# Acid Rain Program; Continuous Emission Monitoring Rule Revisions

> Briefs, arguments, decisions, and more.

URL: https://www.frixlaw.com/law-library/documents/fr%3A99-8939

## Record

- **Collection:** Federal Register
- **Document type:** Rule
- **Published:** May 26, 1999
- **Citation:** 64 FR 28564

## Text

SUMMARY: Title IV of the Clean Air Act (CAA or the Act), as amended by
the Clean Air Act Amendments of 1990, authorizes the Environmental
Protection Agency (EPA or Agency) to establish the Acid Rain Program.
The Acid Rain Program and the provisions in this final rule benefit the
environment by ensuring that the sulfur dioxide (SO2),
nitrogen oxides (NOX) and carbon dioxide (CO2)
air pollution emissions to be measured and tracked pursuant to the
provisions of 40 CFR part 75 are accurately monitored and reported.
These provisions also benefit the regulated entities by providing
additional flexibility and improved cost effectiveness to the
monitoring and reporting options available to part 75 subject sources.
On January 11, 1993, the Agency promulgated final rules, including the
final continuous emission monitoring (CEM) rule, under title IV. On May
17, 1995 and November 20, 1996, the Agency revised the CEM rule to make
the implementation simpler. On May 21, 1998, the Agency proposed
additional revisions to the CEM rule, to make implementation easier and
more efficient for both EPA and the facilities affected by the rule, to
improve quality assurance requirements, and to create new alternative
monitoring options. EPA promulgated final rule revisions addressing
some of these additional proposed revisions, based on comments
received, when EPA promulgated a Finding of Significant Contribution
and Rulemaking for Certain States in the Ozone Transport Assessment
Group Region for Purposes of Reducing Regional Transport of Ozone
(NOX SIP call).
In this action, EPA is issuing final rule revisions addressing the
remaining May 21, 1998 proposed revisions to the CEM rule, with certain
changes to the proposal based on the public comments received. Some of
these revisions will be relevant for sources that become subject to
part 75 requirements in response to the NOX SIP call.

DATES: The effective date of this rule is June 25, 1999. The
incorporation by reference of certain publications listed in the
regulations is approved by the Director of the Federal Register as of
June 25, 1999.

ADDRESSES: Docket. Supporting information used in developing the
regulations is contained in Docket No. A-97-35. This docket is
available for public inspection and photocopying between 8:00 a.m. and
5:30 p.m. Monday through Friday, excluding government holidays and is
located at: EPA Air Docket (MC 6102) , Room M-1500, Waterside Mall, 401
M Street, SW, Washington, DC 20460. A reasonable fee may be charged for
photocopying.

FOR FURTHER INFORMATION CONTACT: Monika Chandra, Acid Rain Division
(6204J), U.S. Environmental Protection Agency, 401 M Street, SW,
Washington, DC 20460, (202) 564-9781.

SUPPLEMENTARY INFORMATION: The contents of the preamble are listed in
the following outline:

I. Regulated Entities
II. Background and Summary of Final Rule
III. Summary of Major Comments and Responses
A. Certification/Recertification Procedural Changes
B. Quality Assurance Requirements for Quantifying Stack Gas
Moisture Content
C. Percent Monitor Availability
D. Span and Range Requirements
E. Flow-to-Load Ratio Test Requirements
F. RATA and Bias Test Requirements
1. RATA Load Levels
2. Single Point Reference Method Sampling
G. Data Validation
1. Data Validation During Monitor Certification and
Recertification
2. Data Validation for RATAs and Linearity Checks
H. Appendix D--Sulfur Dioxide Emissions from the Combustion of
Gaseous Fuels
1. Summary of EPA Analysis of Appendix D Gaseous Fuel
SO2 and Heat Input Methodologies
2. Changes to the Definitions of ``Pipeline Natural Gas'' and
``Natural Gas''
3. Changes to the Methodology for Calculating SO2
Emissions Under Appendix D
4. Changes to the Applicability of Appendix D
5. Changes to the Method of Determining the Sulfur Content
Sampling Frequency for Gaseous Fuels
6. Changes to the Method of Determining the GCV Sampling
Frequency for Gaseous Fuels
I. Electronic Transfer of Quarterly Reports
J. Bias, Relative Accuracy and Availability Determinations
K. Appendix I--Proposed Optional Stack Flow Monitoring
Methodology
L. Subpart H--Clarifications to NOX Mass Monitoring
Requirements
IV. Administrative Requirements
A. Public Docket
B. Executive Order 12866
C. Unfunded Mandates Reform Act
D. Executive Order 12875
E. Executive Order 13084
F. Paperwork Reduction Act
G. Regulatory Flexibility
H. Submission to Congress and the General Accounting Office
I. Executive Order 13045
J. National Technology Transfer and Advancement Act

I. Regulated Entities

Entities regulated by this action are fossil fuel-fired boilers and
turbines that serve generators producing electricity, generate steam,
or cogenerate electricity and steam. While part 75 primarily regulates
the electric utility industry, the recent promulgation of 40 CFR part
96 and certain revisions to part 75 (see 63 FR 57356, October 27, 1998)
means that part 75 could potentially affect other industries. The
recent adoption of part 96, together with revisions to part 75, include
nitrogen oxides (NOX) mass provisions for the purpose of
serving as a model which could be adopted by a state, tribal, or
federal NOX mass reduction program covering the electric
utility and other industries. Regulated categories and entities
include:

------------------------------------------------------------------------
Examples of regulated
Category entities
------------------------------------------------------------------------
Industry.................................. Electric service providers,
boilers, turbines and other
process sources where
emissions exhaust through a
stack.
------------------------------------------------------------------------

This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
action. This table lists the types of entities which EPA is now aware
could potentially be regulated by this action. Other types of entities
not listed in the table could also be regulated. To determine whether
your facility, company, business, organization, etc., is regulated by
this action, you should carefully examine the applicability provisions
in Secs. 72.6, 72.7, 72.8, and part 96 of title 40 of the Code of
Federal Regulations. If you have questions regarding the applicability
of this action to a particular entity, consult the person listed in the
preceding FOR FURTHER INFORMATION CONTACT section of this preamble.

II. Background and Summary of Final Rule

Title IV of the Act requires EPA to establish an Acid Rain Program
to reduce the adverse effects of acidic deposition. On January 11,
1993, the

[[Page 28565]]

Agency promulgated final rules implementing the program, including the
CEM rule (58 FR 3590). Notices of direct final rulemaking and of
interim final rulemaking further amending the regulations were
published on May 17, 1995 (60 FR 26510 and 60 FR 26560). Subsequently,
on November 20, 1996, a final rule was published in response to public
comments received on the direct final and interim rules (61 FR 59142).
On May 21, 1998, the Agency published proposed revisions to the part 75
CEM regulations (62 FR 28032). As noted above, EPA recently promulgated
final revisions to part 75 addressing some of the May 21, 1998,
proposed revisions in conjunction with the promulgation of a Model
NOX Trading Rule in part 96 and the NOX SIP call
(see 63 FR 57356).
Today's action adopts final part 75 revisions to address the
remaining May 21, 1998, proposed revisions and to make minor technical
corrections to the part 75 provisions promulgated in conjunction with
part 96 and the NOX SIP Call. The final revisions involve
the following matters: (1) revised definitions of gas-fired, oil-fired,
and peaking unit to allow for changes in unit fuel usage and/or
operation; (2) a minor wording correction to the applicability
provisions in part 72; (3) new quality assurance/quality control (QA/
QC) requirements for quantifying stack gas moisture content; (4)
clarifying changes to the certification and recertification process;
(5) substitute data requirements for carbon dioxide (CO2),
heat input and moisture; (6) clarifying revisions to the petition
provisions for alternatives to part 75 requirements; (7) clarifying
changes to span and range requirements; (8) clarifying revisions to
general QA/QC requirements; (9) calibration error test requirements;
(10) linearity test requirements; (11) a new flow-to-load QA test for
flow monitors; (12) reductions in and/or clarifications to the relative
accuracy test audit (RATA) and bias test requirements; (13) clarifying
revisions to the procedures for CEM data validation; (14) clarifying
revisions to the sulfur dioxide (SO2) emissions data
protocol for gas-fired and oil-fired units (Appendix D); (15)
determination of CO2 emissions under Appendix G; (16)
recordkeeping and reporting changes to reflect the proposed revisions;
(17) a revised traceability protocol for calibration gases (Appendix
H); and (18) NOX mass emission recordkeeping and reporting
provisions, and minor revisions to NOX mass monitoring
requirements.
Many of these changes are minor technical revisions based on
comments received from facilities following the initial implementation
of part 75. Based on experience gained in the early years of the
program, facilities have developed a number of suggestions that will
simplify and streamline the monitoring process without sacrificing data
quality. The Agency has also amended quality assurance requirements
based on gaps identified by EPA during evaluation of the initial
implementation of part 75. Finally, several minor technical changes
have been made in order to maintain uniformity within the rule itself
and to clarify various provisions.

III. Summary of Major Comments and Responses

A. Certification/Recertification Procedural Changes

Background: EPA proposed to revise the recertification application
review period in Sec. 75.20(b)(5) from 60 days to 120 days, which is
the same review period as for the initial certification application.
The Agency believes that this will reduce confusion, simplify
certification/recertification application tracking, and will result in
the more efficient allocation of resources by local, state, and federal
agencies. Therefore, EPA has adopted this change in the final rule with
certain modifications in response to issues raised by commenters.
Discussion: Two states responded positively to the proposed change.
One state commented that the increased review time ``will allow more
effective use of staff resources and provide ample time for a thorough
review of the data submitted in the application'' (see Docket A-97-35,
Item IV-D-6). Another state commenter remarked that extending the
review period ``adds uniformity and consistency to the certification
and recertification process. This change is positive, and it allows the
state agencies the time to resolve minor deficiencies which may
otherwise serve as grounds to recommend disapproval. Based on
experience, the 120 day period is absolutely essential for the review
of certification/recertification applications'' (see Docket A-97-35,
Item IV-D-9).
Several commenters suggested that if EPA disapproved a
recertification application after the 120 day period, data recorded
during the entire 120 day period would become invalid and the use of
substitute data would be required (see Docket A-97-35, Items IV-D-17,
IV-D-20 and IV-D-24). However, as EPA stated in the preamble to the
proposal, ``less than 2 percent of all monitoring system applications
submitted between 1992 and September 1997 were disapproved'' (63 FR
28045, citing Docket A-97-35, Item II-A-4). As experience with the
program increases, the number of disapprovals is expected to decrease
even further. In addition, EPA's position is that the owners or
operators of affected facilities are responsible for initiating,
conducting, evaluating and certifying the results of the required
testing prior to submission to the appropriate regulatory Agencies. The
Agencies' role is to ``certify'' or verify the results. Thus, there is
no reason to expect that the additional time provided to meet the
administrative needs of the program will result in any significant
compliance risk to the regulated sources, except in instances where
insufficient care is taken to ensure proper conduct of the testing.
Two commenters stated that the owner or operator would be in
violation of the requirements of proposed Sec. 75.33(d) and
Sec. 75.10(a) if a recertification application were disapproved after
120 days (see Docket A-97-35, Items IV-D17 and IV-D-23) because the
percent monitor availability would be below 80%. These proposed
penalties have been withdrawn from the final rule in response to
comments received. Today's final rule does not treat a percent monitor
data availability of less than 80% as a violation. Instead, the final
rule provides that if percent monitor data availability is less than
80%, then the appropriate maximum value (e.g., maximum potential
concentration) or, in some cases, the appropriate minimum potential
value will be used to provide substitute data (see Section C of this
preamble for a further discussion of these provisions).
Several commenters suggested that since the review of the initial
certification applications for the Acid Rain Phase I and Phase II units
has been completed, the burden on the states and EPA has been removed .
Therefore, it should not take EPA 120 days to review recertification
applications (see Docket A-97-35, Items IV-D-14, IV-D-20, and IV-D-24).
This argument would be more compelling if the Acid Rain Program were
the only program that the various regulatory agencies are required to
implement. However, EPA and the States are currently responsible for
implementing several other programs that require comprehensive
administrative review of various types of applications and petitions
(e.g., Compliance Assurance Monitoring (CAM), the OTC NOX
Budget Program, the PSD program and Title V permitting). EPA also
anticipates that the NOX SIP call will further increase the
number of certification and recertification applications and

[[Page 28566]]

petitions that need to be reviewed by the regulatory agencies.
Many recertifications require the same tests as for initial
certification. Therefore, recertification applications often take as
much effort to review as certification applications. It is also
sometimes difficult to distinguish a recertification application
package from an initial certification application package, which can
complicate tracking the two types of applications if they have
different review periods. The recertification process usually requires
that a state or local program perform the initial review and forward
the results to the EPA regional office which will then make a
recommendation to EPA headquarters on whether to approve or disapprove
the application. This requires a significant amount of time and does
not allow much time to coordinate with the source to get additional
information, when needed. There is more likelihood of a disapproval
being issued under a short time frame. Finally, EPA notes that it does
not have control over the number of recertification applications that
are submitted. Individual utility choices, changes in rules, market
conditions, and technology all influence the number of
recertifications. Therefore, EPA has concluded that extending the
application review period from 60 to 120 days is both necessary and
appropriate.

