[Federal Register Volume 63, Number 98 (Thursday, May 21, 1998)]
[Proposed Rules]
[Pages 28032-28195]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 98-11749]
[[Page 28031]]
_______________________________________________________________________
Part II
Environmental Protection Agency
_______________________________________________________________________
40 CFR Parts 72 and 75
Acid Rain Program; Continuous Emission Monitoring Rule Revisions; Acid
Rain Program: Determinations Under EPA Study of Bias Test and Relative
Accuracy and Availability Analysis; Proposed Rules
Federal Register / Vol. 63, No. 98 / Thursday, May 21, 1998 /
Proposed Rules
[[Page 28032]]
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 72 and 75
[FRL-6007-8]
RIN 2060-AG46
Acid Rain Program; Continuous Emission Monitoring Rule Revisions
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
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SUMMARY: Title IV of the Clean Air Act (CAA or the Act), as amended by
the Clean Air Act Amendments of 1990, authorizes the Environmental
Protection Agency (EPA or Agency) to establish the Acid Rain Program.
The Acid Rain Program and the provisions in this proposed rule benefit
the environment by preventing the serious, adverse effects of acidic
deposition on natural resources, ecosystems, materials, visibility, and
public health. The program does this by setting emissions limitations
to reduce the acidic deposition precursor emissions of sulfur dioxide
and nitrogen oxides. On January 11, 1993, the Agency promulgated final
rules, including the final continuous emission monitoring (CEM) rule,
under title IV. On May 17, 1995, the Agency published direct final and
interim rules to make the implementation of the CEM rule simpler.
Subsequently, on November 20, 1996, the Agency published a final rule
in response to public comments received on the direct final and interim
rules.
These proposed revisions to the CEM rule would make a number of
further minor changes to make the implementation of the CEM rule
simpler, more streamlined, and more efficient for both EPA and the
facilities affected by the rule. Furthermore, the proposed revisions
would provide reduced monitoring burdens for affected facility units
with low mass emissions. In addition, the proposed revisions would
establish quality assurance requirements for moisture monitoring
systems and add a new flow monitor quality assurance test to assure the
accuracy of data reported from these types of monitoring systems.
Finally, the proposed revisions would create a new monitoring option,
the F-factor/fuel flow method, for certain units.
DATES: Comments. All public comments must be received on or before July
20, 1998.
Public Hearing. Anyone requesting a public hearing must contact EPA
no later than May 31, 1998. If a hearing is held, it will take place
June 8, 1998, beginning at 10:00 a.m.
ADDRESSES: Comments. Comments must be mailed (in duplicate if possible)
to: EPA Air Docket (6102), Attention: Docket No. A-97-35, Room M-1500,
Waterside Mall, 401 M Street, SW, Washington, DC 20460.
Public Hearing. If a public hearing is requested, it will be held
at the Environmental Protection Agency, 401 M Street, SW, Washington,
DC 20460, in the Education Center Auditorium. Refer to the Acid Rain
homepage at www.epa.gov/acidrain for more information or to determine
if a public hearing has been requested and will be held.
Docket. Docket No. A-97-35, containing supporting information used
to develop the proposal is available for public inspection and copying
from 8:00 a.m. to 5:30 p.m., Monday through Friday, excluding legal
holidays, at EPA's Air Docket Section at the above address.
FOR FURTHER INFORMATION CONTACT: Jennifer Macedonia, Acid Rain Division
(6204J), U.S. Environmental Protection Agency, 401 M Street, SW,
Washington, DC 20460, telephone number (202) 564-9123 or the Acid Rain
Hotline at (202) 564-9620. Electronic copies of this notice and
technical support documents can be accessed through the Acid Rain
Division website at http://www.epa.gov/acidrain.
SUPPLEMENTARY INFORMATION: The contents of the preamble are listed in
the following outline:
I. Regulated Entities
II. Background and Summary of the Proposed Rule
III. Detailed Discussion of Proposed Revisions
A. Use of Projections in the Definitions of Gas-fired, Oil-
fired, and Peaking Unit
B. Wording Correction of the Applicability Provisions in Part 72
C. Low Mass Emissions Excepted Methodology
1. Applicability Criteria
2. Method for Determining Emissions
3. Cutoff Limit for Applicability
4. Continuing Applicability Criteria
5. Reduced Monitoring and Quality Assurance Requirements
6. Reduced Reporting Requirements
D. Quality Assurance Requirements for Moisture Monitoring
Systems
E. Certification/Recertification Procedural Changes
1. Initial Certification versus Recertification
2. Disapproval of an Incomplete Application
3. Submittal Requirements for Certification and Recertification
Applications
4. Decertification Applicability
5. Recertification Test Notice
6. Monitoring Plans
7. Submittal Requirements for Petitions and Other Correspondence
F. Substitute Data
1. Missing Data Procedures for CO2 and Heat Input
2. Prohibition Against Low Monitor Data Availability
G. General Authority to Grant Petitions Under Part 75
H. NOX Mass Monitoring Provisions for Adoption by
NOX Mass Reduction Programs
I. Span and Range Requirements
1. Maximum Potential Values
2. Maximum Expected SO2 and NOX
Concentrations
3. Span and Range Values
4. Dual Span and Range Requirements for SO2 and
NOX
5. Adjustment of Span and Range
J. Quality Assurance/Quality Control (QA/QC) Program
1. QA/QC Plan
2. Flow Monitor Polynomial Coefficient
K. Calibration Gas Concentration for Daily Calibration Error
Tests
L. Linearity Test Requirements
1. Unit Operation During Linearity Tests
2. Linearity Test Frequency
3. Linearity Test Method
4. Exemptions
M. Flow-to-Load Test
N. RATA and Bias Test Requirements
1. RATA Frequency
2. RATA Load Levels
3. Flow Monitor Bias Adjustment Factors
4. Number of RATA Attempts
5. Concurrent SO2 and Flow RATAs
6. SO2 RATA Exemptions and Reduced Requirements
7. QA Provisions for SO2 Monitors, for Natural Gas
Firing or Equivalent
8. General RATA Test Procedures
9. Reference Method Testing Issues
10. Alternative Relative Accuracy Specifications and
Specifications for Low-Emitters
11. Bias Adjustment Factors for Low-Emitters
12. Clarification of Diluent Monitor Certification Requirements
13. Daily Calibration Requirements for Redundant Backup Monitors
14. Daily Performance Specification and Control Limits for Low-
Span DP Flow Monitors
O. CEM Data Validation
1. Recalibration and Adjustment of CEMS
2. Linearity Tests
3. RATAs
4. Recertification of Gas and Flow Monitors
5. Recertification and QA
6. Data from Non-Redundant Backup Monitors
7. Missed QA Test Deadlines
P. Appendix D
1. Pipeline Natural Gas Definitions
2. Fuel Sampling
