Acid Rain Program; Continuous Emission Monitoring Rule Revisions
Related Material
[Federal Register: May 26, 1999 (Volume 64, Number 101)]
[Rules and Regulations]
[Page 28563-28612]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr26my99-19]
[[Page 28563]]
_______________________________________________________________________
Part II
Environmental Protection Agency
_______________________________________________________________________
40 CFR Parts 72 and 75
Acid Rain Program; Continuous Emission Monitoring Rule Revisions; Final
Rule
[[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.
-----------------------------------------------------------------------
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 (SO<INF>2</INF>),
nitrogen oxides (NOX) and carbon dioxide (CO<INF>2</INF>)
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
SO<INF>2</INF> and Heat Input Methodologies
2. Changes to the Definitions of ``Pipeline Natural Gas'' and
``Natural Gas''
3. Changes to the Methodology for Calculating SO<INF>2</INF>
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
------------------------------------------------------------------------
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 (CO<INF>2</INF>),
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 (SO<INF>2</INF>) emissions data
protocol for gas-fired and oil-fired units (Appendix D); (15)
determination of CO<INF>2</INF> 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 SO<INF>2</INF>
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 SO<INF>2</INF> mass emission rates in
lb/hr. Section 75.13(a) of the rule, as amended on May 17, 1995,
contains provisions for CO<INF>2</INF> monitoring paralleling the
provisions of Sec. 75.11(b); that is, when CO<INF>2</INF> concentration
is measured on a dry basis, a correction for stack gas moisture content
is needed to accurately determine the CO<INF>2</INF> mass emissions.
The stack gas moisture content is also needed when a dry-basis
O<INF>2</INF> monitor is used to account for CO<INF>2</INF> 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
SO<INF>2</INF>, CO<INF>2</INF>, 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
SO<INF>2</INF> mass emission rates, CO<INF>2</INF> mass emission rates,
NOX emission rates and heat input values. An error of 1.0
percent H<INF>2</INF>O 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 SO<INF>2</INF>, CO<INF>2</INF>, 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 (O<INF>2</INF>)
analyzer (or analyzers) capable of measuring O<INF>2</INF> 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 O<INF>2</INF> 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
O<INF>2</INF> analyzers, the proposed span values and performance
specifications for calibration error, linearity, and cycle time would
be the same as the current specifications for O<INF>2</INF> 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
<plus-minus> 1.0 percent H<INF>2</INF>O.
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 <ls-thn-eq>7.5 percent or a mean difference between the CEMS and
reference method values within <plus-minus> 0.7 percent H<INF>2</INF>O,
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 (<gr-thn-eq>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 <plus-minus> 1.0 to <plus-minus> 1.5% H<INF>2</INF>O, 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
SO<INF>2</INF>-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% <RA <ls-thn-eq>15% for a semiannual RATA
frequency and RA <ls-thn-eq>10% for an annual RATA frequency, and that
the alternate RA specification, in terms of the mean difference, should
be <plus-minus> 2.0% H<INF>2</INF>O for a semiannual frequency and
<plus-minus> 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%
H<INF>2</INF>O 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 <plus-minus> 1.0% H<INF>2</INF>O (for
semiannual RATA frequency) and
<plus-minus> 0.7% H<INF>2</INF>O (for annual RATA frequency) have been
increased, respectively, to
<plus-minus> 1.5% H<INF>2</INF>O and <plus-minus>1.0% H<INF>2</INF>O.
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 SO<INF>2</INF>, NOX, and flow, as recommended
by the commenters. The moisture missing data algorithm is modeled after
the standard SO<INF>2</INF> 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 CO<INF>2</INF> 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''
SO<INF>2</INF> 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 SO<INF>2</INF> missing data algorithm
is appropriate). The specific equations for which the regular
SO<INF>2</INF> 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 SO<INF>2</INF>, NOX, flow
rate or CO<INF>2</INF>, 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
SO<INF>2</INF> and CO<INF>2</INF>, 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 O<INF>2</INF>, 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 SO<INF>2</INF>, 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 SO<INF>2</INF>
and CO<INF>2</INF>, MER for NOX emission rate and maximum
potential flow rate for flow) as suggested by the commenters. Note that
for O<INF>2</INF> 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 SO<INF>2</INF>
monitor is an approximation of the highest SO<INF>2</INF> 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
SO<INF>2</INF>, NOX, diluent gas (O<INF>2</INF> or
CO<INF>2</INF>), and volumetric flow rate. For SO<INF>2</INF>, 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
SO<INF>2</INF> and NOX span values were then determined by
multiplying the MPC by 1.25. For CO<INF>2</INF> and O<INF>2</INF>, a
span value of 20.0 percent CO<INF>2</INF> or O<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF>, 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 SO<INF>2</INF> 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 CO<INF>2</INF> or 14.0 percent O<INF>2</INF> for boilers (or
1.0 percent CO<INF>2</INF> or 19.0 percent O<INF>2</INF> for turbines)
in the NOX MER calculation.