B. Quality Assurance Requirements for Quantifying Stack Gas Moisture
Content

Background: Section 75.11(b) of the January 11, 1993 Acid Rain rule
requires the owner or operator to continuously (or on an hourly basis)
account for the moisture content of the stack gas when SO2
concentration is measured on a dry basis. The moisture content is
needed to correct the measured hourly stack gas volumetric flow rates
to a dry basis when calculating SO2 mass emission rates in
lb/hr. Section 75.13(a) of the rule, as amended on May 17, 1995,
contains provisions for CO2 monitoring paralleling the
provisions of Sec. 75.11(b); that is, when CO2 concentration
is measured on a dry basis, a correction for stack gas moisture content
is needed to accurately determine the CO2 mass emissions.
The stack gas moisture content is also needed when a dry-basis
O2 monitor is used to account for CO2 emissions
and, in some instances, when accounting for unit heat input or when
determining NOX emission rate in lb/mmBtu.
As presently codified, part 75 does not specify any quality
assurance requirements for moisture measurement devices. Approximately
5 to 10 percent of the continuous emission monitors in the Acid Rain
Program require moisture corrections to accurately measure
SO2, CO2, or NOX emissions or heat
input (see Docket A-97-35, Item II-I-6 ). The accuracy of the stack gas
moisture measurements directly affects the accuracy of the reported
SO2 mass emission rates, CO2 mass emission rates,
NOX emission rates and heat input values. An error of 1.0
percent H2O in measured moisture content causes a 1.0
percent error in the reported emission rate or heat input value.
Failure to quality assure the moisture data can therefore result in
significant under-reporting of SO2, CO2, and
NOX emissions and heat input.
In the May 21, 1998 proposed rule, EPA set forth quality assurance
procedures that would apply to moisture monitoring systems because the
Agency believes that when moisture corrections must be applied,
continuous, quality assured, direct measurement of the stack gas
moisture content or continuous measurement of surrogate parameters for
moisture, such as wet-and dry-basis oxygen concentrations, is the best
way to ensure the accuracy of the reported emission data. The proposed
rule specified that a moisture monitoring system could consist of
either: (1) a continuous moisture sensor; (2) an oxygen (O2)
analyzer (or analyzers) capable of measuring O2 on both a
wet basis and on a dry basis; or (3) a system consisting of a
temperature sensor and a certified data acquisition and handling system
(DAHS) component capable of determining moisture from a lookup table,
i.e., a psychometric chart (this third option would apply only to
saturated gas streams following wet scrubbers).
The proposed rule included requirements for the initial
certification of moisture monitoring systems. For continuous moisture
sensors, a 7-day calibration error test and a relative accuracy test
audit (RATA) would be required. For moisture monitoring systems
consisting of one or more wet-and dry-basis oxygen analyzers, the
proposed requirements included a 7-day calibration error test, a
linearity test and a cycle time test of each O2 analyzer,
and a RATA of the moisture measurement system. For the lookup table
option (saturated streams, only), the certification requirement would
consist of a DAHS verification. The proposed rule specified that owners
or operators would have to complete all moisture monitoring system
certification tests no later than January 1, 2000.
The proposed rule contained performance specifications for moisture
monitoring systems. These specifications would apply to continuous
moisture sensors and to wet-and dry-basis oxygen analyzers. For
moisture monitoring systems consisting of wet-and dry-basis
O2 analyzers, the proposed span values and performance
specifications for calibration error, linearity, and cycle time would
be the same as the current specifications for O2 monitors.
For moisture sensors, a calibration error specification of 3.0% of span
was proposed. The proposed relative accuracy (RA) specification for all
moisture monitoring systems would be 10.0 percent. An alternative RA
specification was also proposed, i.e., the RA test results would be
considered acceptable if the mean difference of the reference method
measurements and the moisture monitoring system measurements is within
1.0 percent H2O.
On-going QA requirements for moisture monitoring systems were also
proposed. Appendix B would be revised to require daily calibrations of
moisture monitoring systems, quarterly linearity checks of wet-and dry-
basis oxygen analyzer(s), and semiannual RATAs of moisture monitoring
systems. Any moisture monitoring system achieving a relative accuracy
of 7.5 percent or a mean difference between the CEMS and
reference method values within 0.7 percent H2O,
would qualify for an annual, rather than semiannual RATA frequency.
Missing data procedures for moisture were included in the proposed
rule in a new section, Sec. 75.37. Provided that the moisture data
availability is high (90.0 percent), the average of the
``hour before'' and ``hour after'' moisture values would be used for
each hour of the missing data period. When the percent data
availability drops below 90.0 percent, 0.0 percent moisture would be
substituted for each hour of the missing data period.
Finally, the proposed rule specified that records must be kept for
the moisture monitoring systems, including hourly average moisture
readings, percent data availability, and records of all calibration
error tests, linearity tests and relative accuracy test audits.
Today's final rule provides a number of options by which owners or
operators of affected sources may account for the stack gas moisture
content on an hourly basis. The rule also includes quality assurance
provisions for moisture monitoring systems. Today's rule differs from
the proposed rule as follows: (1) the alternate specification in terms
of the mean difference has been increased

[[Page 28567]]

from 1.0 to 1.5% H2O, but the
principal relative accuracy specification for moisture monitoring
systems has been promulgated as proposed, at 10.0 percent; (2) the
daily calibration requirement for continuous moisture sensors has been
withdrawn; (3) the use of the lookup table option has been expanded to
include any demonstrably saturated gas stream, rather than limiting it
to gas streams following wet scrubbers; (4) a site-specific coefficient
or constant (``K'' factor), determined at the time of the RATA, may be
used to calibrate the moisture monitoring system with respect to EPA
Reference Method 4; and (5) in lieu of continuously monitoring the
stack gas moisture content, a conservative, fuel-specific default
moisture percentage may be reported for each unit operating hour (for
coal and wood, only).
Discussion: Two state agencies agreed with EPA that there is a need
for quality assurance of moisture monitoring systems (see Docket A-97-
35, Items IV-D-06 and IV-D-09). A third state agency disagreed with the
proposed QA/QC for the moisture monitors, contending that the proposed
amendments provide no added benefit in terms of data quality (see
Docket A-97-35, Item IV-D-11). That same state agency objected to
quality assuring a ``sub-channel'' parameter such as moisture, claiming
that it is inconsistent with the way EPA quality assures other combined
monitoring systems (such as a NOX-diluent system). The
commenter expressed confidence that existing daily, quarterly,
semiannual and annual QA/QC on the gas and flow rate monitors is
sufficient to ensure data quality, and that if the CEMS moisture value
is significantly in error, RATA limits would probably not be met. EPA
notes, however, that the commenter provided no data to demonstrate that
this is true. The Agency also does not agree with the commenter's
characterization of moisture as a ``sub-channel'' parameter. The
attempt to draw an analogy between moisture monitoring and the
NOX-diluent monitoring system is inappropriate. Under part
75, the moisture measurement system is a separate entity and should be
quality-assured as such. The moisture monitor is not a component of any
``combined'' monitoring system. The only true combined monitoring
systems under part 75 are the NOX-diluent and
SO2-diluent monitoring systems, for which the relative
accuracy is determined on a combined basis, in lb/mmBtu (i.e., the
individual relative accuracies of the pollutant and diluent component
monitors are not determined).
Several commenters indicated that they do not believe that a
moisture monitoring system can meet the proposed relative accuracy (RA)
specifications of 10.0% for a semiannual RATA frequency or 7.5% for an
annual RATA frequency. One commenter expressed the opinion that the RA
for a moisture monitoring system should be 15.0% (see Docket A-97-35,
Item IV-G-04). Another commenter suggested that the principal RA
specification should be 10% 15% for a semiannual RATA
frequency and RA 10% for an annual RATA frequency, and that
the alternate RA specification, in terms of the mean difference, should
be 2.0% H2O for a semiannual frequency and
1.5% for an annual RATA frequency (see Docket A-97-35,
Item IV-D-23). Another commenter noted that even slight drift in
measurements can result in significant errors in the moisture
measurements (see Docket A-97-35, Item IV-D-20). One commenter
requested that EPA consider the following alternatives to the proposed
QA/QC requirements for moisture monitors: (1) eliminate the moisture RA
requirement; (2) for wet and dry oxygen analyzers, allow relative
accuracy testing of the oxygen analyzer(s) rather than requiring a RATA
of the moisture system; (3) allow the use of a default value for
moisture, in lieu of monitoring moisture continuously; or (4) subtract
the absolute value of the average moisture values generated by the
moisture monitoring system from the average reference method value at
the time of a RATA and use the difference to correct all subsequent
moisture data until the next RATA (see Docket A-97-35, Item IV-D-02).
Only one set of data was submitted by the commenters for a moisture
monitoring system RATA. The data set indicated that the moisture
monitoring system, which consisted of wet and dry-basis oxygen
analyzers, could achieve an RA of 16.5% (see Docket A-97-35, Item, IV-
D-02). Note, however, that when the moisture monitoring system data and
the reference method data were compared, the moisture monitoring system
consistently indicated a moisture value that was approximately 3%
H2O higher than the reference method, with a confidence
coefficient of 0.507. The low confidence coefficient indicates that the
moisture monitoring system readings were consistently biased high with
respect to the reference method. Therefore, it appears that a suitable
coefficient or constant (``K'' factor) could be applied to the moisture
system readings, to make the moisture monitoring system readings agree
with the reference method. In this case, subtracting 3% moisture from
the average moisture monitoring system values for each run caused the
relative accuracy to drop from 16.5% to 2.4%, which is well below the
proposed 10.0% semiannual and 7.5% annual RA specifications. For the
alternate RA specification, after applying the 3% moisture correction,
the mean difference was essentially zero, which is also well below the
value of 1.0% moisture proposed for a semiannual RATA frequency and the
value of 0.7% moisture proposed for an annual RATA frequency. This
``K'' factor approach, which was suggested by one of the commenters,
has a precedent in the Acid Rain Program. Nearly all flow monitors must
be calibrated to match the EPA reference method (i.e., Method 2), by
using either a constant or a polynomial equation with multiple
coefficients. Section 6.5.7 of Appendix A of today's rule allows such
``K'' factors to be developed for moisture monitoring systems. The
``K'' value, which would be established at the time of the semiannual
or annual RATA, would be programmed into the DAHS and applied to the
subsequent moisture data. Sections 75.56 (a)(5)(ix) and 75.59
(a)(5)(vii) of today's rule require the owner or operator to keep
records on-site, indicating the current value of the coefficient or
``K'' factor and the date on which it began to be used. The rule
further requires a RATA of the moisture monitoring system whenever the
coefficient or ``K'' factor is changed.
Relative accuracy specifications of 10.0% (for semiannual RATA
frequency) and 7.5% (for annual RATA frequency) for moisture monitoring
systems have been promulgated in today's rule, as proposed. The
alternate RA specifications of 1.0% H2O (for
semiannual RATA frequency) and
0.7% H2O (for annual RATA frequency) have been
increased, respectively, to
1.5% H2O and 1.0% H2O.
In view of EPA's decision to allow the use of site-specific ``K''
factors for moisture monitoring systems, the Agency believes that
affected utilities will be able to meet these RA specifications.
The proposed rule set forth a missing data procedure for moisture
monitoring systems. Two commenters expressed concern regarding the
establishment of such a ``conservative'' missing data procedure (see
Docket A-97-35, Items IV-D-11 and IV-D-20). One of these commenters
further stated that there are insufficient data to know what
availability can reasonably be expected from moisture monitoring
systems,