3. Sulfur, Density, and Gross Calorific Value Used in
Calculations
4. Missing Data Procedures for Sulfur Content, Density, and
Gross Calorific Value
5. Installation of Fuel Flowmeters for Recirculation
6. Fuel Flowmeter Testing
[[Page 28033]]
7. Use of Uncertified Commercial Gas Flowmeter
Q. Appendix G
1. Use of ASTM D5373-93 for Determining the Carbon Content of
Coal
2. Changes to Fuel Sampling Frequency
3. Addition of Missing Data Procedures for Fuel Analytical Data
R. Reporting Issues
1. Partial Unit Operating Hours and Emission and Fuel Flow Rates
2. Use of Bias-Adjusted Flow Rates in Heat Input Calculations
3. Removing the Restriction of Using the Diluent Cap Only for
Start-up
4. Complex Stacks--General Issues
5. Complex Stacks--Heat Input at Common Stacks
6. Start-up Reporting--Units Shutdown Over the Compliance
Deadline
7. Start-up Reporting--New Units
8. Recordkeeping and Reporting Provisions
9. Electronic Transfer of Quarterly Reports
S. Revised Traceability Protocol for Calibration Gases
T. Appendix I--New Optional Stack Flow Monitoring Methodology
U. The Use of Predictive Emissions Modeling Systems (PEMS)
IV. Administrative Requirements
A. Public Hearing
B. Public Docket
C. Executive Order 12866
D. Unfunded Mandate Reform Act
E. Paperwork Reduction Act
F. Regulatory Flexibility Act
G. National Technology Transfer and Advancement Act
I. Regulated Entities
Entities potentially 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, today's proposal
could potentially affect other industries. The proposal includes
NOX mass provisions for the purpose of serving as a model
which could be adopted by a state, tribal, or federal NOX
mass reduction program covering the electric utility and other
industries. Regulated categories and entities include:
------------------------------------------------------------------------
Examples of regulated
Category entities
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Industry.................................. Electric service providers,
boilers and turbines from a
wide range of industries.
------------------------------------------------------------------------
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 criteria in
Secs. 72.6, 72.7, and 72.8 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 the Proposed 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 Agency promulgated final rules implementing the program,
including the CEM rule (58 FR 3590-3766). Technical corrections were
published on June 23, 1993 (58 FR 34126) and July 30, 1993 (58 FR
40746-40752). A notice of direct final rulemaking and of interim final
rulemaking further amending the regulations was 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 59142-59166) .
The issues addressed by this proposed rule are: (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 of the applicability provisions in Part 72; (3) new excepted
methodologies for units with low mass emissions; (4) new QA/QC
requirements for moisture monitoring systems; (5) clarifying changes to
the certification and recertification process; (6) substitute data
requirements for CO2 and heat input, as well as a
prohibition against low data availability; (7) clarifying revisions to
the petition provisions for alternatives to part 75 requirements; (8)
NOX mass monitoring provisions provided as a model for
adoption by state, tribal, or federal NOX mass reduction
programs; (9) clarifying changes to span and range requirements; (10)
clarifying revisions to general QA/QC requirements; (11) calibration
gas concentrations for daily calibration error tests; (12) linearity
test requirements; (13) a new flow-to-load QA test for flow monitors;
(14) reductions in and/or clarifications to the relative accuracy test
audit (RATA) and bias test requirements; (15) clarifying revisions to
the procedures for CEM data validation; (16) clarifying revisions to
the SO2 emissions data protocol for gas-fired and oil-fired
units (Appendix D); (17) determining CO2 emissions (Appendix
G, sections 2.1 and 5); (18) recordkeeping and reporting changes to
reflect the proposed revisions; (19) a revised traceability protocol
(Appendix H); and (20) a new optional F-factor/fuel flow method
(Appendix I). In addition, the preamble also includes a discussion on
potential provisions to allow for the use of predictive emissions
modeling systems (PEMS) as an alternative to CEMS for certain units.
Many of the changes proposed today are minor technical revisions
based on comments received from utilities following the initial
implementation of part 75. Based on experience gained in the early
years of the program, utilities have developed a number of suggestions
that EPA believes would simplify and streamline the monitoring process
without sacrificing data quality. In addition, the Agency is proposing
to reduce the monitoring requirements for units with low mass emissions
to reduce burdens on those types of units and to add new monitoring
options for some units. The Agency has also proposed new quality
assurance requirements based on gaps identified by EPA during
evaluation of the initial implementation of part 75. Finally, several
minor technical changes are also proposed in order to maintain
uniformity within the rule itself and to clarify various provisions.
III. Detailed Discussion of Proposed Revisions
A. Use of Projections in the Definitions of Gas-Fired, Oil-Fired, and
Peaking Unit
Background
Section 72.2 of the January 11, 1993 rule provides definitions for
the terms ``gas-fired,'' ``oil-fired,'' and ``peaking unit.'' Each
definition provides a limit on the fuel usage or capacity factor
averaged over a three year period, as well as an individual limit on
each of the three years, in order to qualify under the definition. The
May 17, 1995 revisions to part 75 amended those definitions by adding
provisions for how a unit would initially qualify to meet the
definition. Each definition provides for the case where a unit has
three years of historical data demonstrating qualification, as well as
the case where a unit does not have data for one or more of the three
previous years (e.g., a new unit or a unit that has been in an extended
shutdown). In addition, the gas-fired definition provides for the case
where a unit's fuel usage is projected to change on or before January
1, 1995 and the peaking unit definition provides for the case where a
unit's capacity factor is projected to change on or before the
certification deadline (either 1995 or 1996) for NOX
[[Page 28034]]
monitoring in Sec. 75.4. In each case where historical data does not
exist or is not representative based on projected change, the amended
definitions set provisions for allowing projections of unit operation
to be used in place of historical data in order to meet the criteria of
the respective definition. However, none of the three definitions
provides for the case where a unit's fuel usage or capacity factor is
expected to change after initial classification.
