtr = Total heat input for the quarter, mmBtu.
3.6 Records and Reports
Calculate and record quarterly and cumulative SO2
mass emissions and heat input for each calendar quarter using the
procedures and equations of section 3.5 of this appendix. * * *
67. Appendix E to part 75 is amended by revising sections 2.4.2,
2.4.3, 2.4.4, 2.5.4 and 2.5.5 to read as follows:
Appendix E to Part 75--Optional NOX Emissions Estimation
Protocol for Gas-Fired Peaking Units and Oil-Fired Peaking Units
* * * * *
2. Procedure
* * * * *
2.4 Procedures for Determining Hourly NOX Emission Rate
* * * * *
2.4.2 Use the graph of the baseline correlation results
(appropriate for the fuel or fuel combination) to determine the
NOX emissions rate (lb/mmBtu) corresponding to the heat
input rate (mmBtu/hr). Input this correlation into the data
acquisition and handling system for the unit. Linearly interpolate
to 0.1 mmBtu/hr heat input rate and 0.01 lb/mmBtu NOX
(0.001 lb/mmBtu NOX after April 1, 2000). For each type
of fuel, calculate NOX emission rate using the baseline
correlation results from the most recent test with that fuel,
beginning with the date and hour of the completion of the most
recent test.
2.4.3 To determine the NOX emission rate for a unit
co-firing fuels that has not been tested for that combination of
fuels, interpolate between the NOX emission rate for each
fuel as follows. Determine the heat input rate for the hour (in
mmBtu/hr) for each fuel and select the corresponding NOX
emission rate for each fuel on the appropriate graph. (When a fuel
is combusted for a partial
[[Page 28666]]
hour, determine the fuel usage time for each fuel and determine the
heat input rate from each fuel as if that fuel were combusted at
that rate for the entire hour in order to select the corresponding
NOX emission rate.) Calculate the total heat input to the
unit in mmBtu for the hour from all fuel combusted using Equation E-
1. Calculate a Btu-weighted average of the emission rates for all
fuels using Equation E-2 of this appendix. For each type of fuel,
calculate NOX emission rate using the baseline
correlation results from the most recent test with that fuel,
beginning with the date and hour of the completion of the most
recent test.
2.4.4 For each hour, record the critical quality assurance
parameters, as identified in the monitoring plan, and as required by
section 2.3 of this appendix from the date and hour of the
completion of the most recent test for each type of fuel.
2.5 Missing Data Procedures
* * * * *
2.5.4 Substitute missing data from a fuel flowmeter using the
procedures in section 2.4.2 of appendix D to this part.
2.5.5 Substitute missing data for gross calorific value of fuel
using the procedures in sections 2.4.1 of appendix D to this part.
68. Appendix E to part 75 is further amended by revising
sections 3.1, 3.3.1, and 3.3.4 to read as follows:
3. Calculations
3.1 Heat Input
Calculate the total heat input by summing the product of heat
input rate and fuel usage time of each fuel, as in the following
equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.037
Where:
HT = Total heat input of fuel flow or a combination of
fuel flows to a unit, mmBtu.
HIfuel 1,2,3,...last = Heat input rate from each fuel, in
mmBtu/hr as determined using Equation F-19 or F-20 in section 5.5 of
appendix F to this part, mmBtu/hr.
t1,2,3....last = Fuel usage time for each fuel (rounded
up to the nearest 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)).
* * * * *
3.3 * * *
3.3.1 Conversion from Concentration to Emission Rate
Convert the NOX concentrations (ppm) and
O2 concentrations to NOX emission rates (to
the nearest 0.01 lb/mmBtu for tests performed prior to April 1,
2000, or to the nearest 0.001 lb/mmBtu for tests performed on and
after April 1, 2000), according to the appropriate one of the
following equations: F-5 in appendix F to this part for dry basis
concentration measurements or 19-3 in Method 19 of appendix A to
part 60 of this chapter for wet basis concentration measurements.
* * * * *
3.3.4 Average NOX Emission Rate During Co-firing of Fuels
[GRAPHIC] [TIFF OMITTED] TR26MY99.038
Where:
Eh = NOX emission rate for the unit for the
hour, lb/mmBtu.