[[Page 28568]]

especially in view of the proposed moisture QA/QC specifications. After
careful consideration, the Agency agrees with the commenter and, in
response, the final rule adopts the missing data procedures in
Sec. 75.37 that are less conservative than the procedures in the
proposed rule and that more closely resemble the standard missing data
procedures for SO2, NOX, and flow, as recommended
by the commenters. The moisture missing data algorithm is modeled after
the standard SO2 missing data algorithm in Sec. 75.33(b).
This is consistent with the provisions in Secs. 75.35 and 75.36 of
today's rule, which adopt this algorithm for CO2 and heat
input missing data. However, in finalizing the moisture missing data
provisions, it became evident that a single mathematical algorithm is
not adequate to cover all of the part 75 emission rate and heat input
equations that require moisture corrections. In most of the equations,
the lower moisture values are more conservative, and an ``inverted''
SO2 missing data algorithm is appropriate (for further
discussion of the ``inverted'' algorithm, see section C of this
preamble, below). However, there are certain emission rate equations
for which the opposite is true (i.e., the higher moisture values are
more conservative and the regular SO2 missing data algorithm
is appropriate). The specific equations for which the regular
SO2 algorithm applies are Equations F-3, F-4 and F-8 in
Method 19 in Appendix A of 40 CFR 60. Provided that all of the
moisture-corrected emission and heat input equations used by an
affected facility employ the same moisture missing data algorithm
(regular or inverted), it is a simple matter to substitute for missing
moisture data. However, when two or more equations require different
moisture algorithms, an alternative way of addressing missing moisture
data is needed. EPA believes that this situation will rarely be
encountered (at present, the Agency's records indicate that there are
only two such affected units in the Acid Rain Program). Therefore,
Sec. 75.37(d) of today's rule requires the owner or operator of such
units to petition the Administrator under Sec. 75.66(l), for an
alternative moisture missing data procedure.
Finally, several commenters requested that EPA allow the use of a
default moisture value in lieu of the required moisture monitoring (see
Docket A-97-35, Items IV-D-11, IV-D-02 and IV-D-23). The Agency has
performed a moisture data analysis for various fuels (see Docket A-97-
35, Item IV-A-2) and, based on the results, has provided fuel-specific
default values for moisture in today's rule (for coal and wood, only),
which may be reported for each unit operating hour, as an alternative
to operating and maintaining a continuous moisture monitoring system.
The default values are found in Secs. 75.11(b)(1) and 75.12(b) of
today's rule. Note that two sets of default values appear in the rule
to address the variability in format among the equations used for
determining pollutant emissions and heat input (as discussed in the
previous paragraph). The lower default values in Sec. 75.11(b)(1) apply
to Equations F-2, F-14b, F-16, F-17 and F-18 in Appendix F of part 75
and to Equations 19-5 and 19-9 in EPA Method 19 in Appendix A of 40 CFR
60. The higher default values in Sec. 75.12(b) apply when Equation 19-
3, 19-4 or 19-8 in EPA Method 19 in Appendix A of 40 CFR 60 is used to
determine the NOX emission rate. The default values were
determined as follows. The moisture percentage values (which included
both ultimate moisture and free moisture) for each fuel type were taken
from the appropriate tables in Docket Item IV-A-2, cited above. The
moisture values were then ranked from the lowest percentage value to
the highest percentage value, and the 10th percentile value was
selected for the ``low'' default value and the 90th percentile value
was selected for the ``high'' default value. Each default moisture
percentage was rounded to the nearest whole number.

C. Percent Monitor Availability

Background: EPA proposed that if the annual monitor data
availability dropped below 80% for SO2, NOX, flow
rate or CO2, this would violate the primary measurement
requirement of Sec. 75.10(a). In response to comments, today's final
rule does not treat a percent monitor data availability of less than
80% as a violation. Instead, the final rule provides that if percent
monitor data availability is less than 80%, then the appropriate
maximum value (i.e., maximum potential concentration (MPC) for
SO2 and CO2, maximum potential emission rate
(MER) for NOX and maximum potential flow rate for flow) will
have to be used as substitute data for any hour for which valid data is
not available. For O2, the minimum potential concentration
will be used to provide substitute data. For moisture, consistent with
the discussion in section B of this preamble, the minimum potential
moisture percentage will be used in most instances to provide
substitute data; however, for certain emission rate equations, the
maximum potential moisture percentage must be used.
Discussion: EPA received one comment that supported making a
percent monitor availability of less than 80% a violation (see Docket
A-97-35, Item IV-D-11) and another commenter favored the provision that
if percent monitor availability is below 80% due to ``unforseen events
beyond our control,'' this would be taken into consideration (see
Docket A-97-35, Item IV-G-9). EPA also received comments objecting to
making a percent monitor data availability of less than 80% a violation
and suggesting that EPA should modify the standard missing data
algorithms for SO2, NOX and flow rate to require
the use of a maximum substitute data value when monitor availability
drops below 80 percent (see Docket A-97-35, Items IV-D-17, IV-D-19, IV-
D-23, IV-D-24). In response to the comments, the final rule does not
make percent monitor availability of less than 80% a violation and
instead provides that if percent monitor data availability at a source
is less than 80%, then the owner or operator of the source will have to
substitute the appropriate maximum value (i.e., MPC for SO2
and CO2, MER for NOX emission rate and maximum
potential flow rate for flow) as suggested by the commenters. Note that
for O2 and, in most cases, for moisture, minimum potential
values will be substituted rather than maximum values, since the lower
values of these parameters are more conservative. However, if Equation
19-3, 19-4 or 19-8 in EPA Method 19 in Appendix A of 40 CFR 60 is used
to determine NOX emission rate, higher moisture values are
more conservative and the maximum potential moisture percentage will be
used to provide substitute data.
The missing data approach set forth in today's rule to address low
monitor data availability retains the basic design of the part 75
program and appropriately addresses the need for accountability from
sources that are inadequately maintaining their monitoring systems. The
Agency maintains that this provides a strong incentive to achieve at
least 80% monitor availability. Unlike the proposed approach of
considering sources to be in violation, the substitute data approach
adopted today creates this incentive while rendering unnecessary the
task of determining and evaluating the reason(s) for low monitor data
availability.

D. Span and Range Requirements

Background: The span of a CEMS provides an estimate of the highest
expected value for the parameter being

[[Page 28569]]

measured by the CEMS. For instance, the span value of an SO2
monitor is an approximation of the highest SO2 concentration
likely to be recorded by the CEMS during operation of the affected
unit. The range of a CEMS is the full-scale setting of the instrument.
Under part 75, the range of a monitor must be equal to or greater than
the span value. Section 2.1 of Appendix A further specifies that the
range must be chosen such that the majority of the readings during
normal operation fall between 25.0 and 75.0 percent of full-scale. The
span value is important because the reference gas concentrations and
signals used for daily calibration of the CEMS are expressed as
percentages of the span value. The allowable daily calibration error
for a CEMS is also expressed as a percentage of span.
Sections 2.1.1 through 2.1.4 of Appendix A of the January 11, 1993
rule specified procedures for determining the span values for
SO2, NOX, diluent gas (O2 or
CO2), and volumetric flow rate. For SO2, the
``maximum potential concentration'' (MPC) was first calculated based on
fuel sampling. The MPC values for NOX were specified in the
rule and were based on the type of fuel being combusted. The
SO2 and NOX span values were then determined by
multiplying the MPC by 1.25. For CO2 and O2, a
span value of 20.0 percent CO2 or O2 was required
for all diluent monitors. For flow rate, the ``maximum potential
velocity'' (MPV) was first determined. Then, the span value was
obtained by multiplying the MPV by 1.25 and rounding off the result.
In the January 11, 1993 rule, the SO2 or NOX
monitor range derived from the MPC was referred to as the ``high-
scale.'' The rule further specified that whenever the majority of the
readings during normal operation were expected to be less than 25.0
percent of the high full-scale range value (e.g., if a scrubber is used
to reduce SO2 emissions), a second, ``low-scale'' span and
range would be required. The low scale span value of the CEMS would be
defined as 1.25 times the ``maximum expected concentration'' (MEC).
In the first two years of Acid Rain Program implementation, it
became clear that the span and range provisions of part 75 lacked
sufficient flexibility and clarity. The May 17, 1995 rule revisions
attempted to address these deficiencies. Two alternative methods of
determining the MPC or MEC were added, i.e., from historical CEMS data
or from emission test results. For NOX, a comprehensive list
of MPC values was promulgated (Tables 2-1 and 2-2 in Appendix A),
taking into consideration the unit type in addition to the fuel type.
Flexibility was also added to the dual-range requirements for
NOX monitors. For flow rate, a more detailed procedure for
determining the span value was added.
The May 17, 1995 rule also revised the procedures for adjusting the
span and range of SO2, NOX, and flow monitors.
The original rule had specified that span and range adjustments were
required whenever the MPC, the MEC, or the MPV changed significantly
(although a ``significant'' change was undefined). When a significant
change in the MPC, MEC, or MPV occurred, a new range setting was to be
established and a new span value defined, equal to 80.0 percent of the
adjusted range value. The May 17, 1995 rule changed this procedure,
requiring the new span value to be determined first, followed by the
new range. The May 17, 1995 rule also added procedures for addressing
full-scale exceedances, specifying that the full-scale value is to be
reported for an exceedance of one hour and that a range adjustment is
required for an exceedance greater than one hour.
After promulgation of the May 17, 1995 rule, EPA continued to
receive questions and comments about the span and range sections of
part 75. Apparently, the span and range sections of the rule were still
not sufficiently clear, flexible, or detailed and were in need of
further revision. Therefore, on May 21, 1998, further revisions to the
span and range provisions were proposed.
The proposed rule provided an alternative procedure for determining
the MPC of SO2 or NOX, requiring the MPC to be
based upon a minimum of 720 quality assured monitor operating hours,
rather than 30 unit operating days. A specific requirement to calculate
the maximum potential NOX emission rate (MER) was also
proposed. The owner or operator could use the diluent cap value of 5.0
percent CO2 or 14.0 percent O2 for boilers (or
1.0 percent CO2 or 19.0 percent O2 for turbines)
in the NOX MER calculation.
The proposed rule provided a definition of the MPC for
CO2. The MPC would be 14.0 percent CO2 for
boilers and 6.0 percent CO2 for combustion turbines.
Alternatively, the MPC for CO2 could be based on a minimum
of 720 hours of representative quality assured historical CEM data. A
standardized procedure for calculating the maximum potential flow rate
(MPF) was proposed and a clear distinction between the ``calibration
span value'' of a flow monitor (expressed in the units of measure used
for the daily calibrations) and the ``flow rate span value'' (expressed
in the units used for electronic data reporting) was provided.
The proposed rule set forth changes to the procedures for
determining the maximum expected concentration (MEC) of SO2
and NOX, and to the criteria for determining whether dual
span and range requirements apply. A separate MEC determination would
be required for each type of fuel combusted, except for fuels that are
only used for unit startup or for flame stabilization. To determine
whether a second, low-scale span is required in addition to the high-
scale span based on the MPC, each of the maximum expected concentration
(MEC) values would be compared against the MPC. If any of the MEC
values was 2, NOX or flow
rate span value could be set anywhere between 1.00 and 1.25 times the
applicable maximum value (i.e., the MPC, MEC or MPF). For
CO2 and O2 monitors, the owner or operator would
be given maximum flexibility in selecting an appropriate span value.
For CO2 monitors installed on boilers, any representative
span value between 14.0 percent and 20.0 percent CO2 would
be acceptable. For combustion turbines, any representative
CO2 span value between 6.0 and 14.0 percent CO2
could be used. For O2 monitors, a span value between 15.0
percent and 25.0 percent O2 could be selected and an
alternative O2 span value of less than 15.0 percent could be
used, if supported by an acceptable technical justification.
The proposed rule expanded and clarified the guideline in section
2.1 of Appendix A for selecting an appropriate full-scale range. The
full-scale range would be selected so that the readings during typical
unit operation fall between 20.0 and 80.0 percent of full-scale, which
represents a slight increase in flexibility from the 25 to 75 percent
of full-scale guideline in the current rule. The proposal also cited
three specific cases in which the guideline in section 2.1 is
inapplicable: (1) during the combustion of very low sulfur fuels
(0.05% sulfur by weight); (2) for SO2 or
NOX readings on the high range for an affected unit with
SO2 or NOX emission controls and two span values;
and (3) when SO2 or NOX readings are less than
20.0 percent of the low measurement range for a dual-span unit with
SO2 or NOX emission controls, provided that the
low readings occur during periods of high control device efficiency.