Under the existing rule, the importance of determining whether a
unit qualifies under the definitions of gas-fired, oil-fired, and
peaking unit, centers on the differences in regulatory requirements and
options for different classifications of units. For example, under
Sec. 75.11(d)(2), a unit that qualifies as gas-fired or oil-fired has
an additional option for monitoring SO2 emissions using the
excepted protocol of Appendix D, in lieu of an SO2 CEMS and
flow monitor. Additionally, under Sec. 75.14(c), a unit that qualifies
as gas-fired is exempt from opacity monitoring, and, under section 2.3
of Appendix G to part 75, a gas-fired unit has an additional option for
determining CO2 mass emissions in lieu of a CO2
CEMS or using carbon sampling in conjunction with a fuel flowmeter.
Qualifying under the definition of peaking unit also has the advantage
of allowing additional regulatory options. For example, a peaking unit
has the option of monitoring NOX emission rate using the
excepted protocol under Appendix E, in lieu of a NOX CEMS.
Further, under section 2.3.1 of Appendix B to part 75, a peaking unit
is required to perform annual quality assurance flow monitor RATAs at a
single load level instead of at three load levels.
Utility representatives have contacted EPA for guidance about how a
change in the manner of operation of the unit after certification and
initial classification of the unit affects the status of the unit with
respect to the definitions of gas-fired, oil-fired, and peaking unit.
For example, a utility representative contacted the Agency about a unit
designed to burn gas and/or oil that historically had burned primarily
oil and was classified as an oil-fired unit. The utility had decided to
switch from oil to burn almost entirely gas at the unit and asked
whether it was necessary to wait three years after the switch to gas in
order to gather three years of historical data, to qualify for the
additional regulatory options available only for gas-fired units. The
utility requested permission to use projections of fuel usage certified
by the designated representative, to demonstrate that the unit would
meet the gas-fired definition after the switch to gas, so that the unit
could be exempt from opacity monitoring and qualify to use equation G-4
to determine CO2 mass emissions. The existing rule would
require such a unit to wait three years after the change in operation
in order to qualify as gas-fired. Based on EPA's experience of
implementing the provisions of Parts 72 and 75, the definitions of the
terms gas-fired, oil-fired, and peaking unit are not sufficiently
detailed or flexible to address situations where a permanent change in
the manner of operation after the initial classification (i.e, capacity
factor or fuel usage) affects the gas-fired, oil-fired, or peaking unit
status.
Discussion of Proposed Changes
Today's proposal would amend the definitions of the terms gas-
fired, oil-fired, and peaking unit, to add provisions for an existing
unit that does not presently qualify under the definition but that
experiences a permanent change in operation (i.e., fuel usage for the
gas-and oil-fired definitions and capacity factor for the peaking unit
definition).
For the definition of gas-fired, the proposed revisions would allow
an existing unit to qualify under the definition if the designated
representative submits a minimum of 720 hours of unit operating data
demonstrating that the unit meets the percentage criteria of a gas-
fired unit (i.e., no less than 90.0 percent of the unit's heat input
from the combustion of gaseous fuels with a total sulfur content no
greater than natural gas and the remaining heat input from the
combustion of fuel oil), accompanied by a certification statement from
the designated representative. The designated representative statement
would certify that the changed pattern of fuel usage, represented in
the 720 hours of data, is considered permanent and is projected to
continue for the foreseeable future.
The proposed definition of oil-fired unit would simplify the
provisions for qualification, for purposes of part 75. The proposed
definition would simply require that a unit burn only fuel oil and
gaseous fuels with a total sulfur content no greater than natural gas
and that the unit does not meet the definition of gas-fired, in order
to qualify as oil-fired. With this simplification, a unit could qualify
under any of the following circumstances: (1) a new unit projected to
burn only fuel oil and gaseous fuels with a sulfur content no greater
than natural gas but projected to burn too much oil to qualify as gas-
fired; (2) an existing gas-fired unit, which burns only fuel oil and
natural gas, but which exceeds the gas-fired annual limit of 15 percent
of the annual heat input from fuel oil; and (3) an existing coal-fired
unit that is converted to only burn fuel oil and/or gas but which
projects it will burn too much oil to qualify as gas-fired.
The proposed definition of peaking unit would allow an existing
unit whose capacity factor is projected to change, to qualify as a
peaking unit if the designated representative submits a demonstration
satisfactory to the Administrator that the unit will qualify as a
peaking unit, using the three calendar years beginning with the first
full year following the change in the unit's capacity factor as the
three year period. This demonstration would need to show that the
unit's capacity factor in the year following the permanent change in
operation did not exceed 10.0 percent and that the projected average
annual capacity factor for the unit in the three year period and the
projected capacity for each of the two individual projected years will
meet the definition of a peaking unit.
Additionally, under today's proposal, the gas-fired definition
would be revised to clarify the requirements as they apply for the
purposes of part 75 versus the requirements for the purposes of all
other Parts under the Acid Rain Program. This proposed revision is
merely editorial and would not change the intent of the existing
regulation.
Rationale
The Agency proposes to allow projections of fuel usage or capacity
factor in conjunction with some actual data to be used for the purpose
of meeting the criteria of the gas- or oil-fired or peaking unit
definitions, respectively. The Agency believes it is unnecessary to
require three years to pass before a unit that the designated
representative certifies has permanently changed its manner of
operation is allowed to utilize the additional regulatory options
allowed for units meeting the definitions of gas-fired, oil-fired, and
peaking unit. The Agency believes it is sufficient to require the
designated representative to submit representative data that the unit
would qualify under the definition following the permanent change in
operation or fuel usage (i.e., 720 hours for the gas-fired definition
and a full year for the peaking unit definition) and to certify that
the change in fuel usage or capacity factor is considered permanent and
that the unit is expected to continue to meet the definition of gas-
fired, oil-fired, or peaking unit, as applicable, into the foreseeable
future.
Under the existing rule, the peaking unit definition does provide
for the
[[Page 28035]]
situation where a unit's operation is projected to change and the unit
will meet the peaking unit definition with those projections. However,
this provision is limited to the case where a unit's operation has
changed by the certification deadline for NOX monitoring.
The existing rule does not provide for the scenario where a change to
the unit's operation after the certification deadline would affect the
peaking unit status and where the designated representative might want
to take advantage of regulatory options that are available under this
new status.
EPA believes that it is appropriate to allow a unit to use the
regulatory options that are only allowed for peaking units, if a unit's
operation permanently changes such that it meets the capacity factor
definition with one year of actual data and two years of projections.