Ef = NOX emission rate for the unit for a
given fuel at heat input rate HIf, lb/mmBtu.
HIf = Heat input rate for the hour for a given fuel,
during the fuel usage time, as determined using Equation F-19 or F-
20 in section 5.5 of appendix F to this part, mmBtu/hr.
HT = Total heat input for all fuels for the hour from
Equation E-1.
tf = Fuel usage time for each fuel (rounded up to the
nearest 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)).
Note: For hours where a fuel is combusted for only part of the
hour, use the fuel flow rate or mass flow rate during the fuel usage
time, instead of the total fuel flow or mass flow during the hour,
when calculating heat input rate using Equation F-19 or F-20.
69. Appendix F to part 75 is amended by revising sections 2,
2.1, 2.2, 2.3, and 2.4 to read as follows:
Appendix F to Part 75--Conversion Procedures
* * * * *
2. Procedures for SO2 Emissions
Use the following procedures to compute hourly SO2
mass emission rate (in lb/hr) and quarterly and annual
SO2 total mass emissions (in tons). Use the procedures in
Method 19 in appendix A to part 60 of this chapter to compute hourly
SO2 emission rates (in lb/mmBtu) for qualifying Phase I
technologies. When computing hourly SO2 emission rate in
lb/mmBtu, a minimum concentration of 5.0 percent CO2 and
a maximum concentration of 14.0 percent O2 may be
substituted for measured diluent gas concentration values at boilers
during hours when the hourly average concentration of CO2
is less than 5.0 percent CO2 or the hourly average
concentration of O2 is greater than 14.0 percent
O2.
2.1 When measurements of SO2 concentration and flow
rate are on a wet basis, use the following equation to compute
hourly SO2 mass emission rate (in lb/hr):
[GRAPHIC] [TIFF OMITTED] TR26MY99.039
Where:
Eh = Hourly SO2 mass emission rate during unit
operation, lb/hr.
K = 1.660 x 10-7 for SO2, (lb/scf)/ppm.
Ch = Hourly average SO2 concentration during
unit operation, stack moisture basis, ppm.
Qh = Hourly average volumetric flow rate during unit
operation, stack moisture basis, scfh.
2.2 When measurements by the SO2 pollutant concentration
monitor are on a dry basis and the flow rate monitor measurements
are on a wet basis, use the following equation to compute hourly
SO2 mass emission rate (in lb/hr):
[GRAPHIC] [TIFF OMITTED] TR26MY99.040
where:
Eh = Hourly SO2 mass emission rate during unit
operation, lb/hr.
K = 1.660 x 10-7 for SO2, (lb/scf)/ppm.
Chp = Hourly average SO2 concentration during
unit operation, ppm (dry).
Qhs = Hourly average volumetric flow rate during unit
operation, scfh as measured (wet).
%H2O = Hourly average stack moisture content during unit
operation, percent by volume.
2.3 Use the following equations to calculate total
SO2 mass emissions for each calendar quarter (Equation F-
3) and for each calendar year (Equation F-4), in tons:
[GRAPHIC] [TIFF OMITTED] TR26MY99.041
Where:
Eq = Quarterly total SO2 mass emissions, tons.
Eh = Hourly SO2 mass emission rate, lb/hr.
[[Page 28667]]
th = Unit operating time, hour 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).
n = Number of hourly SO2 emissions values during calendar
quarter.
2000 = Conversion of 2000 lb per ton.
[GRAPHIC] [TIFF OMITTED] TR26MY99.042
Where:
Ea = Annual total SO2 mass emissions, tons.
Eq = Quarterly SO2 mass emissions, tons.
q = Quarters for which Eq are available during calendar
year.
2.4 Round all SO2 mass emission rates and totals to
the nearest tenth.
70. Appendix F to part 75 is further amended by revising
sections 3.3.2, 3.3.3, 3.3.4, 3.4, and 3.5 to read as follows:
3. Procedures for NOX Emission Rate
* * * * *
3.3 * * *
3.3.2 E = Pollutant emissions during unit operation, lb/mmBtu.
3.3.3 Ch = Hourly average pollutant concentration during
unit operation, ppm.