[[Page 28570]]

The proposed rule specified that the following monitoring
configurations could be used to meet dual span and range requirements:
(1) a single analyzer with two ranges, or (2) two separate analyzers
connected to a common probe and sample interface. The high and low
ranges could be designated in the monitoring plan as two separate,
primary monitoring systems, or as separate components of a single,
primary monitoring system, or the ``normal'' range could be designated
as a primary monitoring system, and the other range as a non-redundant
backup monitoring system.
The proposed rule would allow the owner or operator to use a
``default high-range value'' in lieu of operating, maintaining, and
quality assuring a high-scale monitor range. The default high-range
value would be 200.0 percent of the MPC. This value would be reported
whenever the SO2 or NOX concentration exceeded
the full-scale of the low-range analyzer.
Finally, the proposed rule provided detailed guidelines and
procedures for adjusting the span and range of the CEMS. First, if the
maximum value upon which the high span value is based (i.e., the MPC or
MPF) was exceeded during a calendar quarter, but the span was not
exceeded, the span or range would not have to be adjusted. However, if
any quality assured hourly concentration or flow rate exceeded the MPC
or MPF by 5.0 percent during the quarter, a new MPC or MPF
would have to be defined. Second, if any quality assured reading on the
high measurement range exceeded the span value by 10.0
percent during the quarter but did not exceed the range, a new MPC or
MPF (as applicable) would have to be defined, and the span value (and
range, if necessary) would also have to be changed. Third, for full-
scale exceedances of a high monitor range, corrective action would be
required to adjust the span and range. A value of 200.0 percent of the
current full-scale range would be reported to EPA for each hour of each
full-scale exceedance.
Today's rule finalizes the proposed revisions to the span and range
sections of Appendix A. Most of the provisions have been finalized as
proposed, with only minor changes and clarifications. However, there
are three notable exceptions: (1) the proposed requirement for
mandatory quarterly evaluations of the MPC, MEC and MPF values and the
associated prescriptive criteria for adjusting the spans and ranges
have been withdrawn; (2) the proposed change in methodology for
determining dual span and range requirements (i.e., comparing the MEC
value(s) to the MPC) has been withdrawn; and (3) an additional
monitoring configuration option has been provided for units with dual
span requirements. For units with a dual-range SO2 or
NOX analyzer, the final rule allows the low and high ranges
to be represented as a single component of a primary SO2 or
NOX monitoring system.
Discussion: EPA received supportive comments from a number of
utilities, regarding several of the proposed span and range revisions
(see Docket A-97-35, Items IV-D-20, IV-D-23, IV-D-24, IV-D-25, and IV-
G-01). The commenters generally favored the increased flexibility in
determining SO2, NOX, CO2 and
O2 span values and supported the concept of a ``default high
range value.'' One commenter, however, opposed the use of purified
instrument air for O2 monitor calibrations (see Docket A-97-
35, Item IV-D-11) and, as discussed in greater detail below, two
commenters who supported the ``default high range'' concept took issue
with the proposed default value (see Docket A-97-35, Items IV-D-05 and
IV-D-24). One commenter asked EPA to give guidance as to what type of
technical justification would be required to use an alternative
O2 span value of less than 15 percent (see Docket A-97-35,
Item IV-D-23). The final rule provides an example, in section 2.3.1 of
Appendix A.
Several commenters stated that the proposed procedures for making
span and range adjustments were particularly complicated and burdensome
(see Docket A-97-35, Items IV-D-19, IV-D-20, IV-D-23, IV-D-24 and IV-G-
09). Two commenters stated that the requirement to perform quarterly
evaluations of the MPC, MEC and MPF values is unnecessary and excessive
(see Docket A-97-35, Items IV-D-11 and IV-G-02). One commenter
recommended using the guideline in section 2.1 of Appendix A to
determine whether span and range adjustments are needed (see Docket A-
97-35, Item IV-D-11). Another commenter recommended that EPA allow data
points that are clear ``outliers'' to be excluded from quarterly span
and range evaluations (see Docket A-97-35, Item IV-D-04). After
carefully considering these comments, EPA has decided to withdraw the
prescriptive proposed procedures for making span and range adjustments.
Instead, the final rule requires that span and range adjustments be
made only when the MPC, MEC or MPF changes ``significantly.'' This is
similar to the original guideline in the January 11, 1993 rule, except
that a ``significant'' change was undefined in that rule. In today's
rule, a significant change in the MPC, MEC or MPF means that the
guideline of section 2.1 of Appendix A ( for the majority of the
readings to be between 20 and 80% of the range, with certain allowable
exceptions) cannot be met, as determined either by the owner or
operator or through an audit by a regulatory agency. The Agency has
also reduced the frequency of mandatory evaluations of the MPC, MEC and
MPF values. In the final rule, only an annual evaluation of these
values is required. The results of the annual evaluations must be kept
on-site, in a format suitable for inspection.
Two commenters stated that the proposed requirement to treat the
two ranges of a dual-range monitor as separate monitoring systems or as
two separate components of the same system would cause additional
programming costs and would be technically difficult to implement (see
Docket A-97-35, Items IV-D-4 and IV-G-02). The commenters requested
that EPA continue to allow the low and high ranges to be represented in
the monitoring plan by a single component. After consideration, the
Agency has decided that the commenters' request is reasonable and has
included this option in the final rule. Note, however, that the use of
this option is restricted to dual-range analyzers that use electronic
gain to produce the two ranges. Today's rule requires the use of a
special dual-range component type code when this option is selected.
EPA will provide the necessary type code and reporting guidance in the
electronic data reporting (EDR) instructions for EDR version 2.1.
Two commenters stated that 200% of MPC is too high for the proposed
default high range value in sections 2.1.1.3(f) and 2.1.1.4(e) of
Appendix A, for the case where the owner or operator uses a default
value instead of operating a high-range monitor (see Docket A-97-35,
Items IV-D-05 and IV-D-24). A third commenter objected to the proposed
value of 200% of the range, which is to be reported during full-scale
exceedances (see Docket A-97-35, Item IV-G-05). Without a functional
high range monitor, it is not possible to determine the exact pollutant
concentration when a control device malfunctions or when a full-scale
exceedance occurs. In the preamble to the proposed rule, EPA cited one
instance in which the high SO2 range was exceeded and the
estimated SO2 concentration (based on fuel sampling) was
estimated to be about 150% of the range (see 63 FR 28058). For this
reason, the proposed values of 200% of the range (for full-scale
exceedances) and

[[Page 28571]]

200% of the MPC (for the default high range value) have been retained
in the final rule. EPA maintains that these values must be
conservative, based on a ``worst case'' analysis to ensure that
emissions will not be under-reported. The Agency believes that if spans
and ranges are properly set, full-scale exceedances will be relatively
rare. Also, EPA anticipates that the majority of the units for which
owners or operators will elect to use the default high range option
have reliable emission controls and the default value will rarely, if
ever, have to be used.
One commenter objected to the proposed changes to the method of
calculating MPC and MEC values, expressing concern that the revisions
might require his existing span and range values to be re-calculated
(see Docket A-97-35, Item IV-G-02). Another commenter (mistakenly)
interpreted the proposed definition of the MPC for CO2 in
section 2.3.1 of Appendix A to mean that his existing CO2
span values would have to be re-determined (see Docket A-97-35, Item
IV-D-04). A third commenter asked EPA to ``grandfather'' existing span
and range values (see Docket A-97-35, Item IV-D-20). It is not, and
never has been EPA's intent to require utilities to change their
existing spans and ranges, provided that they meet the guideline of
section 2.1 of Appendix A ( for the majority of the readings to be
between 20 and 80% of full-scale, with certain allowable exceptions).
The Agency does not believe that ``grandfathering'' of any existing
part 75 span and range values is necessary. The final rule simply adds
flexibility to the procedures for determining spans and ranges.
Affected units with previously-determined span and range values that
meet the guideline of section 2.1 of Appendix A do not have to change
their current span or range values. To further alleviate undue concern
about this, the Agency has withdrawn the proposed changes to the method
of determining whether a dual span is required. Rather than comparing
the MEC value(s) to the MPC value(s) (as proposed), today's rule
specifies that the MEC value should be compared to the high range
value. This is essentially the same as the requirement in the current
rule.
Finally, one commenter objected to the proposed requirement to
perform the RATA at the low range of the monitor on units that have
scrubbers. The commenter urged EPA to revert to the original rule and
allow the RATA to be performed at whatever range the CEMS is operating
on at the time of the RATA (see Docket A-97-35, Item IV-G-3). EPA does
not agree with the commenter. For units with SO2 scrubbers,
the vast majority of the data is collected on the low range. Therefore,
the SO2 RATA should be performed on that range. If the
scrubber malfunctions at the time of a scheduled SO2 RATA,
the RATA should either be rescheduled later in the quarter or should be
done during the 720 unit operating hour grace period allowed under
revised section 2.3.3 of Appendix B.

E. Flow-to-Load Ratio Test Requirements

Background: The quality assurance requirements for flow rate
monitoring systems in Appendices A and B of part 75 include daily
calibration error tests, daily interference checks, quarterly leak
checks (for differential pressure type monitors only), and semiannual
or annual RATAs. Of these required QA tests, only the RATA provides a
true evaluation of a flow monitor's measurement accuracy by direct
comparison against an independent reference method. The daily
calibration error test checks the system's internal electronic
components by means of reference signals. The calibration error test is
useful in that it can diagnose certain types of monitor problems, but
it does not evaluate the system's ability to measure an actual stack
gas flow rate. Because of this limitation, EPA believes that a more
substantive, periodic QA test is needed to ensure that the accuracy of
the reported flow rate data is maintained in the interval between
successive RATAs. The Agency is particularly concerned about the
potential for poor data quality from flow monitors that are not
properly maintained.
In view of this, EPA proposed to add a new flow monitor quality
assurance test, the ``flow-to-load ratio test,'' to part 75 in section
7.7 of Appendix A and section 2.2.5 of Appendix B. A similar test was
first suggested to the Agency by a flow monitor manufacturer (see
Docket A-97-35, Item II-D-69). The flow-to-load ratio test, which would
be performed quarterly, would be required beginning in the second
quarter of the year 2000. The basic premise of the flow-to-load ratio
test is that a meaningful correlation exists between the stack gas
volumetric flow rate and unit load. In general, for a single unit
discharging to a single stack, as the load increases, the flow rate
increases proportionally, and the flow rate at a given load should
remain relatively constant if the same type of fuel is burned. Common
stacks are somewhat less predictable, because the same combined unit
load can be produced in a number of ways by using different
combinations of boilers. Despite this, if the diluent gas concentration
is properly taken into account, the flow-to-load characteristics of
common stacks often become more normalized. The flow-to-load ratio, or
a normalized ratio, such as the gross heat rate (GHR) can thus serve as
a quantitative indicator of flow monitor accuracy from quarter to
quarter until the next RATA is performed.
The proposed rule provided a calculation methodology for the
quarterly flow-to-load or GHR evaluation. A ``reference'' flow-to-load
ratio or GHR would be established at the time of each normal-load flow
RATA, using data from the flow rate reference method. Then, in
subsequent quarters, hourly data from the flow monitor would be
compared to the reference ratio or GHR, and an absolute average
percentage difference between the hourly data and the reference ratio
would be calculated. If the percentage difference exceeded certain
limits, the utility would be required to investigate to try to
establish the cause of the test failure. If the investigation indicated
a problem with the flow monitor, the utility could perform corrective
actions, followed by an abbreviated flow-to-load diagnostic test, to
demonstrate that the corrective actions were effective. However, if the
investigation could not establish the cause of the flow-to-load test
failure, a normal load flow RATA would be required.
Today's final rule adopts the flow-to-load ratio test provisions.
The final rule is essentially the same as the proposal except for a few
minor changes in response to comments received.
Discussion: EPA received comments on the proposed quarterly flow-
to-load ratio test from seven utilities, two state agencies, one
utility regulatory response group and one flow monitor vendor. One
state agency was supportive of the test, because it can serve as a
quantitative indicator of flow monitor performance from quarter to
quarter (see Docket A-97-35, Item IV-D-9). The flow monitor vendor also
favored the test, because it will help to ensure that all flow
monitoring technologies perform in a reliable manner (see Docket A-97-
35, Item IV-D-12). Several utility commenters objected to the proposed
test, believing it would be burdensome, time-consuming, expensive to
implement (requiring significant DAHS software modifications), and
difficult to pass (see Docket A-97-35, Items IV-D-16, IV-G-5, IV-G-9,
IV-G-2). One commenter suggested that the test be used as a warning to
take corrective action rather than using it to directly validate or
invalidate flow rate data (see

[[Page 28572]]