If the projections are incorrect, the unit will lose its peaking unit
status and will not be able to use projections again to qualify.
Similarly, under the existing rule, the gas-fired definition does
provide for the situation where an existing unit that does not qualify
under the gas-fired definition experiences a change in operations or
fuel usage that would result in the unit qualifying as gas-fired in
future years. However, this provision is limited to the case where a
unit's operation has changed by the certification deadline for
SO2 and opacity monitoring, from 1995 through 1997. The
existing rule does not provide for the scenario where a change to the
unit's fuel usage after the certification deadline would affect the
gas-fired status and that the designated representative might want to
take advantage of regulatory options that are available under this new
status.
However, EPA believes that it is appropriate to allow a unit to use
the regulatory options that are only allowed for gas-fired units, if a
unit's fuel usage permanently changes such that it meets the gas-fired
definition with 720 hours of actual data and projections of fuel usage
to make up the remainder of the three year period. If the projections
are incorrect, the unit will lose its gas-fired status and will not be
able to use projections again to qualify.
B. Wording Correction of the Applicability Provisions in Part 72
Background
Section 72.6(b)(1) currently includes, in the list of types of
units that are unaffected units under the Acid Rain Program, ``[a]
simple combustion turbine that commenced operation before November 15,
1990.'' 40 CFR 72.6(b)(1). Title IV actually provides, through
statutory definitions and provisions setting emission limitations, that
a simple combustion turbine that commenced commercial operation before
the enactment of title IV, i.e., November 15, 1990, is an unaffected
unit. A simple combustion turbine commencing commercial operation on or
after November 15, 1990 is an affected unit (unless it is exempt under
some other provision, e.g., the new units exemption under Sec. 72.7).
To begin, the definition of ``existing unit'' in section 402(8) of
the Act excludes existing simple combustion turbines (i.e., those that
commenced commercial operation prior to November 15, 1990) and so
excludes them from being affected units subject to an SO2
emission limitation under section 405(a)(1). As stated in that section
402(8):
``existing unit'' means a unit * * * that commenced commercial
operation before the date of enactment of the Clean Air Act
Amendments of 1990 [i.e., November 15, 1990] * * * For purposes of
this title, existing units shall not include simple combustion
turbines * * * 42 U.S.C. 7651a(8).
In contrast, the statutory definition of ``new unit'' does not exclude
any new simple combustion turbines, and under section 403(e), all new
utility units are affected units subject to an SO2 emission
limitation. As stated in section 402(10):
``new unit'' means a unit that commences commercial operation on or
after the date of enactment of the Clean Air Act Amendments of 1990
[i.e., November 15, 1990]. 42 U.S.C. 7651a(10).
A unit that commences commercial operation after November 15, 1990, and
so does not meet the definition of ``existing unit'', is therefore a
new unit and an affected unit subject to Acid Rain Program
requirements.
While Sec. 72.6(b)(1) states that a simple combustion turbine that
``commenced operation'' before November 15, 1990 is not an affected
unit, EPA interprets this provision, consistent with the Act, to refer
to commencement of commercial operation. However, in order to remove
any ambiguity and any possibility of erroneous application of the
statutory exemption for simple combustion turbines, EPA believes that
the regulatory provision should be corrected.
Discussion of Proposed Changes
Today's proposal would revise the existing Sec. 72.6(b)(1) in order
to make it consistent with title IV of the Act. EPA proposes to revise
the language of the provision to refer expressly to ``commercial
operation,'' rather than simply ``operation,'' of a simple combustion
turbine.
Rationale
EPA notes that the existing Sec. 72.6(b)(1) was not intended to
deviate from the provisions in the Act concerning simple combustion
turbines. In proposing the applicability provisions that were finalized
(with changes) as Sec. 72.6, EPA explained that:
simple combustion turbines would be subject to Acid Rain Program
requirements in Phase II (as new units) if such units commenced
commercial operation on or after November 15, 1990, because the
statutory exemption for simple combustion turbines is only
applicable to existing units. 56 FR 63002, 63008 (1991).
In noting that new simple combustion turbines are affected units, EPA
requested comment on whether a ``de minimis exclusion should be
included in the final rule'' for ``very small units'' from the Acid
Rain Program. Id. In response to comments supporting an exemption for
simple combustion turbines and other units, EPA established in the
final rule an exemption for new units (including new simple combustion
turbines) serving generators with total capacity of 25 MWe or less. 58
FR 3590, 3593-4 (1993); Response to Comment at P-22 and P-23 (1993). In
the final rule preamble, EPA did not indicate any intention to make any
other changes concerning the applicability of the Acid Rain Program to
new simple combustion turbines.
C. Low Mass Emissions Excepted Methodology
Background
In the January 11, 1993 Acid Rain permitting rule, EPA provided for
a conditional exemption from the emissions reduction, permitting, and
emissions monitoring requirements of the Acid Rain Program for new
units having a nameplate capacity of 25 MWe or less that burn fuels
with a sulfur content no greater than 0.05 percent by weight, because
of the de minimis nature of their emissions (see 58 FR 3593-94 and
3645-46). Moreover, in the January 11, 1993 monitoring rule, EPA
allowed gas-fired and oil-fired peaking units to use the provisions of
Appendix E, instead of CEMS, to determine the NOX emission
rate, stating that this was a de minimis exception. EPA allowed this
exception from the requirements of section 412 of the Clean Air Act
because the NOX emissions from these units would be
extremely low, both
[[Page 28036]]
collectively and individually, and because the cost of measuring a ton
of NOX with CEMS could be several hundred dollars per ton of
NOX monitored (see 58 FR 3644-45). One utility wrote to the
Agency, suggesting that the Agency consider further regulatory relief
for other units with extremely low emissions that do not fall under the
categories of small new units burning fuels with a sulfur content less
than or equal to 0.05 percent by weight or gas-fired and oil-fired
peaking units (see Docket A-97-35, Item II-D-31). The utility
specifically suggested that the Agency consider an exemption, the
ability to use Appendix E, or some other simplified methods which are
more cost effective.
In the process of implementing part 75, other utilities also have
suggested to EPA that it provide regulatory relief to low mass emitting
units (see Docket A-97-35, Items II-D-29, II-E-25). These units might
be low mass emitting because they use a clean fuel, such as natural
gas, and/or because they operate relatively infrequently. Some
utilities stated that they spend a great deal of time reviewing the
emissions data when preparing quarterly reports for these units. Others
indicated that it would be important to reduce monitoring and quality
assurance (QA) requirements in order to save time and money currently
devoted to units with minimal emissions (see Docket A-97-35, Item II-E-
25).