The proposed rule provided a definition of the MPC for
CO<INF>2</INF>. The MPC would be 14.0 percent CO<INF>2</INF> for
boilers and 6.0 percent CO<INF>2</INF> for combustion turbines.
Alternatively, the MPC for CO<INF>2</INF> 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 SO<INF>2</INF>
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 SO<INF>2</INF>, 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
CO<INF>2</INF> and O<INF>2</INF> monitors, the owner or operator would
be given maximum flexibility in selecting an appropriate span value.
For CO<INF>2</INF> monitors installed on boilers, any representative
span value between 14.0 percent and 20.0 percent CO<INF>2</INF> would
be acceptable. For combustion turbines, any representative
CO<INF>2</INF> span value between 6.0 and 14.0 percent CO<INF>2</INF>
could be used. For O<INF>2</INF> monitors, a span value between 15.0
percent and 25.0 percent O<INF>2</INF> could be selected and an
alternative O<INF>2</INF> 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
(<ls-thn-eq>0.05% sulfur by weight); (2) for SO<INF>2</INF> or
NOX readings on the high range for an affected unit with
SO<INF>2</INF> or NOX emission controls and two span values;
and (3) when SO<INF>2</INF> or NOX readings are less than
20.0 percent of the low measurement range for a dual-span unit with
SO<INF>2</INF> 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 SO<INF>2</INF> 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 <gr-thn-eq>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 <gr-thn-eq>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 SO<INF>2</INF> or
NOX analyzer, the final rule allows the low and high ranges
to be represented as a single component of a primary SO<INF>2</INF> 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 SO<INF>2</INF>, NOX, CO<INF>2</INF> and
O<INF>2</INF> span values and supported the concept of a ``default high
range value.'' One commenter, however, opposed the use of purified
instrument air for O<INF>2</INF> 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
O<INF>2</INF> 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 SO<INF>2</INF> range was exceeded and the
estimated SO<INF>2</INF> 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 CO<INF>2</INF> in
section 2.3.1 of Appendix A to mean that his existing CO<INF>2</INF>
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 SO<INF>2</INF> scrubbers,
the vast majority of the data is collected on the low range. Therefore,
the SO<INF>2</INF> RATA should be performed on that range. If the
scrubber malfunctions at the time of a scheduled SO<INF>2</INF> 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 SO<INF>2</INF> 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
E<INF>f</INF> (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 E<INF>f</INF> 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 <gr-thn-eq>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 <plus-minus> 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 <plus-minus>
3.0 ppm or 0.3 percent CO<INF>2</INF> (or O<INF>2</INF>) 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 <plus-minus>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
<plus-minus>10% of the reference method value, or <plus-minus>15 ppm,
or <plus-minus>0.02
lb/mmBtu, or <plus-minus>1.5% H<INF>2</INF>O, 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 <plus-minus>2.5 percent of
the instrument span (<plus-minus>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., <plus-minus>5.0 percent of span for gas
monitors and <plus-minus>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 SO<INF>2</INF> 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
SO<INF>2</INF> 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 SO<INF>2</INF> 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
SO<INF>2</INF> 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
(H<INF>2</INF>S) 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 SO<INF>2</INF> 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 SO<INF>2</INF>
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 H<INF>2</INF>S 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 SO<INF>2</INF> emission rate. The SO<INF>2</INF> 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 H<INF>2</INF>S per 100 scf would
result in an approximately five-fold underestimation of SO<INF>2</INF>
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 <ls-thn-eq>0.3 gr/100 scf of H<INF>2</INF>S, as
opposed to the previous requirement to document an H<INF>2</INF>S
content <ls-thn-eq>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 SO<INF>2</INF>
emission rate would either be required to begin daily gas sampling of
the fuel sulfur content or would have to install an SO<INF>2</INF>
CEMS.