Docket A-97-35, Item IV-D-11). Another commenter recommended that for
common stacks, additional hours be exempted from the data analysis,
specifically hours in which the combination of boilers and loads does
not match the combination used during the last normal load flow RATA
(see Docket A-97-35, Item IV-D-17). Two commenters recommended
increasing the threshold to qualify for a less stringent flow-to-load
specification from 50 MW to 60 or 70 MW (see Docket A-97-35, Items IV-
D-11, IV-D-2). Two commenters recommended reducing the frequency of
flow RATAs based on good performance in the flow-to-load test;
specifically, one commenter advocated performing flow RATAs every other
year and the other commenter recommended performing a flow RATA once
every five years (see Docket A-97-35, Items IV-D-22, IV-G-2). One
commenter stated that the proposed flow-to-load methodology does not
adequately address multiple stack configurations where one of the
stacks is a bypass stack, and also recommended that EPA make it clear
that the flow-to-load data analysis only applies to reported data and
not to redundant backup monitor data which are not reported (see Docket
A-97-35, Item IV-G-2). Finally, the utility regulatory response group
found the proposal to be an improvement over the pre-proposal draft
that was circulated in May, 1997, but took issue with the following:
(1) The method of calculating the test results, using the absolute
value of, rather than the arithmetic, percentage of differences between
the hourly flow-to-load ratios and the reference ratio; (2) failure of
the proposal to address units with bypass stacks or other complex stack
configurations; and (3) allowing only one week after the end of the
quarter to investigate and troubleshoot the flow monitor when a flow-
to-load test failure occurs, before a RATA requirement is triggered
(see Docket A-97-35, Item IV-D-20).
Today's rule includes flow-to-load test provisions in section 7.7
of Appendix A and section 2.2.5 of Appendix B. The final rule is
essentially the same as the proposal, except for the following changes,
which have been incorporated in response to the comments received.
First, a new section 7.8 has been added to Appendix A, which allows
owners or operators of units with complex stack configurations to
petition for an exemption from quarterly flow-to-load testing. Any such
petition would have to provide information and data which demonstrate
to the satisfaction of the Administrator that the flow rate through the
complex stack configuration cannot be reasonably correlated to unit
load. Second, for a unit with a multiple stack discharge configuration
consisting of a main stack and a bypass stack (e.g., for a unit with a
wet SO2 scrubber), the flow-to-load test is to be performed
on an individual stack basis and hours in which emissions are
discharged simultaneously through both stacks may be excluded from the
quarterly flow-to-load analysis. Third, the threshold to qualify for a
less stringent flow-to-load specification has been raised from 50 MW to
60 MW. Fourth, when a flow-to-load or GHR test is failed, two weeks,
rather than one, are allowed after the end of the quarter to
investigate the cause of the test failure before triggering a RATA
requirement.
EPA does not agree with the commenters who characterized the
proposed flow-to-load test as time-consuming, burdensome, and difficult
to implement (requiring extensive software revision). The Agency
believes that implementation of the flow-to-load test will not require
any special modification of existing part 75 DAHS systems or software.
All of the information needed to perform the quarterly flow-to-load or
GHR analysis is currently reported in the electronic quarterly report
required under Sec. 75.64. Rather, a PC-based computer program will be
needed, which can extract the essential information from the quarterly
report and analyze it. Once such a computer program is written,
analysis of the quarterly flow rate and load data should become a
routine operation which will be neither burdensome nor time-consuming.
The Agency also disagrees with those commenters who contended that
the flow-to-load test will be difficult to pass. On the contrary, the
flow-to-load test should be relatively easy to pass, provided that the
flow monitor is properly operated and well-maintained. Prior to issuing
the proposed rule, EPA analyzed quarterly flow rate and load data from
the third quarter of 1996 for 21 units and stacks, including 9 single
units, 11 common stacks, and 1 multiple-stack unit. The units chosen
for this analysis were selected as a representative sample of units
that would be affected by this QA test requirement and included various
operational circumstances (e.g., base loaded and peaking units, single
fuel units, and units that burn multiple fuels). The flow-to-load and
GHR test methodologies were applied to each unit or stack, excluding
none of the normal load data from the analysis. The results of the
flow-to-load and GHR data analyses were nearly the same. Only one
failure of the quarterly flow-to-load test was observed in each
analysis (i.e., the failure rate was f (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 (f was 7.3 percent for the analysis of the flow-to-
load ratios and 8.0 percent for the simulated GHR analysis (with
diluent gas corrections), which is still well below the 15.0 percent
tolerance limit (see Docket A-97-35, Item IV-A-3). Thus, it appears to
make very little difference, in terms of ease of passing, whether the
absolute percentage difference or the arithmetic percentage difference
is used in the flow-to-load and GHR calculations. Therefore, the flow-
to-load and GHR calculation methodology has been finalized as proposed
using the absolute percentage difference.
Two commenters suggested that the flow RATA frequency should be
reduced based on good performance on the quarterly flow-to-load test
(see Docket A-97-35, Items IV-D-22 and IV-G-02). The Agency agrees with
the commenters that with the addition of the new QA tests it is
reasonable to lessen the frequency of the annual three load flow RATA.
Therefore, EPA is also adopting the following three provisions reducing
the flow RATA requirements: (1) Routine flow RATAs are changed from
three-load tests to two-load tests; (2) a single-load annual flow RATA
is allowed if the unit operates at one load level for 85
percent of the time since the last annual flow RATA; and (3) a three-
load flow RATA is required only once every five years and whenever the
instrument is re-linearized. EPA has adopted these reduced flow RATA

[[Page 28573]]

requirements principally because of the reasonable assurance of data
quality that will be provided in between RATAs by the new flow-to-load
test. Note, however, that the flow-to-load ratio test, which analyzes a
limited amount of flow rate data at a single load level, does not serve
as a replacement for annual RATA testing. Rather, the flow-to-load
ratio test helps to ensure that the flow monitor remains accurate in
between successive semiannual or annual RATAs.

F. RATA and Bias Test Requirements

1. RATA Load Levels
Background: The previous provisions of part 75 were neither
sufficiently standardized nor clear in defining the appropriate load
levels for RATAs. For example, the previous rule required gas monitor
RATAs to be conducted at normal load and required gas and flow rate
monitor bias adjustment factors to be determined at normal load, but no
definition of normal load was provided. In addition, section 6.5.2 of
Appendix A specified that the ``low'' load audit point for a 3-level
flow RATA can be located anywhere from the minimum safe, stable load to
50.0 percent of the maximum load, and no minimum separation is required
between the audit points at adjacent load levels. If adjacent audit
points are too close together, a multiple load flow evaluation loses
its significance.
EPA proposed revisions to Appendix A of part 75, which would more
clearly define the load levels at which RATAs are done in order to
achieve greater consistency in the way that RATAs are performed. The
proposed methodology, which would become effective as of April 1, 2000,
would require the utility to define the ``range of operation'' for each
affected unit or common stack (except for peaking units). The range of
operation would extend from the minimum safe, stable load to the
maximum achievable load. The ``low'' load level would then be defined
as 0-30% of the range of operation, the ``mid'' load level would be 30-
60% of the range and the ``high'' load level would be 60-100% of the
range. The proposed methodology would require a load frequency
distribution (histogram) to be developed, prior to each annual RATA, to
determine the percentage of time the unit or stack has operated at each
load level in the previous four ``QA operating quarters.'' A summary of
the data used for the load frequency determination would be maintained
on-site in a format suitable for inspection, and the results of the
determination would be included in the electronic quarterly report
under Sec. 75.64. The most frequently used load level would then be
designated as the ``normal'' load. The second most frequently used load
could, at the discretion of the owner or operator, be designated as a
second normal load level. Gas monitor RATAs would be required at the
normal load level. Routine quality assurance RATAs for flow monitors
would be done at the two most frequently used load levels. Today's rule
adopts the proposed changes with certain modifications in response to
comments.
Discussion: The Agency received comments on the proposed method of
determining RATA load levels from three individual utilities and from
two utility regulatory response groups. Only two comments were received
on the proposed definitions of ``range of operation,'' ``low,''
``mid,'' and ``high'' load levels. One commenter supported the effort
to establish load level definitions, but found the proposal to be too
inflexible and complicated and suggested that EPA should permit
overlapping load ranges (see Docket A-97-35, Item IV-D-20). The other
commenter requested that EPA modify the proposed definition of the
``minimum safe, stable load'' for common stacks. The commenter
expressed concern that for base-loaded units which share a common
stack, the proposed definition might require a unit to be shut down to
attain the low load level in a 3-load flow RATA (see Docket A-97-35,
Item IV-D-24). Four commenters opposed the proposed requirement to
develop a historical load frequency distribution to establish the
normal load level(s) for the unit or stack, stating that the load
frequency is too variable (being dependent on unit availability,
operation, and dispatch) and that the new requirement would add another
level of unnecessary data collection and manipulation (see Docket A-97-
35, Items IV-D-20, IV-D-24, IV-D-19, and IV-D-23). Another commenter
suggested that RATA load ranges should be based on the typical load
requirements for the quarter in which the RATA is done, particularly if
the historical data are no longer representative. The commenters
further recommended that EPA should: (1) eliminate the requirement to
use four operating quarters of data; (2) allow extenuating data to be
excluded; (3) allow recent changes to be considered when selecting load
ranges; and (4) allow utilities to consider forecasted usage of a unit
when selecting load ranges (see Docket A-97-35, Item IV-D-20). Finally,
one commenter objected to the proposed requirement to report the
results of the load frequency data analysis electronically, stating
that requiring electronic reporting of the results provides no
advantage over keeping the data analysis on-site and that such
reporting would require DAHS software changes (see Docket A-97-35, Item
IV-G-2).
Today's rule finalizes the proposed definitions of the ``range of
operation,'' and the ``low,'' ``mid,'' and ``high'' load levels in
section 6.5.2.1 of Appendix A and the associated requirement to report
the upper and lower boundaries of the range of operation, with one
minor revision. A provision has been added for frequently-operated
(e.g., base-loaded) units that share a common stack, which allows the
``minimum safe, stable load'' to be determined in a different manner.
For such units, the owner or operator may use the sum of the minimum
safe, stable loads for the individual units as the minimum safe stable
load for the common stack (rather than using the lowest of the minimum
safe, stable load values for the individual units). The Agency believes
that this adequately addresses the commenter's concern that one or more
units might have to be shut down in order to attain the ``low'' load
level during a 3-load flow RATA.
Section 6.5.2.1 of Appendix A of today's rule also finalizes the
proposed methodology for determining normal load and for selecting the
appropriate load levels for the annual 2-load flow RATAs, with
revisions based on comments received. In the final rule, a
determination of the normal load level(s) and the appropriate flow RATA
load levels is still required, but it has been made a one-time
requirement, rather than an annual requirement. The requirement becomes
effective on April 1, 2000, but owners or operators may comply with it
prior to that date. The owner or operator must review historical load
data for the unit or stack, for a minimum of four representative
operating quarters. From these data, the percentage of unit operating
time at each load level (``low,'' ``mid'' or ``high'') will be
determined. The historical load data may be analyzed by any suitable
means; construction of a histogram, per se, is not required. The load
level used the most frequently will be designated normal, and the
second most frequently used load level may, at the discretion of the
owner or operator, be designated as a second normal load. The two most
frequently used load levels are the load levels at which the annual 2-
load flow RATA will be performed. The results of the historical load
data analysis will be reported in the electronic quarterly report as
part of the electronic monitoring plan. EPA