Discussion of Proposed Changes
Today's proposal would incorporate optional reduced monitoring,
quality assurance, and reporting requirements into part 75 for units
that burn only natural gas or fuel oil, emit no more than 25 tons of
SO2 and no more than 25 tons of NOX annually, and
have calculated annual SO2 and NOX emissions
(reflecting their potential emissions during actual operation) that do
not exceed such limits.
A unit would initially qualify for the reduced requirements by
demonstrating to the Administrator's satisfaction that the unit meets
the applicability criteria in proposed Sec. 75.19(a). Proposed
Sec. 75.19(a) would require facilities to submit historical actual (or
projections, as described below) and calculated emissions data from the
previous three calendar years demonstrating that a unit falls below the
25-ton cutoffs for SO2 and NOX. The calculated
emissions data for the previous three calendar years would be
determined by applying the emission factors and maximum rated hourly
heat input, under Sec. 75.19(c), to the hours of operation and fuel
burned during the previous three calendar years. The data demonstrating
that a unit meets the applicability requirements of Sec. 75.19(a) would
be submitted in a certification application for approval by the
Administrator to use the low mass emissions excepted methodology. The
Agency requests comments on whether a unit that exceeded the 25-ton
emissions cutoff for a part of the previous three years, but that has
made a permanent change in the operation of the unit such that it would
expect to meet the applicability criteria based on projections of
future operation, should be allowed to use the excepted methodology.
For units that lack historical data for one or more of the previous
three calendar years (including new units that lack any historical
data), proposed Sec. 75.19(a) would require the facility to provide (1)
any historical emissions and operating data, beginning with the unit's
first calendar year of commercial operation, that demonstrates that the
unit falls under the 25-ton cutoffs for SO2 and
NOX, both with actual emissions and with calculated
emissions using the proposed methodology, as described above; and (2) a
demonstration satisfactory to the Administrator that the unit will
continue to emit below the tonnage cutoffs (e.g., for a new unit,
applying the emission rates and hourly heat input, under Sec. 75.19(c),
to a projection of annual operation and fuel usage to determine the
projected mass emissions).
For units with historical actual (or projections, as described
above) emissions and calculated emissions falling below the tonnage
cutoffs, facilities would be allowed to use the optional methodology in
proposed Sec. 75.19(c) in lieu of either CEMS or, where applicable, in
lieu of the excepted methods under Appendix D, E, or G for the purpose
of determining and reporting heat input, NOX emission rate,
and NOX, SO2, and CO2 mass emissions.
Under the optional methodology in proposed Sec. 75.19(c), a facility
would calculate and report hourly SO2 and CO2
mass emissions based on the unit's maximum rated hourly heat input and
the appropriate emission factor, defined in Sec. 75.19(c), Tables 1a
and 1c, for the fuel burned that hour. Similarly, a facility would
calculate and report hourly NOX mass emissions as the
product of the maximum rated hourly heat input and the appropriate fuel
and boiler type NOX emission rate located in proposed Table
1b. The facility would no longer be required to keep monitoring
equipment installed on low mass emissions units, nor would it be
required to meet the quality assurance test requirements or QA/QC
program requirements of Appendix B to part 75. Moreover, emissions
reporting requirements would be reduced by requiring only that the
facility report the unit's hourly mass emissions of SO2,
CO2, and NOX, the unit's NOX emission
rate, and the fuel type burned for each hour of operation, and report
the quarterly total and year-to-date cumulative mass emissions, heat
input, and operating time, in addition to the unit's quarterly average
and year-to-date average NOX emission rate for each quarter.
Facilities would continue to be required to monitor, record, and report
opacity data for oil-fired units, as specified under Secs. 75.14(a),
75.57(f), and 75.64(a)(iii) respectively. Under Sec. 75.14(c) and (d),
however, gas-fired, diesel-fired, and dual-fuel reciprocating engine
units would continue to be exempt from opacity monitoring requirements.
If an initially qualified unit were subsequently to burn fuel other
than natural gas or fuel oil, the unit would be disqualified from using
the reduced requirements starting the first date on which the fuel
(other than natural gas or fuel oil) was burned.
In addition, if an initially qualified unit were to subsequently
exceed the 25-ton cutoff for either SO2 or NOX
while using the proposed methodology, the facility would no longer be
allowed to use the reduced requirements in proposed Sec. 75.19(c) for
determining the affected unit's heat input, NOX emission
rate, or SO2, CO2, and NOX mass
emissions. Proposed Sec. 75.19(b) would allow the facility two quarters
from the end of the quarter in which the exceedance of the relevant 25-
ton cutoff(s) occurred to install, certify, and report SO2,
CO2, and NOX data from a monitoring system that
meets the requirements of Secs. 75.11, 75.12, and 75.13, respectively.
Rationale
In addressing concerns from utilities about the cost of monitoring,
quality assurance testing, and reporting emissions from low-emitting
sources, EPA considered how to establish reduced requirements.
Utilities have indicated to EPA that it would be more helpful for the
Agency to reduce testing requirements for monitoring equipment than it
would be to reduce only reporting requirements (see Docket A-97-35,
Item II-E-25). The Agency considered whether a reduction in monitoring
or reporting requirements might have unintended adverse consequences
for the environment. In order to minimize this possibility, but still
make the program more cost
[[Page 28037]]
effective for facilities, the Agency is proposing to allow an exception
from full monitoring and reporting requirements for low mass emitting
units. In proposing these reduced requirements, the Agency is
exercising its discretion to allow de minimis exceptions from statutory
requirements in administering the Clean Air Act (see, e.g., Alabama
Power Co. v. Costle, 636 F.2d 323, 360-61 (D.C. Cir. 1979); and 58 FR
3593-94 and 3645-46). The Agency, in exercising its discretion,
believes that in light of the de minimis aggregate amount of emissions
from low-emitting units as a group, little or no environmental benefit
would be derived from continuing to require the additional accuracy of
monitoring data from low-emitting units under the existing regulations,
if such units are subjected instead to the proposed optional
requirements. EPA also notes that any such benefit would be greatly
outweighed by the cost of providing the more accurate data.