3.3.4 %O2, %CO2 = Oxygen or carbon dioxide
volume during unit operation (expressed as percent O2 or
CO2). A minimum concentration of 5.0 percent
CO2 and a maximum concentration of 14.0 percent
O2 may be substituted for measured diluent gas
concentration values at boilers during hours when the hourly average
concentration of CO2 is
< 5.0 percent CO2 or the hourly average concentration of
O2 is > 14.0 percent O2. A minimum
concentration of 1.0 percent CO2 and a maximum
concentration of 19.0 percent O2 may be substituted for
measured diluent gas concentration values at stationary gas turbines
during hours when the hourly average concentration of CO2
is < 1.0 percent CO2 or the hourly average concentration
of O2 is > 19.0 percent O2.
* * * * *
3.4 Use the following equations to calculate the average
NOX emission rate for each calendar quarter (Equation F-
9) and the average emission rate for the calendar year (Equation F-
10), in lb/mmBtu:
[GRAPHIC] [TIFF OMITTED] TR26MY99.043
Where:
Eq = Quarterly average NOX emission rate, lb/
mmBtu.
Ei = Hourly average NOX emission rate during
unit operation, lb/mmBtu.
n = Number of hourly rates during calendar quarter.
[GRAPHIC] [TIFF OMITTED] TR26MY99.044
Where:
Ea = Average NOX emission rate for the
calendar year, lb/mmBtu.
Ei = Hourly average NOX emission rate during
unit operation, lb/mmBtu.
m = Number of hourly rates for which Ei is available in
the calendar year.
3.5 Round all NOX emission rates to the nearest 0.01
lb/mmBtu prior to April 1, 2000, and to the nearest 0.001 lb/mmBtu
on and after April 1, 2000.
71. Appendix F to part 75 is further amended by revising
sections 4.1, 4.2, 4.3, 4.4, and 4.4.1 to read as follows:
4. Procedures for CO2 Mass Emissions
* * * * *
4.1 When CO2 concentration is measured on a wet
basis, use the following equation to calculate hourly CO2
mass emissions rates (in tons/hr):
[GRAPHIC] [TIFF OMITTED] TR26MY99.045
Where:
Eh = Hourly CO2 mass emission rate during unit
operation, tons/hr.
K = 5.7 X 10-7 for CO2, (tons/scf) /
%CO2.
Ch = Hourly average CO2 concentration during
unit operation, wet basis, percent CO2. For boilers, a
minimum concentration of 5.0 percent CO2 may be
substituted for the measured concentration when the hourly average
concentration of CO2 is < 5.0 percent CO2,
provided that this minimum concentration of 5.0 percent
CO2 is also used in the calculation of heat input for
that hour. For stationary gas turbines, a minimum concentration of
1.0 percent CO2 may be substituted for measured diluent
gas concentration values during hours when the hourly average
concentration of CO2 is < 1.0 percent CO2,
provided that this minimum concentration of 1.0 percent
CO2 is also used in the calculation of heat input for
that hour.
Qh = Hourly average volumetric flow rate during unit
operation, wet basis, scfh.
4.2 When CO2 concentration is measured on a dry
basis, use Equation F-2 to calculate the hourly CO2 mass
emission rate (in tons/hr) with a K-value of 5.7 x 10-7
(tons/scf) percent CO2, where Eh = hourly
CO2 mass emission rate, tons/hr and Chp =
hourly average CO2 concentration in flue, dry basis,
percent CO2.
4.3 Use the following equations to calculate total
CO2 mass emissions for each calendar quarter (Equation F-
12) and for each calendar year (Equation F-13):
[GRAPHIC] [TIFF OMITTED] TR26MY99.046
Where:
ECO2q = Quarterly total CO2 mass emissions,
tons.
Eh = Hourly CO2 mass emission rate, tons/hr.
th=Unit operating time, 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).