Two other commenters suggested that the use of two sulfur content
criteria in the natural gas definition (the dual criteria of 1 grain
H<INF>2</INF>S 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 SO<INF>2</INF> emission rate of
0.0006 lb/mmBtu, thereby underestimating SO<INF>2</INF> 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 SO<INF>2</INF>
and Heat Input Methodologies
In responding to the comments received, the Agency first attempted
to quantify the SO<INF>2</INF> emissions from the combustion of gaseous
fuels under the current Acid Rain rules. A data analysis was performed,
assuming that the vast majority of SO<INF>2</INF> 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 SO<INF>2</INF> emitted by these 582 units was 14,728 tons in 1997 or
0.1% of the total SO<INF>2</INF> mass emissions in the program; and (4)
of the 14,728 tons of SO<INF>2</INF> 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 SO<INF>2</INF>
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 SO<INF>2</INF>
emissions from a coal-fired unit. For this reason, the method of
calculating the SO<INF>2</INF> 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
SO<INF>2</INF> 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 H<INF>2</INF>S per 100 scf, but the
definition of natural gas allows fuels with up to 1.0 grain of
H<INF>2</INF>S and 20 grains of total sulfur to be classified as
``natural gas.'' In view of this, it is possible that the reported
cumulative SO<INF>2</INF> 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 SO<INF>2</INF> 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:
<bullet> The use of the default SO<INF>2</INF> 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.
<bullet> 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 SO<INF>2</INF>
emission rate should be allowed, which more closely represents the
potential SO<INF>2</INF> emission rate for that fuel.
<bullet> The applicability of Appendix D should be expanded to
include any gaseous fuel (rather than limiting it to fuels with a
total sulfur content <ls-thn-eq> 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 <ls-thn-eq>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 SO<INF>2</INF> emission rate. The Agency believes that in
general, any ``natural gas'' with <ls-thn-eq>1.0 grain of
H<INF>2</INF>S/100 scf will also meet the requirement that hydrogen
sulfide must account for <gr-thn-eq>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 SO<INF>2</INF> emissions.
3. Changes to the Methodology for Calculating SO<INF>2</INF> Emissions
Under Appendix D
Today's rule adopts a two-tiered approach to the use of default
SO<INF>2</INF> 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
<ls-thn-eq>0.3 grains of hydrogen sulfide per 100 scf, the default
SO<INF>2</INF> 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 <ls-thn-eq>1.0 grain of hydrogen sulfide per 100
scf to calculate a site-specific default SO<INF>2</INF> 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
SO<INF>2</INF> 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
SO<INF>2</INF> 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 <ls-thn-eq>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
SO<INF>2</INF> 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 SO<INF>2</INF> 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
SO<INF>2</INF> 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 H<INF>2</INF>S 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 H<INF>2</INF>S. 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 SO<INF>2</INF>, NOX and CO<INF>2</INF> 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, CO<INF>2</INF> (or O<INF>2</INF>) 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 SO<INF>2</INF>, NOX, or total hydrocarbons
above 0.1 parts per million (ppm), a concentration of CO above 1 ppm,
or a concentration of CO<INF>2</INF> 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
SO<INF>2</INF>, NOX, or total hydrocarbons above 0.1 ppm, a
concentration of CO above 1 ppm, or a concentration of CO<INF>2</INF>
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 SO<INF>2</INF>, NOX,
CO<INF>2</INF>, 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 SO<INF>2</INF>, NOX, CO<INF>2</INF>, 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 SO<INF>2</INF>, 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 CO<INF>2</INF> 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 SO<INF>2</INF> concentration is measured on a
dry basis or at which moisture corrections are required to account for
CO<INF>2</INF> 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
SO<INF>2</INF>, NOX or CO<INF>2</INF> 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 SO<INF>2</INF>, CO<INF>2</INF>, or O<INF>2</INF>
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 SO<INF>2</INF> 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 SO<INF>2</INF>) and
the diluent monitor (O<INF>2</INF> or CO<INF>2</INF>). For a moisture
monitoring system consisting of one or more oxygen analyzers capable of
measuring O<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> emissions
(SO<INF>2</INF> and flow monitors).