[[Page 28574]]

believes that reporting one additional monitoring plan record will not
prove to be burdensome. A summary of the data used for the load
determinations and the calculated results must be kept on-site, in a
format suitable for inspection.
EPA continues to believe that a review of historical operating load
data is a reasonable way to standardize the determination of the normal
load level(s) and the appropriate flow RATA load levels for a unit or
stack. In order to maintain national consistency and to ensure that a
``level playing field'' is maintained among affected utilities, the
Agency believes that a standardized procedure is necessary. Although
several commenters took issue with the specifics of the proposed
methodology, none of them provided a sufficiently detailed alternative
procedure for serious consideration by the Agency. Requests to ``allow
exclusion of extenuating data'' and ``permit consideration of recent
changes when selecting load ranges'' do not provide a sufficient basis
for the development of appropriate regulatory language. Further, since
the standardized procedure is based on data for four operating
quarters, any unrepresentative data is likely to have minimal effect.
Therefore, EPA did not incorporate most of the commenters' suggestions.
However, to address the concern of several commenters about possible
variability in unit load and manner of unit operation, a provision has
been added to section 6.5.2.1 of Appendix A which requires the
historical load analysis to be repeated if the way in which a unit
operates changes significantly and the previously-determined normal
load level(s) and the two most frequently used load levels change. The
new provision requires a minimum of two representative operating
quarters of historical load data to document that a change in the
manner of unit operation has actually occurred.
2. Single-Point Reference Method Sampling
Background: Section 6.5.6 of Appendix A to part 75 gives the
traverse point location requirements for reference method sampling
during relative accuracy test audits (RATAs) of gas monitoring systems.
The reference method sampling points are to be located along a line, in
accordance with section 3.2 of Performance Specification No. 2 in
Appendix B to 40 CFR part 60. Performance Specification No. 2 requires
three reference method sampling points for each RATA test run. EPA
proposed changes to section 6.5.6 of Appendix A, pertaining to RATA
traverse point selection. Proposed section 6.5.6 would allow single-
point reference method sampling to be used in two specific instances:
(1) for all moisture determinations, a single reference method point,
located at least 1.0 meter from the stack wall, could be used; and (2)
for flue gas sampling, a single reference method measurement point,
located no less than 1.0 meter from the stack wall, could be used at
any test location if a stratification test is performed prior to each
RATA at the location and certain acceptance criteria are met.
In order to implement the second option (single-point gas
sampling), a 12-point stratification test, as described in proposed
section 6.5.6.1, would have to be passed one time at the sampling
location, meeting the acceptance criteria for single-point sampling
given in proposed section 6.5.6.3 of Appendix A. The location would
qualify for single-point gas sampling if the concentration at each
individual traverse point differed by no more than 5.0
percent from the arithmetic average concentration for all traverse
points. The results would also be acceptable if the concentration at
each individual traverse point differed by no more than
3.0 ppm or 0.3 percent CO2 (or O2) from the
arithmetic average concentration for all traverse points. Once a 12-
point stratification test was passed at the candidate sampling
location, either the 12-point test or an abbreviated 3-point or 6-point
stratification test, as described in proposed section 6.5.6.2, would
have to be passed prior to subsequent RATAs at the location.
Today's rule finalizes the provisions for single-point moisture and
gas reference method sampling, with certain modifications in response
to comments received. The criteria in today's rule to qualify for
single-point sampling are more stringent than the criteria in the
proposed rule.
Discussion: EPA received comments from two utilities and three
State air regulatory agencies on the proposal to allow single-point
reference method sampling. One of the utility commenters favored
allowing single-point sampling, viewing it as an excellent step to
improve the overall efficiency of RATA testing (see Docket A-97-35,
Item IV-D-21). The other utility commenter also favored the proposal,
believing that it would reduce the manpower requirements for gas RATA
testing (see Docket A-97-35, Item IV-D-22). One State agency commenter
opposed the unrestricted use of single-point moisture sampling, stating
that the moisture results could be biased if gas stratification is
present in the stack. Another State agency commenter viewed the
proposal to allow single-point reference method sampling as
unfavorable, expressing concern that single-point sampling may not
yield valid results, particularly if the sampling point is too near the
stack wall, where air in-leakage can occur (see Docket A-97-35, Item
IV-D-9). The third State agency commenter appeared to take issue with
the use of a 3-point abbreviated stratification test, stating that for
the large-diameter stacks in the Acid Rain Program, a three point test
is not adequate to demonstrate the absence of stratification.
In response to the comments received, the single-point reference
method provisions in section 6.5.6 of Appendix A of today's rule are
more restrictive than the provisions in the proposal. After careful
consideration, EPA has decided to allow single-point reference method
sampling, but to place additional restrictions on its use. The Agency
believes that some of the state agency commenters' concerns about the
proposed single-point sampling methodology are valid. Accordingly,
today's final rule addresses these concerns.
Today's rule allows the unrestricted use of single-point moisture
sampling only in applications where the moisture data are used to
determine the stack gas molecular weight. For all other moisture
measurement applications, i.e., for moisture monitoring system RATAs or
when moisture data are used to correct emission data from a dry basis
to a wet basis (or vice-versa), single-point moisture sampling is only
permitted if a 12-point pollutant or diluent gas stratification test is
performed and passed (at the 5.0 percent specification in section
6.5.6.3 of Appendix A) prior to the RATA. Similarly, for flue gas
sampling, today's rule allows the use of single-point reference method
sampling only if a 12-point gas stratification test is performed and
passed at the 5.0 percent specification prior to the RATA. Use of an
abbreviated (3- or 6-point) stratification test as a means of
qualifying for single-point sampling is not allowed.
Finally, when a test location qualifies for single-point reference
method sampling, today's rule specifies that the measurement point must
be located at least 1.0 meter from the stack wall and must be situated
along one of the measurement lines used in the 12-point stratification
test. EPA believes that these modifications to the proposed single-
point reference method sampling methodology are necessary to ensure

[[Page 28575]]

that representative samples will continue to be obtained.

G. Data Validation

1. Data Validation During Monitor Certification and Recertification
Background: The previous version of part 75 specified that for any
replacement, change, or modification to a monitoring system requiring
recertification of the CEMS, all data from the CEMS are invalid from
the hour of that replacement, change, or modification until the hour of
completion of all required recertification tests. The proposed rule
would have revised Sec. 75.20(b)(3) to conditionally allow emission
data generated by the CEMS during a recertification test period to be
used for part 75 reporting, provided that the required tests are
successfully completed in a timely manner and that certain data
validation rules are followed during the recertification test period.
Proposed sections 6.2, 6.3.1, and 6.5 of Appendix A would have allowed
these new data validation procedures to also be applied to the initial
certification of monitoring systems. The intended purpose of the
proposed revisions is to minimize the number of hours of substitute
data or maximum potential values that must be reported during a monitor
certification or recertification period.
In proposed Sec. 75.20(b)(3), specific rules were provided for data
validation during the recertification test period. The recertification
test period would begin with the first successful calibration error
test (known as a ``probationary calibration error test'') after making
the change to the CEMS and completing all necessary post-change
adjustments (e.g., reprogramming or linearization) of the CEMS. The
post-change activities could include preliminary tests such as trial
RATA runs or a challenge of the monitor with calibration gases. Data
from the CEMS would be considered invalid from the hour in which the
replacement, modification, or change to the system is commenced until
the hour of completion of the probationary calibration error test, at
which point the data status would become ``conditionally valid.''
The conditionally valid status of the CEMS data would continue
throughout the recertification test period, provided that the required
recertification tests were done ``hands-off'' (i.e., with no
adjustments, such as reprogramming or linearization of the CEMS, other
than the calibration adjustments allowed under proposed section 2.1.3
of Appendix B) and provided that the recertification tests and required
daily calibration error tests continued to be passed. If all of the
required recertification tests and calibration error tests were passed
hands-off, with no failures and within the required time period, then
all of the conditionally valid emission data recorded by the CEMS
during the recertification test period would be considered quality
assured and suitable for part 75 reporting. However, if any required
test was failed, the conditionally valid data would, in most cases, be
invalidated and a new recertification test period would have to be
initiated, following corrective actions.
Today's rule finalizes the CEMS validation procedures for
certifications and recertifications, with certain modifications in
response to comments received.
Discussion: EPA received strongly supportive comments on the
proposed revisions to Sec. 75.20(b)(3) from five utilities, one state
air regulatory agency and two utility regulatory response groups.
However, two utilities asked the Agency to modify the proposal to allow
trial gas injections and preliminary RATA runs to be done during the
recertification test period, rather than prior to it. One commenter
stated that preliminary gas injections and RATA runs, which are
considered to be a valuable maintenance tool, should be allowed
following the probationary calibration error test, and, provided that
the results of the trial runs are acceptable, the recertification
should be allowed to proceed (see Docket A-97-35, Item IV-G-3). Another
commenter requested that the proposal be revised to allow a single
challenge with each of the three gases prior to a linearity test and to
allow up to five preliminary trial runs prior to a RATA (see Docket A-
97-35, Item IV-G-5).
Today's rule finalizes the proposed data validation procedures in
Sec. 75.20(b)(3) for monitor certification and recertification, with
the following modifications in response to the comments. First, an
introductory statement of applicability has been added at the beginning
of Sec. 75.20(b)(3), clearly indicating that the provisions of the
section apply both to recertifications and to initial certifications.
The statement of applicability also allows the data validation
procedures to be applied, at the discretion of the owner or operator,
to the routine quality assurance linearity tests and RATAs required
under Appendix B of part 75 (see the section on ``Data Validation for
RATAs and Linearity Checks'' in this preamble, for a further discussion
of this option). Second, proposed paragraph (b)(3)(x) of Sec. 75.20 has
been merged with proposed paragraph (b)(3)(i), for greater clarity;
both paragraphs deal with missing data substitution prior to the
recertification test period. Third, the definition of a ``hands-off''
recertification test in Sec. 75.20(b)(3)(v) has been revised to make it
clear that once a recertification test has begun, only routine
calibration adjustments following daily calibration error tests are
permitted until the test is completed. Fourth, language has been added
to Sec. 75.20(b)(3) to address the case in which a multi-load flow RATA
is passed at one or more load levels and then failed at a subsequent
load level.
Regarding the fourth revision to Sec. 75.20(b)(3) described in the
previous paragraph, 2.3.2(e) of Appendix B of today's rule states that
in such cases, only the RATA at the failed load level needs to be
repeated (unless re-linearization of the monitor is necessary, in which
case a 3-load RATA is required). Because of this new Appendix B
provision, the following corresponding data validation provisions have
been added to Secs. 75.20(b)(3)(vii)(A) and 75.20(b)(3)(vii)(B): (1)
upon failure of the RATA at the particular load level, the length of
the new recertification test period is not 720 unit operating hours,
but is equal to the number of hours remaining in the original
recertification test period at the time of test failure; and (2) data
invalidation is prospective, beginning with the hour of failure of the
RATA at the particular load level; therefore, conditionally valid data
recorded prior to the test failure at the particular load level are not
invalidated. Finally, in response to the comments received, a new
paragraph, (b)(3)(vii)(E), has been added to Sec. 75.20 to address the
issue of trial RATA runs and pre-test gas injections. Section
75.20(b)(3)(vii)(E) allows pre-test trial gas injections and pre-RATA
runs to be done during the recertification period, for the purpose of
optimizing the performance of the monitoring system. A trial run or
injection will not affect the status of previously-recorded
conditionally valid data, provided that: (1) the results of the trial
run are within the Appendix A specifications for a passed linearity
test or RATA (i.e., for a trial gas injection, within 5% or
5 ppm of the reference gas or, for a trial RATA run, if the average
reference method and the average CEMS readings differ by no more than
10% of the reference method value, or 15 ppm,
or 0.02
lb/mmBtu, or 1.5% H2O, as applicable); (2) no
adjustments are made

[[Page 28576]]