HR = Number of hourly CO2 mass emission rates
available during calendar quarter.
[GRAPHIC] [TIFF OMITTED] TR26MY99.047
Where:
ECO2a = Annual total CO2 mass emission,
ECO2q = Quarterly total CO2 mass emissions,
tons.
q = Quarters for which ECO2q are available during
calendar year.
4.4 For an affected unit, when the owner or operator is
continuously monitoring O2 concentration (in percent by
volume) of flue gases using an O2 monitor, use the
equations and procedures in section 4.4.1 and 4.4.2 of this appendix
to determine hourly CO2 mass emissions (in tons).
4.4.1 Use appropriate F and Fc factors from section
3.3.5 of this appendix in one of the following equations (as
applicable) to determine hourly average CO2 concentration
of flue gases (in percent by volume):
[GRAPHIC] [TIFF OMITTED] TR26MY99.048
[[Page 28668]]
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. For boilers, a maximum
concentration of 14.0 percent O2 may be substituted for
the measured concentration when the hourly average concentration of
O2 is > 14.0 percent O2, provided that this
maximum concentration of 14.0 percent O2 is also used in
the calculation of heat input for that hour. For stationary gas
turbines, a maximum concentration of 19.0 percent O2 may
be substituted for measured diluent gas concentration values during
hours when the hourly average concentration of O2 is >
19.0 percent O2, provided that this maximum concentration
of 19.0 percent O2 is also used in the calculation of
heat input for that hour.
[GRAPHIC] [TIFF OMITTED] TR26MY99.061
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. For boilers, a maximum
concentration of 14.0 percent O2 may be substituted for
the measured concentration when the hourly average concentration of
O2 is > 14.0 percent O2, provided that this
maximum concentration of 14.0 percent O2 is also used in
the calculation of heat input for that hour. For stationary gas
turbines, a maximum concentration of 19.0 percent O2 may
be substituted for measured diluent gas concentration values during
hours when the hourly average concentration of O2 is >
19.0 percent O2, provided that this maximum concentration
of 19.0 percent O2 is also used in the calculation of
heat input for that hour.
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.
* * * * *
72. Appendix F to part 75 is amended by revising sections 5
through 5.2.4; adding sections 5.3 through 5.3.2; revising sections
5.5, 5.5.1 and 5.5.2; and by adding new sections 5.6 through 5.6.2
and 5.7 and by removing and revising section 5.4 to read as follows:
5. Procedures for Heat Input
Use the following procedures to compute heat input rate to an
affected unit (in mmBtu/hr or mmBtu/day):
5.1 Calculate and record heat input rate to an affected unit on
an hourly basis, except as provided in sections 5.5 through 5.5.7.
The owner or operator may choose to use the provisions specified in
Sec. 75.16(e) or in section 2.1.2 of appendix D to this part in
conjunction with the procedures provided in sections 5.6 through
5.6.2 to apportion heat input among each unit using the common stack
or common pipe header.
5.2 For an affected unit that has a flow monitor (or approved
alternate monitoring system under subpart E of this part for
measuring volumetric flow rate) and a diluent gas (O2 or
CO2) monitor, use the recorded data from these monitors
and one of the following equations to calculate hourly heat input
rate (in mmBtu/hr).
5.2.1 When measurements of CO2 concentration are on a
wet basis, use the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.049
Where:
HI = Hourly heat input rate during unit operation, mmBtu/hr.
Qw = Hourly average volumetric flow rate during unit
operation, wet basis, scfh.
Fc = Carbon-based F-factor, listed in section 3.3.5
of this appendix for each fuel, scf/mmBtu.
%CO2w = Hourly concentration of CO2 during
unit operation, percent CO2 wet basis. For boilers, a
minimum concentration of 5.0 percent CO2 may be
substituted for the measured concentration when the hourly average
concentration of CO2 is < 5.0 percent CO2,
provided that this minimum concentration of 5.0 percent
CO2 is also used in the calculation of CO2
mass emissions for that hour. For stationary gas turbines, a minimum
concentration of 1.0 percent CO2 may be substituted for
measured diluent gas concentration values during hours when the
hourly average concentration of CO2 is < 1.0 percent
CO2, provided that this minimum concentration of 1.0
percent CO2 is also used in the calculation of
CO2 mass emissions for that hour.