(a) Coal-fired units. The owner or operator shall meet the general
operating requirements in Sec. 75.10 for an SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> 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 O<INF>2</INF> 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 O<INF>2</INF>
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 SO<INF>2</INF> 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 SO<INF>2</INF> mass emissions; or
* * * * *
(e) Units with SO<INF>2</INF> continuous emission monitoring
systems during the combustion of gaseous fuel. The owner or operator of
an affected unit with an SO<INF>2</INF> continuous emission monitoring
system shall, during any hour in which the unit combusts only gaseous
fuel, determine SO<INF>2</INF> 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
SO<INF>2</INF> monitoring system, determine SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> monitoring system, determine
SO<INF>2</INF> 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 SO<INF>2</INF> mass
emissions by using a certified SO<INF>2</INF> 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 SO<INF>2</INF> 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
SO<INF>2</INF> 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.,
<plus-minus>2.5 percent of the span value or <plus-minus>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 SO<INF>2</INF> 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 SO<INF>2</INF>
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 O<INF>2</INF>
or CO<INF>2</INF>), 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 CO<INF>2</INF>
emissions.
(a) CO<INF>2</INF> 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 CO<INF>2</INF> 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 ``CO<INF>2</INF> continuous emission monitoring system'' shall
apply rather than ``SO<INF>2</INF> continuous emission monitoring
system,'' the phrase ``CO<INF>2</INF> concentration'' shall apply
rather than ``SO<INF>2</INF> concentration,'' the term ``maximum
potential concentration of CO<INF>2</INF>'' shall apply rather than
``maximum potential concentration of SO<INF>2</INF>,'' and the phrase
``CO<INF>2</INF> mass emissions'' shall apply rather than
``SO<INF>2</INF> mass emissions.''
* * * * *
(c) Determination of CO<INF>2</INF> mass emissions using an O<INF>2</INF>
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 CO<INF>2</INF> concentration and mass emissions with a
flow monitoring system; a continuous O<INF>2</INF> concentration
monitor; fuel F and F<INF>c</INF> factors; and, where O<INF>2</INF>
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 ``CO<INF>2</INF> continuous emission
monitoring system'' shall apply rather than ``SO<INF>2</INF> continuous
emission monitoring system,'' the term ``maximum potential
concentration of CO<INF>2</INF>'' shall apply rather than ``maximum
potential concentration of SO<INF>2</INF>,'' and the phrase
``CO<INF>2</INF> mass emissions'' shall apply rather than
``SO<INF>2</INF> 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 SO<INF>2</INF> emissions and heat input
determinations.
* * * * *
(b) * * *
(2) * * *
(ii) * * *
(B) Install, certify, operate, and maintain an SO<INF>2</INF>
continuous emission monitoring system and flow monitoring system in the
duct from each nonaffected unit; determine SO<INF>2</INF> mass
emissions from the affected units as the difference between
SO<INF>2</INF> mass emissions measured in the common stack and
SO<INF>2</INF> 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
SO<INF>2</INF> 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 SO<INF>2</INF> mass emissions measured in the common stack
to each of the units using the common stack and on reporting the
SO<INF>2</INF> mass emissions. The Administrator may approve such
demonstrated substitute methods for apportioning and reporting
SO<INF>2</INF> 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 SO<INF>2</INF>
continuous emission monitoring system and flow monitoring system in
each stack. Determine SO<INF>2</INF> mass emissions from each affected
unit as the sum of the SO<INF>2</INF> 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 SO<INF>2</INF> mass emissions from the
units using that stack and shall calculate and report SO<INF>2</INF>
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 ``SO<INF>2</INF> mass
emissions'' or ``emissions'' and the phrase ``a diluent monitor and a
flow monitor'' shall apply rather than ``SO<INF>2</INF> 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 SO<INF>2</INF>, NOX, and CO<INF>2</INF>
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 CO<INF>2</INF>
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 SO<INF>2</INF>, as defined in section
2.1.1.1 of appendix A to this part, to report SO<INF>2</INF>
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 CO<INF>2</INF>, as defined in section 2.1.3.1 of
appendix A to this part, to report CO<INF>2</INF> 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 SO<INF>2</INF> or CO<INF>2</INF>
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
SO<INF>2</INF> 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 <plus-minus>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
<plus-minus>10% of the average reference method value or <plus-minus>15
ppm, or <plus-minus>1.5% H<INF>2</INF>O, or <plus-minus>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 SO<INF>2</INF> 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 O<INF>2</INF> or a
CO<INF>2</INF> 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 CO<INF>2</INF> 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 CO<INF>2</INF> monitoring system).