In drafting today's proposal, the Agency considered six relevant
questions: (1) What parameters should the applicability criteria be
based on? (2) How should estimated emissions be calculated? (3) What
cutoff emission level should be used to determine applicability of the
reduced requirements? (4) What should the on-going applicability
requirements be? (5) What should the reduced monitoring and quality
assurance requirements be for these units? and (6) What should the
recordkeeping and reporting requirements be for these units?
1. Applicability Criteria
The Agency believes that the initial criteria for a unit to qualify
for the excepted monitoring should be consistent with the on-going
criteria for using such monitoring so that only units that can likely
continue to use the methodology will qualify in the first place. With
the reduced monitoring requirements under this exception, a unit will
not need to install monitors. Consequently, the Agency believes that
the on-going applicability criteria should not depend on measurements
from emissions monitoring equipment and that actual emissions data or
actual heat input data, which are measured by the monitoring equipment,
would not be appropriate as the primary applicability criteria for
initial qualification for the exception or as the criteria for on-going
qualification.
The Agency considered what criteria, other than actual
measurements, should be used as a basis for determining applicability
to use the reduced monitoring and reporting exception. EPA considered
various parameters to use in the applicability criteria, including:
estimated emissions or heat input, the fuel burned, the unit capacity
factor, and annual generation measured in MW-hr. Because the Agency's
objectives for the exception include ensuring that the total emissions
from the group of units that would qualify under the exception are de
minimis and allowing more cost effective monitoring for units in such a
group, the Agency believes it would be preferable to base the
applicability on estimated emissions. While it may be simpler to base
qualification for reduced monitoring solely on the fuel burned, the
unit capacity factor, or the annual generation than to estimate the
emissions, the Agency believes that it would be more difficult under
that approach to ensure that total emissions that qualify under the
exception were de minimis. The Agency further believes that using any
of the other parameters, while attempting to ensure that the total
emissions from the group are de minimis, might exclude some units that
actually have low emissions. For example, a unit that burns mostly
natural gas with emergency oil would be excluded from an exception
limited to units that burn only natural gas. The Agency believes that
an applicability criteria based on emissions would relate more directly
to the objectives behind the optional exception than would other
operating factors that might serve as a proxy for emissions.
2. Method for Determining Emissions
The Agency considered several methods for determining the estimated
emissions as the basis for applicability of the reduced monitoring and
reporting excepted methodology. For each of the methods considered,
rather than using actual measured sulfur and carbon values,
CO2, SO2, and flow CEM readings, NOX
CEM readings, or NOX values from an Appendix E
NOX-versus-heat input correlation, a facility would
calculate the unit's emissions based on an emission rate factor and
default heat input. Since the units that would qualify for the excepted
methodology would still be accountable for reporting emissions to the
Agency and surrendering allowances based on those emissions, where
applicable, the emissions estimations would not just be used to
determine if the unit qualifies under the exception; the reported
estimations would also be used to determine compliance. The Agency
considered its goals for emissions accounting in order to establish the
emission rate factors and default heat input. The Agency maintains that
it would be inappropriate to select values that would potentially
underestimate emissions, thereby undermining the Agency's ability to
determine compliance and achieve emission reductions under title IV or
any other regulatory program involving SO2, CO2,
or NOX. Some industry representatives suggested that
facilities would be willing to use a conservative emission estimate,
such as a maximum potential emission rate times the maximum heat input,
if it would allow them to save time and money currently spent on
monitoring and quality assurance (see Docket A-97-35, Items II-D-30,
II-D-43, II-D-45, II-E-13, and II-E-25).
The Agency explored basing the estimated emissions on a unit's
maximum potential emissions, i.e., converting the unit's nameplate
capacity (which assumes maximum possible operation) to a maximum annual
heat input for the unit and multiplying by the unit's maximum emission
rate (which assumes the highest emission rate of all fuels capable of
being burned at the unit). This option would have several advantages.
It would ensure that emissions are not underestimated, would allow for
reduced monitoring requirements, and would ensure that a unit that
initially qualifies for the exception would continue to qualify without
having to reevaluate the unit's emissions each year (unless some
modification was made to the unit to increase its nameplate capacity or
allow a higher emitting fuel to be burned). This approach, however,
would likely disqualify gas-fired units that sometimes burn oil or
peaking units that operate infrequently, since maximum potential
emissions would be substantially higher than their actual emissions and
would likely exceed the applicability criteria limit. Using this method
to estimate emissions for purposes of an applicability cutoff would
greatly diminish the usefulness of the reduced requirements and would
fail to fully meet the intended purpose of today's proposal.
In place of using a heat input derived from maximum possible
operation (i.e., nameplate capacity), the Agency considered estimating
heat input by multiplying the actual operating hours times a maximum
rated hourly heat input for the unit. While this would require re-
evaluation of a unit's eligibility each year, this would allow an
infrequently operated peaking unit to qualify if its emissions are low,
which EPA believes is worth the additional burden of annual re-
evaluation. Therefore, the Agency is proposing to use maximum rated
hourly heat input as the heat input in the emissions
[[Page 28038]]
estimation. Maximum rated hourly heat input would be defined, in
Sec. 72.2, as a unit-specific maximum hourly heat input (mmBtu) based
on the manufacturer's rating of the unit or, if that value has been
exceeded in practice, based on the highest observed hourly heat input.
In addition, there would be provisions for a lower maximum hourly heat
input to be used if the unit has undergone modifications which
permanently limit its capacity.
The Agency also considered what emission rate(s) to apply, instead
of using the highest emission rate of all fuels capable of being burned
at the unit, in order to avoid underestimation and to allow a unit that
primarily burns gas but has the ability to burn oil to qualify for the
reduced requirements. The Agency believes that it would be appropriate
to use emission rates based on uncontrolled emissions for the actual
fuel burned in any given hour to estimate emissions for purposes of the
initial and on-going applicability cutoffs to qualify to use the low
mass emissions excepted methodology and for purposes of emissions
reporting, allowance accounting, and compliance. This approach would
avoid disqualifying gas-fired units simply because of their occasional
use of oil and would also avoid underestimating emissions.