5.2.2 When measurements of CO2 concentration are on a
dry basis, use the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.051
[[Page 28669]]
Where:
HI = Hourly heat input rate during unit operation, mmBtu/hr.
Qh = Hourly average volumetric flow rate during unit
operation, wet basis, scfh.
Fc = Carbon-based F-Factor, listed in section 3.3.5 of
this appendix for each fuel, scf/mmBtu.
%CO2d = Hourly concentration of CO2 during
unit operation, percent CO2 dry basis. For boilers, a
minimum concentration of 5.0 percent CO2 may be
substituted for the measured concentration when the hourly average
concentration of CO2 is < 5.0 percent CO2,
provided that this minimum concentration of 5.0 percent
CO2 is also used in the calculation of CO2
mass emissions for that hour. For stationary gas turbines, a minimum
concentration of 1.0 percent CO2 may be substituted for
measured diluent gas concentration values during hours when the
hourly average concentration of CO2 is < 1.0 percent
CO2, provided that this minimum concentration of 1.0
percent CO2 is also used in the calculation of
CO2 mass emissions for that hour.
%H2O = Moisture content of gas in the stack, percent.
5.2.3 When measurements of O2 concentration are on a
wet basis, use the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.052
Where:
HI = Hourly heat input rate during unit operation, mmBtu/hr.
Qw = Hourly average volumetric flow rate during unit
operation, wet basis, scfh.
F = Dry basis F-factor, listed in section 3.3.5 of this appendix
for each fuel, dscf/mmBtu.
%O2w = Hourly concentration of O2 during unit
operation, percent O2 wet basis. For boilers, a maximum
concentration of 14.0 percent O2 may be substituted for
the measured concentration when the hourly average concentration of
O2 is > 14.0 percent O2, provided that this
maximum concentration of 14.0 percent O2 is also used in
the calculation of CO2 mass emissions for that hour. For
stationary gas turbines, a maximum concentration of 19.0 percent
O2 may be substituted for measured diluent gas
concentration values during hours when the hourly average
concentration of O2 is > 19.0 percent O2,
provided that this maximum concentration of 19.0 percent
O2 is also used in the calculation of CO2 mass
emissions for that hour.
%H2O = Hourly average stack moisture content, percent by
volume.
5.2.4 When measurements of O2 concentration are on a
dry basis, use the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.053
[[Page 28670]]
Where:
HI = Hourly heat input rate during unit operation, mmBtu/hr.
Qw = Hourly average volumetric flow during unit
operation, wet basis, scfh.
F = Dry basis F-factor, listed in section 3.3.5 of this appendix
for each fuel, dscf/mmBtu.
%H2O = Moisture content of the stack gas, percent.
%O2d = Hourly concentration of O2 during unit
operation, percent O2 dry basis. For boilers, a maximum
concentration of 14.0 percent O2 may be substituted for
the measured concentration when the hourly average concentration of
O2 is > 14.0 percent O2, provided that this
maximum concentration of 14.0 percent O2 is also used in
the calculation of CO2 mass emissions for that hour. For
stationary gas turbines, a maximum concentration of 19.0 percent
O2 may be substituted for measured diluent gas
concentration values during hours when the hourly average
concentration of O2 is > 19.0 percent O2,
provided that this maximum concentration of 19.0 percent
O2 is also used in the calculation of CO2 mass
emissions for that hour.
5.3 Heat Input Summation (for Heat Input Determined Using a Flow
Monitor and Diluent Monitor)
5.3.1 Calculate total quarterly heat input for a unit or common
stack using a flow monitor and diluent monitor to calculate heat
input, using the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.054
Where:
HIq = Total heat input for the quarter, mmBtu.
HIi = Hourly heat input rate during unit operation, using
Equation F-15, F-16, F-17, or F-18, mmBtu/hr.
ti = Hourly operating time for the unit or common stack,
hour 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).