(4) For each CO<INF>2</INF> pollutant concentration monitor, each
O<INF>2</INF> monitor which is part of a CO<INF>2</INF> continuous
emission monitoring system, each diluent monitor used to monitor heat
input and each SO<INF>2</INF>-diluent continuous emission monitoring
system:
* * * * *
(5) For each continuous moisture monitoring system consisting of
wet- and dry-basis O<INF>2</INF> analyzers:
(i) A 7-day calibration error test of each O<INF>2</INF> analyzer;
(ii) A cycle time test of each O<INF>2</INF> analyzer;
(iii) A linearity test of each O<INF>2</INF> 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 SO<INF>2</INF>-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., SO<INF>2</INF>,
CO<INF>2</INF>, 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 (SO<INF>2</INF>, CO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF>
continuous emission monitoring system is not required to perform the
daily or quarterly assessments of the SO<INF>2</INF> 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, SO<INF>2</INF> 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 SO<INF>2</INF> monitoring system is failed while the unit
is combusting only gaseous fuel, the SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF>
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
SO<INF>2</INF> 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
SO<INF>2</INF> monitoring system burns only very low sulfur fuel (as
defined in Sec. 72.2 of this chapter), the SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> monitoring system
is not exempted under paragraphs (a)(6) or (a)(7) of this section from
the SO<INF>2</INF> 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 SO<INF>2</INF> monitoring system. However, no more than eight
successive calendar quarters shall elapse after a relative accuracy
test audit of an SO<INF>2</INF> 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
SO<INF>2</INF>
[[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 SO<INF>2</INF> 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 CO<INF>2</INF> concentration
data (in percent CO<INF>2</INF>, or percent O<INF>2</INF> converted to
percent CO<INF>2</INF> using the procedures in appendix F to this part)
has not been measured and recorded for an affected unit, either by a
certified CO<INF>2</INF> 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 CO<INF>2</INF> or
O<INF>2</INF> concentration data (in percent CO<INF>2</INF>, or percent
O<INF>2</INF>) used for the determination of heat input has not been
measured and recorded for an
[[Page 28601]]
affected unit, either by a certified CO<INF>2</INF> or O<INF>2</INF>
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 SO<INF>2</INF>, CO<INF>2</INF>,
NOX, or O<INF>2</INF> 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
SO<INF>2</INF> continuous emission monitoring system combusts only
gaseous fuel.
(1) Whenever a unit with an SO<INF>2</INF> 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 SO<INF>2</INF> 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
SO<INF>2</INF> mass emissions using Equation F-23 in section 7 of
appendix F to this part, substitute for missing data from a flow
monitoring system, CO<INF>2</INF> diluent monitor or O<INF>2</INF>
diluent monitor using the missing data substitution procedures in
Sec. 75.36.
(2) Whenever a unit with an SO<INF>2</INF> 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
SO<INF>2</INF> 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, CO<INF>2</INF> diluent monitor, or O<INF>2</INF> diluent
monitor using the missing data substitution procedures in Sec. 75.36.
(3) The owner or operator of a unit with an SO<INF>2</INF>
monitoring system shall not include hours when the unit combusts only
gaseous fuel in the SO<INF>2</INF> data availability calculations in
Sec. 75.32 or in the calculations of substitute SO<INF>2</INF> data
using the procedures of either Sec. 75.31 or Sec. 75.33, for hours when
SO<INF>2</INF> 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 SO<INF>2</INF> 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
SO<INF>2</INF> emissions are determined in accordance with
Sec. 75.11(e)(1) or (e)(2).