to the calibration of the CEMS following the trial run, other than the
adjustments allowed under section 2.1.3 of Appendix B; and (3) the CEMS
is not repaired, re-linearized, or reprogrammed after the trial run. As
long as these conditions continue to be met, the CEMS can be further
optimized without data loss. However, if, for any trial run or
injection the conditions are not met, the trial run or injection is
treated as a failed or aborted linearity check or RATA and the
applicable provisions in Secs. 75.20(b)(3)(vii)(A) and
75.20(b)(3)(vii)(B) pertaining to aborted or failed recertification
tests must be followed.
2. Data Validation for RATAs and Linearity Checks
Background: EPA proposed rules for CEMS data validation prior to
and during the periodic linearity tests and RATAs required by part 75.
These new provisions were found in proposed sections 2.2.3 and 2.3.2 of
Appendix B. According to these provisions, a linearity test or RATA
could not be started if the CEMS were operating ``out-of-control'' with
respect to any of its other daily, semiannual, or annual quality
assurance tests. Prior to the test, both routine and non-routine
calibration adjustments, as defined in proposed section 2.1.3 of
Appendix B, would be permitted. During the linearity or RATA test
period, however, no adjustment of the monitor would be permitted except
for routine daily calibration adjustments following successful daily
calibration error tests. For 2-level and 3-level flow RATAs, no
linearization of the monitor would be permitted between load levels. If
a linearity check or RATA was failed or aborted due to a problem with
the monitor, the monitor would be declared out-of-control as of the
hour in which the test is failed or aborted. Data from the monitor
would remain invalid until the hour of completion of a subsequent
successful test of the same type.
The proposed rule also attempted to clarify the way in which
linearity and RATA test results are to be reported to EPA in the
electronic quarterly report required under Sec. 75.64. Proposed
sections 2.2.3 and 2.3.2 of Appendix B specified that only the results
of completed and partial tests which affect data validation would have
to be reported. That is, all completed passed tests, all completed
failed tests, and all tests aborted due to a problem with the CEMS
would have to be included in the quarterly report. Therefore, aborted
test attempts followed by corrective maintenance, re-linearization of
the monitor, or any other adjustments other than those allowed under
proposed section 2.1.3 of Appendix B would have to be reported.
However, tests which are aborted or invalidated due to problems with
the calibration gases or reference method or due to operational
problems with the affected unit(s) would not need to be reported,
because such runs do not affect the validation status of emission data
recorded by the CEMS. In addition, aborted RATA attempts which are part
of the process of optimizing a monitoring system's performance would
not have to be reported, provided that in the period from the end of
the aborted test to the commencement of the next RATA attempt: (1) no
corrective maintenance or re-linearization of the CEMS was performed,
and (2) no adjustments other than the calibration adjustments allowed
under proposed section 2.1.3 of Appendix B were made. However, such
aborted RATA runs would still have to be documented and kept on-site as
part of the official test log.
Today's rule finalizes the CEMS data validation requirements for
RATAs and linearity checks. The final rule has been modified from the
proposal, based on comments received.
Discussion: EPA received comments on the proposed data validation
procedures for RATAs and linearity checks from one state air regulatory
agency, two utilities and one utility regulatory response group. Two of
the commenters found the proposed rule language defining the allowable
pre-test adjustments to be inconsistent with the preamble language
found at 63 FR 28075. The commenters noted an apparent contradiction
between the preamble statement that there is ``no significant risk in
allowing pre-RATA adjustments provided that the monitor's accuracy
between successive RATAs can be reasonably established'' and the rule
language in section 6.5(a)(1) of Appendix A that ``no adjustments,
linearizations or reprogramming of the CEMS other than the calibration
adjustments described in section 2.1.3 of Appendix B to this part, are
permitted prior to and during the RATA test period.'' Both commenters
expressed concern that this proposed rule language appeared to exclude
important activities such as re-linearization of a flow monitor (see
Docket A-97-35, Items IV-D-20, IV-G-2). Another commenter also objected
to the proposed language in section 6.5(a)(1) of Appendix A, stating
that technicians need to be able to perform evaluations and adjustments
of flow and gas measurement systems prior to conducting a RATA (see
Docket A-97-35, Item IV-G-3). Another commenter took issue with the
provisions in proposed sections 2.2.3 and 2.3.2 of Appendix B which
allow ``non-routine'' adjustments to be made prior to linearity tests
and RATAs. The commenter especially objected to the idea of allowing
adjustments in a direction away from the reference gas tag value,
believing that this compromises the integrity of the audit and sets an
``unfortunate precedent'' (see Docket A-97-35, Item IV-D-11).
Today's rule finalizes the data validation provisions for linearity
checks and RATAs in sections 2.2.3 and 2.3.2 of Appendix B. Based on
the comments received, EPA has made substantive revisions to the
proposed rule in an attempt to clarify the allowable pre-test
adjustments and the rules for validating the CEMS data. Today's rule
specifies that when a linearity check or RATA is due, the owner or
operator has three options. First, the test may be done ``cold,'' with
no pre-test adjustments of any kind. Second, the test may be done after
making only the routine or non-routine calibration adjustments allowed
under section 2.1.3 of Appendix B. Under this second option, trial gas
injections and preliminary RATA runs are allowed, followed by
additional adjustments (if necessary) within the limits of section
2.1.3 of Appendix B, to optimize the monitor's performance. The trial
runs or injections need not be reported, provided that they meet the
acceptance criteria for trial RATA runs and gas injections in
Sec. 75.20(b)(3)(vii)(E) (see the section of this preamble entitled
``Data Validation During Monitor Certification and Recertification''
for further discussion of these acceptance criteria). If the acceptance
criteria are not met, the trial run is counted as a failed or aborted
test. Third, the CEMS may be repaired, re-linearized or reprogrammed
prior to the quality assurance test. In this case, the CEMS may either
be considered out-of-control from the hour of commencement of the
corrective maintenance, re-linearization or reprogramming until
completion of the required quality assurance test or the owner or
operator may follow the data validation procedures in Sec. 75.20(b)(3)
upon completion of the necessary corrective maintenance, re-
linearization, or reprogramming.
EPA believes that the revisions to sections 2.2.3 and 2.3.2 of
Appendix B address the commenters' concerns about pre-test adjustments.
For example, if, at the time of a scheduled flow RATA, the owner or
operator decides to re-linearize the primary flow monitor to optimize
its performance, this would be permissible under the third option
above. However, re-linearization of a flow monitor

[[Page 28577]]

triggers a requirement to perform a 3-load RATA. Therefore, if the
monitor is declared out-of-control from the hour of the re-
linearization until the hour of completion of the 3-load RATA (as would
be required by the proposed rule), this could result in significant
data loss, since a 3-load RATA can take days (or even weeks) to
complete, depending on electrical demand. For this reason, today's rule
allows the owner or operator to use the recertification data validation
procedures in Sec. 75.20(b)(3) to supplement the quality assurance
provisions in Appendix B. In this example, if the owner or operator
opts to use the data validation procedures in Sec. 75.20(b)(3), data
from the flow monitor would be considered conditionally valid upon
completion of a ``probationary calibration error test,'' following the
re-linearization of the monitor. The procedures in
Sec. 75.20(b)(3)(vii)(E) allow for trial runs and further optimization
of the monitor prior to the RATA. If the 3-level flow RATA is then
passed in accordance with the procedures of Sec. 75.20(b)(3) and within
the allotted time frame (indicating that the re-linearization was
successful), the conditionally valid data will become quality assured
and may be used for reporting.
For the following reasons, EPA does not agree with the commenter
who opposed allowing ``non-routine'' calibration adjustments prior to a
quality assurance test. The ``non-routine'' adjustments described in
section 2.1.3 of Appendix B allow adjustments only within the
performance specifications of the instrument. When a monitor is
initially certified, it must pass several quality assurance tests, one
of which is a 7-day calibration error test. The monitor must
demonstrate, for 7 consecutive operating days, that it is capable of
meeting a calibration error specification of 2.5 percent of
the instrument span (3.0 percent for flow monitors). Once a
monitor has been certified, the ``control limits'' for daily
calibration error tests of the monitor are twice the performance
specification value, i.e., 5.0 percent of span for gas
monitors and 6.0 percent for flow monitors. Thus, when the
``non-routine'' adjustments described under section 2.1.3 of Appendix B
are made prior to a linearity test or RATA, the monitor is actually
being held to a tighter specification than is used for daily operation.
The Agency therefore does not agree that keeping the instrument's
calibration within the performance specification ``band'' at the time
of linearity tests or RATAs compromises the integrity of the audits or
sets a bad precedent. On the contrary, it demonstrates that the monitor
continues to perform in a comparable manner to its performance at the
time of initial certification. When the monitor is held to the
calibration error specification required for initial certification, the
monitor is shown to be capable of passing a linearity test or RATA.

H. Appendix D--Sulfur Dioxide Emissions From the Combustion of Gaseous
Fuels

Background: EPA proposed several revisions to the procedures in
Appendix D of part 75 for determining sulfur dioxide emissions from
gas-fired and oil-fired units. Most of the proposed revisions would
provide affected utilities with additional flexibility and sampling
options. These changes were generally supported by the comments
received and have either been finalized as proposed or with minor
revisions and clarifications. However, for gaseous fuels, EPA received
a number of significant comments concerning the proposed changes to the
definition of the term ``pipeline natural gas'' under Sec. 72.2 and
received other comments which have prompted the Agency to re-evaluate
the applicability and use of Appendix D. In response to the significant
comments received, the Agency is adopting the following final revisions
to Appendix D and to Sec. 72.2:
(1) Revised definitions of ``pipeline natural gas,'' ``natural
gas'' and ``gas-fired'' have been promulgated in Sec. 72.2;
(2) The applicability of Appendix D has been expanded to include
gaseous fuels with any sulfur content (previously, Appendix D had been
limited to gaseous fuels with a sulfur content of 20 grains per 100
scf, or less); and
(3) The methodology for determining the frequency of fuel gross
calorific value (GCV) under section 2.3 of Appendix D has been
modified.
In order to put today's revisions in context, it is necessary to
review how the Agency addressed these issues in previous rulemakings.
Section 2.4 of Appendix D of the core rules of the Acid Rain Program
issued on January 11, 1993, allowed units combusting ``natural gas''
(as defined in Sec. 72.2) to calculate SO2 mass emissions
through either: (1) fuel sulfur sampling and measurement of the fuel
flow rate by a certified fuel flowmeter; or (2) the use of a default
SO2 emission rate of 0.0006 lb/mmBtu and heat input
determined using a certified fuel flowmeter and monthly analysis for
fuel GCV. In the preamble to the January 11, 1993 rule, the Agency
stated, ``the definition of ``natural gas'' does not, therefore,
include landfill gas, digester gas, biomass, or gasified coal'' (58 FR
3590 and 3596). The Agency further stated in the preamble that,
``essentially sulfur-free fuels such as natural gas, landfill methane,
or synthetic propane'' should qualify for the use of Appendix D
methodologies. The intent of the Agency in that rulemaking was to allow
the use of a default emission rate for SO2 mass emissions
calculations for natural gas and other fuels which have a similar low
sulfur content, but not for fuels which have higher sulfur content than
natural gas. Appendix D did not effectively address how to determine
SO2 mass emissions for gaseous fuels other than natural gas.
On May 17, 1995 the Agency revised the core Acid Rain rules to add
a new definition for ``pipeline natural gas,'' and revised the
definitions of ``natural gas'' and ``gas-fired.'' The most significant
change in the definition of ``natural gas'' was the addition of the
requirement that ``natural gas'' must contain ``one grain or less
hydrogen sulfide per 100 standard cubic feet and 20 grains or less
total sulfur per 100 standard cubic feet.'' The intent of this
additional language was to clarify which gaseous fuels qualified as
``natural gas.'' The criteria used (1 grain hydrogen sulfide
(H2S) and 20 grains total sulfur) were based on contracts
and tariff sheets for pipeline natural gas regulated by the Federal
Energy Regulatory Commission (FERC). Consistent with this approach, the
Agency defined ``pipeline natural gas'' as natural gas provided by a
supplier through a pipeline. In addition, the Agency modified the
definition of ``gas-fired'' to make it clear that the use of Appendix D
was limited to units combusting ``fuel oil,'' ``natural gas,'' and
``gaseous fuels containing no more sulfur than natural gas.'' The
default SO2 emission rate of 0.0006 lb/mmBtu could only be
used for the combustion of either natural gas or a fuel with a sulfur
content no greater than natural gas. To use the default SO2
emission rate, the owner or operator was required to demonstrate that
the fuel being combusted qualified as natural gas, based on contract or
tariff values which indicate that the gas meets the criteria for
natural gas H2S content and total sulfur content.
As noted in the preamble of the proposed rule, the May 12, 1995
revisions apparently did not eliminate confusion concerning the use of
the default SO2 emission rate. The SO2 default
emission rate of 0.0006 lb/mmBtu is equivalent to approximately 0.2
grains hydrogen sulfide per 100