For determining SO2 mass emissions using the low mass
emissions methodology, EPA proposes the use of emission factors in lb/
mmBtu based on its AP-42 air pollution emission rate factors, which are
established from the sulfur content and gross calorific value of the
fuel being burned (see Docket A-97-35, Items II-A-11, II-I-1). Since
the SO2 emissions are directly proportional to the amount of
sulfur in the fuel and in light of the limited variability in the
sulfur content of natural gas and oil, the proposed SO2 mass
emission factors should be fairly representative of uncontrolled,
actual emissions. Because of the relatively low sulfur content of
natural gas or oil, it is doubtful that any of such units have
SO2 controls. The proposed factors fall within the typical
range of sulfur content and gross calorific value for each fuel,
although somewhat on the conservative side for sulfur content of diesel
fuel and natural gas other than pipeline natural gas.
For determining NOX mass emissions and emission rate,
EPA proposes using the fuel- and unit-type-specific NOX
emission rate factors based on 90th percentile emission rate data
reported under part 75 generally for uncontrolled units (see Docket A-
97-35, Item II-A-9). While attempting to develop an accounting approach
for NOX emissions from low mass emission units, EPA
encountered several issues. The first issue involves the use of AP-42
factors. During the finalization of the core part 75 monitoring rule,
EPA considered allowing peaking units with negligible emissions both
individually and collectively to estimate NOX emissions
using AP-42 emission rate factors. EPA rejected this approach in the
January 11, 1993 final rule preamble at 58 FR 3644-45 because the AP-42
emission rate factors are derived from industry-wide average estimates
of emissions for different fuel and boiler types and are not based on
actual historical operating experience of the units to which the
estimates would be applied. Applying AP-42 factors could result in
underestimation of NOX emissions because actual
NOX emissions can vary significantly from unit to unit. The
formation of NOX from the combustion of fossil fuels is
dependent on the amount of nitrogen in the fuel being combusted and on
the mix of nitrogen and oxygen in combustion air. Further, the
NOX formation process depends on unit-specific factors of
combustion gas temperature and stoichiometry of fuel and air local to
the flame. Consequently, there can be significant variations in the
level of NOX emissions from unit to unit due to variations
in combustion conditions. Therefore, EPA is not proposing the use of
AP-42 factors to estimate NOX emissions from low mass
emissions units. Instead, now that three years of actual historical
operating data collected under part 75 are available, it was possible
to develop the default NOX emission rate factors being
proposed today. Although the default NOX emission rate
factors in today's proposal are generic factors, they should not
underestimate NOX emissions because they are based on the
90th percentile of actual annual average emission rates reported
generally from uncontrolled units under part 75.
The Agency also considered using site-specific NOX
emission rate factors based on historical emission data or emissions
testing data for the unit. For example, a facility might use the
maximum value ever recorded by the CEM for the unit, or it might use
the highest NOX emission rate value calculated from the
unit's most recent Appendix E NOX test, or it might use
site-specific values similar to those discussed in the guidance manual
for implementing the NOX budget program in the OTR (see
Docket A-97-35, Item II-I-7). The application of site-specific
NOX emission factors for low mass emission units raises
several issues. First, for units with pollution controls where the
emission factor is based on controlled emissions, the site-specific
emission factor could underestimate actual emissions if the controls
are not operating properly. EPA considered only allowing site-specific
NOX emission factors with units that do not utilize
NOX emission controls; however, EPA realizes that many units
employ at least some form of NOX emission controls (e.g.,
water or steam injection). EPA also considered allowing a source with
controls to use a site-specific emission factor only if it could
demonstrate that the pollution controls are operating properly.
However, this would involve extensive, additional recordkeeping and
tracking to verify the proper operation of pollution controls and
ensure that emissions are not underestimated; this would run contrary
to the general approach under the exception of reducing monitoring and
reporting requirements. A second issue involves verifying that the
site-specific NOX emission factor is still representative
over time or after unit modifications. This would require future
NOX emission rate testing. Therefore, for purposes of
creating a methodology that is simple to implement and in order to
reduce future testing requirements for facilities with low mass
emitting units, the Agency proposes instead using NOX
emission rate factors based on fuel and unit type and reflecting
uncontrolled emissions. EPA requests comments on this approach, whether
other approaches should be used, and especially whether there are any
additional boiler types not represented in today's proposed rule for
which NOX emission rates should be provided.
For determining CO2 mass emissions, today's rule
proposes to use CO2 emission rate factors in tons/mmBtu. The
CO2 emission rate factors are derived based on ideal gas
theory and standard Agency Fc factors for estimating the
volume of CO2 to be emitted when a certain heat input of a
particular fuel is burned (see Docket A-97-35, Item II-A-11). This
resembles the approach currently used in Equation G-4 of Appendix G for
gas-fired units.
Therefore, the Agency believes that an appropriate method of
estimating emissions for the purposes of qualifying for a reduced
monitoring and reporting exception and for purposes of emissions
accounting and compliance for units under the exception is to calculate
emissions based on the actual number of operating hours and the actual
fuel burned using maximum rated hourly heat input and fuel-based and,
for NOX unit-type-based, emission factors. The Agency
requests comments on this approach and on whether an alternate
[[Page 28039]]
approach should be used. While the Agency believes that the resulting
emissions estimates will in most, if not all, cases be conservative and
result in an overestimation of emissions, it would be possible, however
unlikely, that the estimate could underestimate the actual emissions
for some types of units. Therefore, for existing units with historical
emissions data available, the proposal would require that in addition
to meeting the applicability criteria using the emissions estimates
calculated as described above, the unit would have to meet the cutoffs
for initial qualification for the exception using the actual annual
emissions monitored during the three years prior to applying to use the
exception.
3. Cutoff Limit for Applicability
EPA began developing applicability criteria by first considering
the level of projected aggregate emissions determined to be de minimis
for purposes of developing the new unit exemption promulgated in the
January 11, 1993 Acid Rain permitting rule (see 58 FR 3593-94 and 3645-
46). Aggregate emissions projected for units under the exemption were
approximately 138 cumulative tons of SO2 and 1934 cumulative
tons of NOX emitted per year. The Agency then conducted a
study of actual emissions data from 1996 quarterly reports under part
75 and evaluated potential tonnage cutoffs for SO2 and
NOX. The Agency compared the cumulative mass emissions from
groups of units emitting less than various specified amounts to the
total emissions reported under the Acid Rain program during the year
(see Docket A-97-35, Item II-A-10). For example, the study shows what
proportion of total SO2 was emitted by units with both
actual and potential 1 emissions of 25 tons or less per
year, 50 tons or less per year, 60 tons or less per year, and 75 tons
or less per year. From these analyses, EPA also estimated how many
units might be eligible for reduced requirements for determining
emissions and how much of an impact the new emissions accounting option
would have on nationwide emissions accounting.