5.3.2 Calculate total cumulative heat input for a unit or
common stack using a flow monitor and diluent monitor to calculate
heat input, using the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.055
Where:
HIc = Total heat input for the year to date, mmBtu.
HIq = Total heat input for the quarter, mmBtu.
5.4 [Reserved]
5.5 For a gas-fired or oil-fired unit that does not have a flow
monitor and is using the procedures specified in appendix D to this
part to monitor SO2 emissions or for any unit using a
common stack for which the owner or operator chooses to determine
heat input by fuel sampling and analysis, use the following
procedures to calculate hourly heat input rate in mmBtu/hr. The
procedures of section 5.5.3 of this appendix shall not be used to
determine heat input from a coal unit that is required to comply
with the provisions of this part for monitoring, recording, and
reporting NOX mass emissions under a State or federal
NOX mass emission reduction program.
5.5.1(a) When the unit is combusting oil, use the following
equation to calculate hourly heat input rate:
[GRAPHIC] [TIFF OMITTED] TR26MY99.056
Where:
HIo = Hourly heat input rate from oil, mmBtu/hr.
Mo = Mass rate of oil consumed per hour, as determined
using procedures in appendix D to this part, in lb/hr, tons/hr, or
kg/hr.
GCVo = Gross calorific value of oil, as measured by ASTM
D240-87 (Reapproved 1991), ASTM D2015-91, or ASTM D2382-88 for each
oil sample under section 2.2 of appendix D to this part, Btu/unit
mass (incorporated by reference under Sec. 75.6).
106 = Conversion of Btu to mmBtu.
(b) When performing oil sampling and analysis solely for the
purpose of the missing data procedures in Sec. 75.36, oil samples
for measuring GCV may be taken weekly, and the procedures specified
in appendix D to this part for determining the mass rate of oil
consumed per hour are optional.
5.5.2 When the unit is combusting gaseous fuels, use the
following equation to calculate heat input rate from gaseous fuels
for each hour:
[GRAPHIC] [TIFF OMITTED] TR26MY99.062
Where:
HIg = Hourly heat input rate from gaseous fuel, mmBtu/hour.
Qg = Metered flow rate of gaseous fuel combusted during
unit operation, hundred cubic feet.
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 D1826-88, ASTM D3588-91, ASTM
D4891-89, GPA Standard 2172-86 ``Calculation of Gross Heating Value,
Relative Density and Compressibility Factor for Natural Gas Mixtures
from Compositional Analysis,'' or GPA Standard 2261-90 ``Analysis
for Natural Gas and Similar Gaseous Mixtures by Gas
Chromatography,'' Btu/100 scf (incorporated by reference under
Sec. 75.6).
106 = Conversion of Btu to mmBtu.
* * * * *
5.6 Heat Input Rate Apportionment for Units Sharing a Common
Stack or Pipe
5.6.1 Where applicable, the owner or operator of an affected
unit that determines heat input rate at the unit level by
apportioning the heat input monitored at a common stack or common
pipe using megawatts should apportion the heat input rate using the
following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.057
Where:
HIi = Heat input rate for a unit, mmBtu/hr.
HIcs = Heat input rate at the common stack or pipe,
mmBtu/hr.
MWi = Gross electrical output, MWe.
ti = Operating time at a particular unit, hour 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).
tCS = Operating time at common stack, hour 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).
n = Total number of units using the common stack.
i = Designation of a particular unit.
[[Page 28671]]
5.6.2 Where applicable, the owner or operator of an affected unit
that determines the heat input rate at the unit level by
apportioning the heat input rate monitored at a common stack or
common pipe using steam load should apportion the heat input rate
using the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.058
Where:
HIi = Heat input rate for a unit, mmBtu/hr.
HICS = Heat input rate at the common stack or pipe,
mmBtu/hr.
SF = Gross steam load, lb/hr.
ti = Operating time at a particular unit, hour 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).
tCS = Operating time at common stack, hour 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).
n = Total number of units using the common stack.
i = Designation of a particular unit.