[[Page 28578]]

standard cubic feet (scf) of gas, when hydrogen sulfide is the sole
source of total sulfur in the gas (as is the case for refined natural
gas), or 0.2 grains total sulfur per 100 scf of gas. The Agency did not
intend that fuels with average sulfur content much higher than 0.2
grains per 100 scf should be allowed to use the default value. In this
context, the current definition of ``natural gas'' under Sec. 72.2,
which includes the term ``20 grains of total sulfur,'' is somewhat
confusing. Further, use of the 0.0006 lb/mmBtu default emission rate
for ``natural gas'' with one grain of H2S per 100 scf would
result in an approximately five-fold underestimation of SO2
emissions. Therefore, in the proposed rule, the Agency modified the
definition of pipeline natural gas to include only natural gas with a
hydrogen sulfide content less than or equal to 0.3 grains hydrogen
sulfide per 100 scf, thereby clarifying that the default emission rate
of 0.0006 lb/mmBtu could only be used for natural gas with an
appropriately low hydrogen sulfide content.
The proposed rule required documentation of the hydrogen sulfide
content of the natural gas either through quality characteristics
specified by a purchase contract or pipeline transportation contract,
through certification of the gas vendor, based on routine vendor
sampling and analysis, or through at least one year's worth of
analytical data on the fuel hydrogen sulfide content from samples taken
at least monthly, demonstrating that all samples contain 0.3 grains or
less of hydrogen sulfide per 100 standard cubic feet. For a fuel to be
classified as ``pipeline natural gas'' the fuel would, of course, first
have to meet the current definition of ``natural gas'' in Sec. 72.2,
which states, ``Natural gas means a naturally occurring fluid mixture
of hydrocarbons (e.g., methane, ethane, or propane) containing 1 grain
or less hydrogen sulfide per 100 standard cubic feet, and 20 grains or
less total sulfur per 100 standard cubic feet), produced in geological
formations beneath the Earth's surface, and maintaining a gaseous state
at standard atmospheric temperature and pressure under ordinary
conditions.''
Discussion: Several comments were received on the proposed changes
to the definition of ``pipeline natural gas,'' and comments were also
received on the current definition of ``natural gas.'' In responding to
the comments, the Agency is revising both the definition of ``pipeline
natural gas'' and ``natural gas,'' as well as making various
corresponding changes to wording in part 75 to ensure consistency
within the rule.
Two commenters were opposed to the change to the definition of
pipeline natural gas (see Docket A-97-35, Items IV-D-23 and IV-D-24).
Both commenters suggested that the requirement to document that a
gaseous fuel has 0.3 gr/100 scf of H2S, as
opposed to the previous requirement to document an H2S
content 1.0 gr/100 scf, would either disqualify some sources
currently using the default emission rate of 0.0006 lb/mmBtu or force
those sources to use means other than the contract or tariff provisions
to demonstrate that the hydrogen sulfide content of the gas is less
than 0.3 gr./100 scf. Under the proposed Appendix D revisions, any
sources disqualified from the use of the default SO2
emission rate would either be required to begin daily gas sampling of
the fuel sulfur content or would have to install an SO2
CEMS.
Two other commenters suggested that the use of two sulfur content
criteria in the natural gas definition (the dual criteria of 1 grain
H2S and 20 grains total sulfur per 100 scf) was confusing
and could lead to misinterpretation of which fuels could be classified
as either ``pipeline natural gas'' or ``natural gas'' under Sec. 72.2
(see Docket A-97-35, Items IV-G-3 and IV-G-10). One of these commenters
suggested that the definition of natural gas should be changed to
incorporate only the requirement of 20 grains or less of total sulfur
per 100 scf. If this suggestion were followed, a source with 20 grains
total sulfur per 100 scf could use an SO2 emission rate of
0.0006 lb/mmBtu, thereby underestimating SO2 emissions 100-
fold. This would clearly be unacceptable and contrary to the Agency's
intent since the initial adoption of Appendix D.
One commenter suggested that the requirement to determine the fuel
GCV on the same frequency as sulfur sampling be removed from Appendix D
and that monthly GCV sampling be allowed in all cases (see Docket A-97-
35, Item IV-D-20). The commenter claimed that the variability of fuel
GCV is not necessarily the same as the variability of the sulfur
content of a fuel.
1. Summary of EPA Analysis of Appendix D Gaseous Fuel SO2
and Heat Input Methodologies
In responding to the comments received, the Agency first attempted
to quantify the SO2 emissions from the combustion of gaseous
fuels under the current Acid Rain rules. A data analysis was performed,
assuming that the vast majority of SO2 emissions from the
combustion of gaseous fuel are from affected units reporting gas as the
primary fuel. The data analysis (which was limited to 1997 emission
data) indicates the following: (1) there are 582 units that list gas as
the primary fuel (representing about 30% of the units in the program);
(2) these 582 units accounted for approximately 10% of the total heat
input reported for all Acid Rain-affected units; (3) the total amount
of SO2 emitted by these 582 units was 14,728 tons in 1997 or
0.1% of the total SO2 mass emissions in the program; and (4)
of the 14,728 tons of SO2 emitted by the 582 units, 12,844
tons were from only 17 units and the remaining 1,884 tons were from the
remaining 565 units (see Docket A-97-35, Item IV-A-4). Thus it appears
that gas-fired units account for a significant portion of the total
heat input and electrical generation under the Acid Rain Program, but
contribute only a fraction of one percent of the total SO2
emissions. Note, however, that even though emissions from the
individual gas-fired units are very small, the cumulative emissions
from all 582 units are roughly equivalent to the typical SO2
emissions from a coal-fired unit. For this reason, the method of
calculating the SO2 emissions from the gas-fired units must
be sufficiently accurate to prevent significant underestimation of
emissions. The methodology in the current rule allows the default
SO2 emission rate of 0.0006 lb/mmBtu to be used for all
types of natural gas. As previously noted, the default emission rate
corresponds to 0.2 grains of H2S per 100 scf, but the
definition of natural gas allows fuels with up to 1.0 grain of
H2S and 20 grains of total sulfur to be classified as
``natural gas.'' In view of this, it is possible that the reported
cumulative SO2 emissions reported in 1997 for the 582 gas-
fired units may be inaccurate by several orders of magnitude. This
level of uncertainty in reported emissions is unacceptable in an
allowance trading program such as the Acid Rain Program. Consequently,
a more representative method is needed to characterize the actual
sulfur content of the gaseous fuels combusted by Acid Rain-affected
units.
The Agency also performed an analysis of all available gaseous fuel
GCV sampling data from all Acid Rain sources reporting such data in
1997. Gaseous fuels were analyzed in two categories, pipeline natural
gas and ``other'' gas. Only 14 Acid Rain sources reported sampling and
analysis of ``other'' gases in 1997. The data analysis showed that for
275,669 pipeline natural gas analyses, the average fuel GCV was 1023
Btu/ft3 and the 95th

[[Page 28579]]

percentile value was 1051 Btu/ft3, a difference of only
2.6%. For the ``other'' gaseous fuels, the average GCV from 14,282
analyses was 819 Btu/ft3 and the 95th percentile value was
1118 Btu/ft3, a difference of approximately 26%. This
demonstrates the consistency of the GCV of pipeline natural gas and the
high variability of the few ``other'' gaseous fuels for which Appendix
D is currently being used (see Docket A-97-35, Item IV--A-1).
In finalizing today's rule, the Agency also considered the
potential impact of the revisions to Appendix D on the new Subpart H of
part 75 (which establishes the requirements for monitoring of
NOX mass emissions). Currently, the provisions of Subpart H
are being used by the Ozone Transport Commission (OTC) NOX
Budget Program and, in the future, Subpart H may be adopted as part of
an implementation plan as a means of complying with the NOX
SIP Call (see 63 FR 57356). Subpart H of part 75 allows heat input
determined by the procedures of Appendix D to be used in determining
NOX mass emissions from gas-fired units. In the process of
implementing part 75 and the OTC NOX Budget Program, the
Agency has encountered an increasing number of sources that combust
gaseous fuels which neither qualify as ``pipeline natural gas'' or
``natural gas.'' These fuels include refinery gas, landfill gas,
digester gas, coke oven gas, process gas, propane liquified gas,
liquified petroleum gas, blast furnace gas and coal-derived gas. Under
the previous version of part 75 units combusting these fuels would
either be required to install SO2 and stack flow monitoring
systems or would have to petition the Agency to use Appendix D. It is
likely that under the OTC NOX Budget Program and under the
SIP call, the number of sources combusting these ``other'' gaseous
fuels and required to monitor heat input using part 75 methods will
increase significantly. The Agency anticipates that the owners or
operators of the majority of these sources would petition to use the
procedures of Appendix D to determine heat input used for
NOX mass calculations, in lieu of installing CEMS. However,
the current Appendix D does not address how to determine hourly heat
input for gaseous fuels with variable GCV. The Agency also notes that
any error in hourly heat input determined under Appendix D would result
in a corresponding and equal error in the reported NOX mass
emissions. It is therefore particularly important to establish
consistent and easily implementable heat input monitoring criteria for
all types of gaseous fuels under Appendix D. Clear, flexible and
reasonable requirements for gaseous fuel GCV sampling and analysis are
needed.
Based on the comments received and the data analyses described
above, the Agency has concluded that:

The use of the default SO2 emission rate of
0.0006 lb/mmBtu is only appropriate for natural gas with a
documented contractual or tariff limit of 0.3 grains hydrogen
sulfide per hundred standard cubic feet or for fuels which are
demonstrated to have a similar low total sulfur content.
For natural gas with a contract or tariff hydrogen
sulfide limit up to 1.0 grain of hydrogen sulfide per 100 standard
cubic feet, or for fuels which are demonstrated to have a similar
low total sulfur content, a site-specific default SO2
emission rate should be allowed, which more closely represents the
potential SO2 emission rate for that fuel.
The applicability of Appendix D should be expanded to
include any gaseous fuel (rather than limiting it to fuels with a
total sulfur content 20 grains per 100 scf. For gaseous
fuels with highly variable sulfur content, hourly sampling using
advanced monitoring such as on-line gas chromatography should be
required. The frequency of determination of the GCV of a gaseous
fuel should be independent of the requirements for sulfur sampling
and should be based solely on the variability of the GCV.
2. Changes to the Definitions of ``Pipeline Natural Gas'' and ``Natural
Gas''
As previously stated, the Agency is revising the definitions of
``pipeline natural gas'' and ``natural gas'' in Sec. 72.2. Since the
definition of ``pipeline natural gas'' necessarily includes the
definition of ``natural gas'', and the definitions therefore involve
similar issues, EPA is addressing both definitions in today's final
rule. In particular, ``pipeline natural gas'' is defined in such a way
that only fuels with the appropriate sulfur content can meet the
definition and can use the default emission rate of 0.0006 lb/mmBtu.
Under the revised definition, pipeline natural gas must contain less
than 0.3 grains of hydrogen sulfide per 100 scf. Consistent with this
approach, the definition of ``natural gas'' is revised so that only the
requirement for the hydrogen sulfide content to be less than one grain
per 100 scf remains, and the requirement for the total sulfur content
to be 20 grains per 100 scf is deleted. Further, EPA is
adding to both definitions a requirement that hydrogen sulfide content
must account for at least 50% (by weight) of the total sulfur in the
fuel. This ensures that a fuel with a high total sulfur content, but a
relatively small hydrogen sulfide content, cannot qualify to use a
default SO2 emission rate. The Agency believes that in
general, any ``natural gas'' with 1.0 grain of
H2S/100 scf will also meet the requirement that hydrogen
sulfide must account for 50% of the total sulfur in the
fuel. However, the Agency reserves the right to request that the owner
or operator provide data to demonstrate compliance with this latter
requirement. Finally, EPA is adding a requirement to the ``natural
gas'' definition that the gas must have either a methane content of at
least 70% or the same GCV as methane (950 to 1100 Btu/scf). This
requirement ensures that the gas will have a stable GCV, consistent
with the Appendix D provisions which allow monthly GCV sampling for
either pipeline natural gas or natural gas. In today's rule, the
requirements for documenting that a fuel qualifies as ``pipeline
natural gas'' or ``natural gas'' are essentially the same as the
proposed rule. The three principal ways of providing the necessary
documentation are: (1) gas quality characteristics specified in a
purchase contract or pipeline transportation contract; (2)
certification by the gas vendor, based on routine sampling and analysis
for at least one year; and (3) at least one year of analytical data on
the fuel characteristics, derived from monthly (or more frequent)
samples. In addition, sections 2.3.5 and 2.3.6 of Appendix D of today's
rule allow the owner or operator to conduct a 720 hour demonstration of
the fuel's sulfur and GCV characteristics (see Items 5 and 6 in this
section, below).
EPA believes that the revised definitions of ``pipeline natural
gas'' and ``natural gas'' will: (1) apply to the low sulfur fuel
combusted by the vast majority of the sources in the Acid Rain Program;
(2) be documentable, in most cases, based on contract or tariff
provisions without other types of demonstrations; and (3) allow most
sources currently using 0.0006 lb/mmBtu as a default to continue using
that default value or to use an alternative, site-specific default
value that will not underestimate SO2 emissions.
3. Changes to the Methodology for Calculating SO2 Emissions
Under Appendix D
Today's rule adopts a two-tiered approach to the use of default
SO2 emission rates, depending on whether a fuel qualifies as
``pipeline natural gas'' or as ``natural gas.'' First, if the owner or
operator can demonstrate that the fuel combusted at a unit has
0.3 grains of hydrogen sulfide per 100 scf, the default
SO2 emission rate of 0.0006 lb/mmBtu may be used. Second,
the rule allows units combusting gaseous fuels

[[Page 28580]]

with >0.3 grains, but 1.0 grain of hydrogen sulfide per 100
scf to calculate a site-specific default SO2 emission rate,
as suggested by two of the commenters (see Docket A-97-35, Items IV-D-
23 and IV-D-24). The method of calculating the default value is ba

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Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A99-8939. Public record. Not legal advice.