(4) During all hours in which a unit with an SO<INF>2</INF>
continuous emission monitoring system combusts only gaseous fuel and
the owner or operator uses the SO<INF>2</INF> monitoring system to
determine SO<INF>2</INF> mass emissions pursuant to Sec. 75.11(e)(3),
the owner or operator shall determine the percent monitor data
availability for SO<INF>2</INF> in accordance with Sec. 75.32 and shall
use the standard SO<INF>2</INF> 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
SO<INF>2</INF> pollutant concentration monitor, or a CO<INF>2</INF>
pollutant concentration monitor (or an O<INF>2</INF> monitor used to
determine CO<INF>2</INF> concentration in accordance with appendix F to
this part), or an O<INF>2</INF> or CO<INF>2</INF> 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) SO<INF>2</INF>, CO<INF>2</INF>, or O<INF>2</INF> concentration
data and moisture data. For each hour of missing SO<INF>2</INF> or
CO<INF>2</INF> pollutant concentration data (including CO<INF>2</INF>
data converted from O<INF>2</INF> data using the procedures in appendix
F of this part), or missing O<INF>2</INF> or CO<INF>2</INF> 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 SO<INF>2</INF>, CO<INF>2</INF> or O<INF>2</INF> 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 SO<INF>2</INF>,
CO<INF>2</INF> or O<INF>2</INF> concentration data or moisture data
exist, the owner or operator shall substitute, as applicable, for each
hour of missing data, the maximum potential SO<INF>2</INF>
concentration or the maximum potential CO<INF>2</INF> concentration or
the minimum potential O<INF>2</INF> 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 SO<INF>2</INF> pollutant concentration monitor, or a CO<INF>2</INF>
pollutant concentration monitor (or O<INF>2</INF> monitor used to
determine CO<INF>2</INF> concentration), or an O<INF>2</INF> or
CO<INF>2</INF> 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 SO<INF>2</INF> pollutant concentration
monitor, the CO<INF>2</INF> pollutant concentration monitor, the
O<INF>2</INF> or CO<INF>2</INF> 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 SO<INF>2</INF>
monitoring system shall, when SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF>,
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 SO<INF>2</INF> 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 (SO<INF>2</INF>) 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 SO<INF>2</INF> CEMS, CO<INF>2</INF> CEMS, Moisture CEMS and Diluent (CO<INF>2</INF> or O<INF>2</INF>) 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 <ls-thn-eq> 24 Average........................ HB/HA.
N > 24 For SO<INF>2</INF>, CO<INF>2</INF> and H<INF>2</INF>O**, the .................
greater of: HB/HA.
Average...................... 720 hours.*
90th percentile..............
............................ For O<INF>2</INF>, and H<INF>2</INF>OX, the lesser .................
of: HB/HA.
Average...................... 720 hours.*
10th percentile..............
90 or more, but below 95...... N <ls-thn-eq> 8 Average........................ HB/HA.
N > 8 For SO<INF>2</INF>, CO<INF>2</INF> and H<INF>2</INF>O**, the .................
greater of: HB/HA.
Average...................... 720 hours.*
95th percentile..............
............................ For O<INF>2</INF>, and H<INF>2</INF>OX, the lesser .................
of: HB/HA.
Average...................... 720 hours.*
5th percentile...............
80 or more, but below 90...... N > 0 For SO<INF>2</INF>, CO<INF>2</INF> and H<INF>2</INF>O**,........ .................
Maximum value \1\............ 720 hours.*
............................ For O<INF>2</INF>, and H<INF>2</INF>OX: .................
Minimum value\1\............. 720 hours.*
Below 80...................... N > 0 Maximum potential concentration
or % (for SO<INF>2</INF>, CO<INF>2</INF> and H<INF>2</INF>O**)
or
............................ Minimum potential concentration None.
or % (for O<INF>2</INF>, and H<INF>2</INF>OX).
----------------------------------------------------------------------------------------------------------------
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 <ls-thn-eq> 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 <ls-thn-eq> 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 SO<INF>2</INF>
concentration recorded by an SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF>
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 CO<INF>2</INF> data.
(a) On and after April 1, 2000, the owner or operator of a unit
with a CO<INF>2</INF> continuous emission monitoring system for
determining CO<INF>2</INF> mass emissions in accordance with Sec. 75.10
(or an O<INF>2</INF> monitor that is used to determine CO<INF>2</INF>
concentration in accordance with appendix F to this part) shall
substitute for missing CO<INF>2</INF> 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 CO<INF>2</INF> data
for heat input determination. Prior to April 1, 2000, the owner or
operator shall substitute for missing CO<INF>2</INF> 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
CO<INF>2</INF> continuous emission monitoring system, or (for a
previously certified CO<INF>2</INF> 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 CO<INF>2</INF> pollutant
concentration data or substitute CO<INF>2</INF> 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 CO<INF>2</INF>
concentration data or substitute CO<INF>2</INF> data for heat input
determination, as applicable, in accordance with the procedures in
Sec. 75.33(b), except that the term ``CO<INF>2</INF> concentration''
shall apply rather than ``SO<INF>2</INF> concentration'' and the term
``CO<INF>2</INF> pollutant concentration monitor'' or ``CO<INF>2</INF>
diluent monitor'' shall apply rather than ``SO<INF>2</INF> 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 (O<INF>2</INF> or CO<INF>2</INF>) 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 O<INF>2</INF> or CO<INF>2</INF> 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 CO<INF>2</INF> or O<INF>2</INF>
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 CO<INF>2</INF> or O<INF>2</INF> 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
CO<INF>2</INF> or O<INF>2</INF> 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 CO<INF>2</INF> or
O<INF>2</INF> concentration to calculate heat input, as follows.