5.7 Heat Input Rate Summation for Units with Multiple Stacks or Pipes
The owner or operator of an affected unit that determines the
heat input rate at the unit level by summing the heat input rates
monitored at multiple stacks or multiple pipes should sum the heat
input rates using the following equation:
[GRAPHIC] [TIFF OMITTED] TR26MY99.059
Where:
HIUnit = Heat input rate for a unit, mmBtu/hr.
HIs = Heat input rate for each stack or duct leading from
the unit, mmBtu/hr.
tUnit = Operating time for the unit, hour or fraction of
the hour (in equal increments that can range from one hundredth to
one quarter of an hour, at the option of the owner or operator).
ts = Operating time during which the unit is exhausting
through the stack or duct, hour or fraction of the hour (in equal
increments that can range from one hundredth to one quarter of an
hour, at the option of the owner or operator).
73. Appendix F is further amended by revising section 7 to read
as follows:
7. Procedures for SO2 Mass Emissions at Units With
SO2 Continuous Emission Monitoring Systems During the
Combustion of Pipeline Natural Gas or Natural Gas
The owner or operator shall use the following equation to
calculate hourly SO2 mass emissions as allowed for units
with SO2 continuous emission monitoring systems if,
during the combustion of gaseous fuel that meets the definition of
pipeline natural gas or natural gas in Sec. 72.2 of this chapter,
SO2 emissions are determined in accordance with
Sec. 75.11(e)(1).
[GRAPHIC] [TIFF OMITTED] TR26MY99.060
Where:
Eh = Hourly SO2 mass emissions, lb/hr.
ER = Applicable SO2 default emission rate from section
2.3.1.1 or 2.3.2.1.1 of appendix D to this part, lb/mmBtu.
HI = Hourly heat input, as determined using the procedures of
section 5.2 of this appendix.
74. Appendix F is further amended by correcting section 8 to
read as follows:
8. Procedures for NOX Mass Emissions
The owner or operator of a unit that is required to monitor,
record, and report NOX mass emissions under a State or
federal NOX mass emission reduction program must use the
procedures in section 8.1, 8.2, or 8.3, as applicable, to account
for hourly NOX mass emissions, and the procedures in
section 8.4 to account for quarterly, seasonal, and annual
NOX mass emissions to the extent that the provisions of
subpart H of this part are adopted as requirements under such a
program.
75. Appendix G to part 75 is amended by revising the paragraph
defining the term ``Wc'' that follows Equation G-1 and by
revising the paragraph defining the term ``Fc'' that follows
Equation G-4 to read as follows:
Appendix G to Part 75--Determination of CO2 Emissions
* * * * *
2. Procedures for Estimating CO2 Emissions From
Combustion
* * * * *
2.1 * * *
(Eq. G-1)
Where:
* * * * *
Wc = Carbon burned, lb/day, determined using fuel
sampling and analysis and fuel feed rates. Collect at least one fuel
sample during each week that the unit combusts coal, one sample per
each shipment or delivery for oil and diesel fuel, one fuel sample
for each delivery for gaseous fuel in lots, one sample per day or
per hour (as applicable) for each gaseous fuel that is required to
be sampled daily or hourly for gross calorific value under section
2.3.5.6 of appendix D to this part, and one sample per month for
each gaseous fuel that is required to be sampled monthly for gross
calorific value under section 2.3.4.1 or 2.3.4.2 of appendix D to
this part. Collect coal samples from a location in the fuel handling
system that provides a sample representative of the fuel bunkered or
consumed during the week. Determine the carbon content of each fuel
sampling using one of the following methods: ASTM D3178-89 or ASTM
D5373-93 for coal; ASTM D5291-92 ``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 D3238-90 and either ASTM D2502-87 or
ASTM D2503-82 (Reapproved 1987) for oil; and computations based on
ASTM D1945-91 or ASTM D1946-90 for gas. Use daily fuel feed rates
from company records for all fuels and the carbon content of the
most recent fuel sample under this section to determine tons of
carbon per day from combustion of each fuel. (All ASTM methods are
incorporated by reference under Sec. 75.6.) Where more than one fuel
is combusted during a calendar day, calculate total tons of carbon
for the day from all fuels.