Substitute CO<INF>2</INF> data for heat input determinations shall be
provided according to Sec. 75.35(d). Substitute O<INF>2</INF> data for
the heat input determinations shall be provided in accordance with the
procedures in Sec. 75.33(b), except that the term ``O<INF>2</INF>
concentration'' shall apply rather than the term ``SO<INF>2</INF>
concentration'' and the term ``O<INF>2</INF> diluent monitor'' shall
apply rather than the term ``SO<INF>2</INF> pollutant concentration
monitor.'' In addition, the term ``substitute the lesser of'' shall
apply rather than ``substitute the greater of;'' the terms ``minimum
hourly O<INF>2</INF> concentration'' and ``minimum potential
O<INF>2</INF> concentration, as determined under section 2.1.3.2 of
appendix A to this part'' shall apply rather than, respectively, the
terms ``maximum hourly SO<INF>2</INF> concentration'' and ``maximum
potential SO<INF>2</INF> 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
``SO<INF>2</INF> concentration;'' the term ``moisture monitoring
system'' shall apply rather than the term ``SO<INF>2</INF> 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 SO<INF>2</INF> concentration'' and ``maximum potential
SO<INF>2</INF> 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 SO<INF>2</INF> emissions, CO<INF>2</INF> 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
``SO<INF>2</INF> concentration'' and the term ``moisture monitoring
system'' shall apply rather than ``SO<INF>2</INF> pollutant
concentration monitor;'' or
(ii) If any of the following equations is used to determine
SO<INF>2</INF> emissions, CO<INF>2</INF> 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 SO<INF>2</INF>
emissions, NOX emissions, CO<INF>2</INF> 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 SO<INF>2</INF>,
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., SO<INF>2</INF> 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 SO<INF>2</INF>,
NOX, CO<INF>2</INF>, O<INF>2</INF>, 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 SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF>
concentration and volumetric flow if either one of these monitors is
still operating:
* * * * *
(xi) Method of determination of SO<INF>2</INF> 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 SO<INF>2</INF> emission record provisions during the
combustion of gaseous fuel. (1) If SO<INF>2</INF> 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
SO<INF>2</INF> 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
SO<INF>2</INF> CEMS to determine SO<INF>2</INF> 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 SO<INF>2</INF> 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) SO<INF>2</INF> 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
SO<INF>2</INF> mass emissions:
(1) For SO<INF>2</INF> 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 SO<INF>2</INF> concentration (ppm, rounded to
the nearest tenth);
(iv) Hourly average SO<INF>2</INF> 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 SO<INF>2</INF>
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
SO<INF>2</INF> 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 O<INF>2</INF>,
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 SO<INF>2</INF> 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 SO<INF>2</INF> mass emission rate (lb/hr, rounded to
the nearest tenth);
(iii) Hourly SO<INF>2</INF> 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 SO<INF>2</INF> mass emission rate from SO<INF>2</INF>
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:
NSO<INF>2</INF>: Method 6C.
Flow: Method 2 or its allowable
alternatives under appendix A to part 60 of
this chapter.
NOX: Method 7E.
CO<INF>2</INF> or O<INF>2</INF>: Method 3A.
5........................ For units with add-on SO<INF>2</INF> and/or NOX emission
controls: SO<INF>2</INF> concentration or NOX emission
rate estimate from Agency preapproved
parametric monitoring method.
6........................ Average of the hourly SO<INF>2</INF> concentrations, CO<INF>2</INF>
concentrations, O<INF>2</INF> 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 SO<INF>2</INF> concentration, CO<INF>2</INF>
concentration, O<INF>2</INF> concentration, NOX
concentration, moisture percentage, flow
rate, or NOX emission rate using initial
missing data procedures.
8........................ 90th percentile hourly SO<INF>2</INF> concentration, CO<INF>2</INF>
concentration, NOX concentration, flow rate,
moisture percentage, or NOX emission rate or
10th percentile hourly O<INF>2</INF> concentration or
moisture percentage (moisture missing data
algorithm depends on which equations are
used for emissions and heat input).