* * * * *
2.3 * * *
(Eq. G-4)
Where:
* * * * *
Fc = Carbon based F-factor, 1040 scf/mmBtu for natural
gas; 1,240 scf/mmBtu for crude, residual, or distillate oil; and
calculated according to the procedures in section 3.3.5 of appendix
F to this part for other gaseous fuels.
* * * * *
[[Page 28672]]
76. Appendix G to part 75 is amended by adding new sections 5
through 5.3 to read as follows:
5. Missing Data Substitution Procedures for Fuel Analytical Data
Use the following procedures to substitute for missing fuel
analytical data used to calculate CO2 mass emissions
under this appendix.
5.1 Missing Carbon Content Data Prior to
4/1/2000
Prior to April 1, 2000, follow either the procedures of this
section or the procedures of section 5.2 of this appendix to
substitute for missing carbon content data. On and after April 1,
2000, use the procedures of section 5.2 of this appendix to
substitute for missing carbon content data, not the procedures of
this section.
5.1.1 Most Recent Previous Data
Substitute the most recent, previous carbon content value
available for that fuel type (gas, oil, or coal) of the same grade
(for oil) or rank (for coal). To the extent practicable, use a
carbon content value from the same fuel supply. Where no previous
carbon content data are available for a particular fuel type or rank
of coal, substitute the default carbon content from Table G-1 of
this appendix.
5.1.2 [Reserved]
5.2 Missing Carbon Content Data On and After 4/1/2000
Prior to April 1, 2000, follow either the procedures of this
section or the procedures of section 5.1 of this appendix to
substitute for missing carbon content data. On and after April 1,
2000, use the procedures of this section to substitute for missing
carbon content data.
5.2.1 In all cases (i.e., for weekly coal samples or composite
oil samples from continuous sampling, for oil samples taken from the
storage tank after transfer of a new delivery of fuel, for as-
delivered samples of oil, diesel fuel, or gaseous fuel delivered in
lots, and for gaseous fuel that is supplied by a pipeline and
sampled monthly, daily or hourly for gross calorific value) when
carbon content data is missing, report the appropriate default value
from Table G-1.
5.2.2 The missing data values in Table G-1 shall be reported
whenever the results of a required sample of fuel carbon content are
either missing or invalid. The substitute data value shall be used
until the next valid carbon content sample is obtained.
Table G-1.--Missing Data Substitution Procedures for Missing Carbon
Content Data
------------------------------------------------------------------------
Sampling technique/
Parameter frequency Missing data value
------------------------------------------------------------------------
Oil and coal carbon content. All oil and coal Most recent,
samples, prior to previous carbon
April 1, 2000. content value
available for that
grade of oil, or
default value, in
this table.
Gas carbon content.......... All gaseous fuel Most recent,
samples, prior to previous carbon
April 1, 2000. content value
available for that
type of gaseous
fuel, or default
value, in this
table.
Default coal carbon content. All, on and after Anthracite: 90.0
April 1, 2000. percent.
Bituminous: 85.0
percent.
Subbituminous/
Lignite: 75.0
percent.
Default oil carbon content.. All, on and after 90.0 percent.
April 1, 2000.
Default gas carbon content.. All, on and after Natural gas: 75.0
April 1, 2000. percent.
Other gaseous fuels:
90.0 percent.
------------------------------------------------------------------------
5.3 Gross Calorific Value Data
For a gas-fired unit using the procedures of section 2.3 of this
appendix to determine CO2 emissions, substitute for
missing gross calorific value data used to calculate heat input by
following the missing data procedures for gross calorific value in
section 2.4 of appendix D to this part.
Appendix H to Part 75--Revised Traceability Protocol No. 1
77. Appendix H to part 75 is removed and reserved.
Appendix J to Part 75--Compliance Dates for Revised Recordkeeping
Requirements and Missing Data Procedures
78. Appendix J to part 75 is removed and reserved.
[FR Doc. 99-8939 Filed 5-25-99; 8:45 am]
BILLING CODE 6560-50-U