9........................ 95th percentile hourly SO<INF>2</INF> concentration, CO<INF>2</INF>
concentration, NOX concentration, flow rate,
moisture percentage, or NOX emission rate or
5th percentile hourly O<INF>2</INF> concentration or
moisture percentage (moisture missing data
algorithm depends on which equations are
used for emissions and heat input)
10....................... Maximum hourly SO<INF>2</INF> concentration, CO<INF>2</INF>
concentration, NOX concentration, flow rate,
moisture percentage, or NOX emission rate or
minimum hourly O<INF>2</INF> 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 SO<INF>2</INF>,
maximum potential concentration of CO<INF>2</INF>,
maximum potential concentration of NOX
maximum potential flow rate, maximum
potential NOX emission rate, maximum
potential moisture percentage, minimum
potential O<INF>2</INF> 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 CO<INF>2</INF> 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
CO<INF>2</INF> measurement, use 5.0 percent for boilers
and 1.0 percent for turbines; if it is
replacing an O<INF>2</INF> measurement, use 14.0
percent for boilers and 19.0 percent for
turbines).
15....................... Fuel analysis data from appendix G to this
part for CO<INF>2</INF> mass emissions. (This code is
optional through 12/31/99, and shall not be
used after 1/1/00.)
16....................... SO<INF>2</INF> 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 O<INF>2</INF> or
percent CO<INF>2</INF>, rounded to the nearest tenth);
(5) If applicable, the hourly average moisture content of the stack
gas (percent H<INF>2</INF>O, 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 O<INF>2</INF>, 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) CO<INF>2</INF> 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 CO<INF>2</INF> mass emissions, the owner or operator shall
record or calculate CO<INF>2</INF> 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 CO<INF>2</INF> CEMS
(including an O<INF>2</INF> 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 CO<INF>2</INF> 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 CO<INF>2</INF> 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 CO<INF>2</INF> 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 O<INF>2</INF>, rounded
to the nearest tenth);
(vi) Hourly average CO<INF>2</INF> mass emission rate (tons/hr,
rounded to the nearest tenth);
(vii) Percent monitor data availability for both the CO<INF>2</INF>
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 CO<INF>2</INF>
mass emission rate and hourly average CO<INF>2</INF> 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 CO<INF>2</INF> mass emission rate, as provided in
Sec. 75.53; and
(x) Indication of whether the diluent cap was used for
CO<INF>2</INF> 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
CO<INF>2</INF> mass emissions:
(i) Date;
(ii) Daily combustion-formed CO<INF>2</INF> mass emissions (tons/
day, rounded to the nearest tenth);
(iii) For coal-fired units, flag indicating whether optional
procedure to adjust combustion-formed CO<INF>2</INF> 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 CO<INF>2</INF>, daily sorbent-related
CO<INF>2</INF> 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 CO<INF>2</INF>, total daily CO<INF>2</INF> 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 O<INF>2</INF> 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 CO<INF>2</INF> diluent monitor (which is used only
for heat input determination and is not used as a CO<INF>2</INF>
pollutant concentration monitor) shall keep the following records for
the O<INF>2</INF> or CO<INF>2</INF> diluent monitor:
(1) Component-system identification code, as provided in
Sec. 75.53;
(2) Date and hour;
(3) Hourly average diluent gas (O<INF>2</INF> or CO<INF>2</INF>)
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 (O<INF>2</INF> or
CO<INF>2</INF>) 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 SO<INF>2</INF> concentration data or NOX emission
rate (in addition to other information), or shall record the
information in paragraph (b)(1) of this section for SO<INF>2</INF> 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 SO<INF>2</INF> emission controls using
the optional parametric monitoring procedures in appendix C to this
part, for each hour of missing SO<INF>2</INF> concentration or
volumetric flow data:
(i) The information required in Sec. 75.54(c) or Sec. 75.57(c) for
SO<INF>2</INF> 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 SO<INF>2</INF> add-on emission controls other
than wet or dry limestone, corresponding parameters approved by the
Administrator;
(xi) Method of determination of SO<INF>2</INF> 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 SO<INF>2</INF> concentration values,
recorded by an SO<INF>2</INF> 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 O<INF>2 </INF>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 SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF>
concentration during missing data periods under Sec. 75.34(a)(2), any
available inlet and outlet SO<INF>2</INF> concentration values recorded
by an SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF> 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 SO<INF>2</INF>
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)
[[Continued on page 28613]]
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