---------------------------------------------------------------------------
\1\ The terms ``potential emissions'' used in this section of
the preamble have a different meaning than the terms ``potential to
emit'' used elsewhere by the Agency.
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EPA is proposing cutoff values of 25 tons per year of
SO2 and 25 tons per year of NOX. In order to
qualify as a low mass emissions unit, a unit would have to demonstrate
that both actual historical emissions and potential emissions
(calculated with maximum hourly heat input, emission factors and
either, for existing units, actual historical number of operating hours
or, for new units, projections of future annual operating hours) do not
exceed 25 tons each for SO2 and NOX on an annual
basis. Based upon its analyses (see Docket A-97-35, Item II-A-10), EPA
estimates that this tonnage cutoff level would mean that the group of
units subject to the proposed reduced requirements, even after Acid
Rain Program emission reductions are considered, would have total
annual emissions of about 16 tons of SO2 and 90 tons of
NOX (less than a thousandth of a percent of total annual
SO2 emissions and about 0.002 percent of total annual
NOX emissions for all affected units). Both amounts, 16 tons
of SO2 and 90 tons of NOX, are less than the
total number of tons of those pollutants determined to be de minimis
for purposes of the new unit exemption. Today's proposal to treat low
mass emission units as de minimis is consistent with the de minimis
conclusions reached for new units.
While the reduced requirements are somewhat less accurate than the
methodologies under the existing regulations, the reduced requirements
are intended to yield emissions data that are conservative and that, to
the extent they are inaccurate, are likely to overstate emissions.
Moreover, EPA believes that the level of inaccuracy (i.e.,
overstatement of emissions) would similarly be extremely low (i.e.,
less than a thousandth of a percent). Both the total emissions subject
to the reduced requirements and the potential amount of overstatement
of emissions are de minimis. Moreover, any overstatement of regulated
emissions would have the effect of tightening emission limits (e.g., by
requiring surrender of more allowances for SO2 than
otherwise). Any overstatement of other emissions would be too small to
affect adversely the air quality related activities (e.g., air quality
modeling) for which the emissions data would be used.
EPA would, however, be concerned about extending today's proposed
reductions in monitoring, quality assurance, and reporting requirements
to units that exceed the 25-ton cutoffs for actual or potential
emissions. Section 412 of the CAA requires all affected units to
monitor SO2, volumetric flow, NOX, and opacity
using continuous emission monitoring systems or an alternative
monitoring system approved by the Administrator as having the same
precision, reliability, accessibility, and timeliness. In addition,
section 412 of the Act requires that emissions data be quality-assured.
Section 821 of the Clean Air Act Amendments of 1990 provides that,
through regulations issued by the Administrator, all affected units
must be required to monitor CO2 emissions in the same manner
and to the same extent as SO2 and NOX are
monitored under section 412. Part 75 of EPA's rules requires monitoring
of SO2, NOX, and CO2 and allows
certain exceptions to the statutory requirement for CEMS or CEMS-
equivalent alternative monitoring: in Appendix D because, inter alia,
the information gathered using the Appendix D methods is as precise,
reliable, accessible, and useful as that from CEMS, and compares
acceptably with regard to timeliness; and in Appendix E because the
emissions from all units eligible to use Appendix E are negligible and
such units do not have emission limitations for NOX under
the Acid Rain Program (see 58 FR 3641-45). The proposed reduced
monitoring and reporting requirements for low mass emissions units
would not yield information equivalent to that from CEMS. EPA must
balance the benefits of reduced monitoring, quality assurance, and
reporting requirements for units against the intent of the statute that
monitoring with CEMS or their equivalent be required so as to obtain
reliable, precise, timely, and readily accessible information on
emissions. EPA solicits comment on whether 25 tons is the appropriate
cutoff level for applicability of the low mass emission excepted
methodology.
In particular, EPA is concerned that extending the proposed
reduction in requirements to units with more than this de minimis level
of emissions could have a negative impact on the environment. Emissions
data from the Acid Rain Program are being used for a variety of
efforts, including emissions modeling and establishing baseline
emissions information (prior to any emission reductions) for new air
pollution control programs. Using less accurate methods to monitor more
than a de minimis amount of emissions could potentially undermine
efforts to establish baseline emissions and to assess what emission
reductions have already taken place and how much further emissions must
be reduced in order to meet air quality standards.
Furthermore, with regard to coal-fired units, such units account
for the largest proportion of all emissions, tend to be operated more
frequently, and generally have much higher emission rates in lb/mmBtu
for SO2, NOX and CO2, and the majority
of the units have emission limitations and emission reduction
[[Page 28040]]
requirements for SO2 and NOX. In addition, the
sulfur content in coal and gaseous fuels other than natural gas is much
more variable than for natural gas and oil, and the emission factors
for coal or gaseous fuels other than natural gas, particularly an
SO2 emission factor, are therefore less reliable and much
more likely to understate, rather than overstate, emissions. Based on
these considerations, the proposed rule would restrict the use of the
reduced requirements to gas-fired units and oil-fired units that burn
natural gas and/or fuel oil.
In order to qualify for the proposed low mass emissions excepted
methodology, the proposed applicability criteria would require a unit
to meet annual tonnage cutoffs of 25 tons each for SO2 and
NOX. EPA considered whether the excepted methodology should
be available on a pollutant specific level so that, for example, a unit
which falls below the tonnage cutoff for SO2 but not for
NOX could use the proposed excepted methodology under
Sec. 75.19 to measure SO2 emissions but use a NOX
CEM or the excepted methodology under Appendix E, where applicable, to
measure NOX emissions. EPA believes this approach would not
be appropriate because some of the same monitoring equipment and
reporting software is necessary for measuring and reporting both of the
pollutants. One of the prime benefits of the low mass emissions
excepted methodology would be the simplified reporting which would
require less time and a less sophisticated Data Acquisition and
Handling System. In particular, the need for a DAHS that could
calculate substitute data using the missing data algorithms would be
removed because there are no missing data algorithms for the low mass
emissions excepted methodology. If the excepted methodology is only
applied to one of the pollutants, much of the benefit would be negated
because the DAHS would still need to be capable of calculating
substitute data for the measured pollutant and close to the full
quarterly report would still be required. Another prime benefit of the
proposed low mass emissions excepted methodology would be the removal
of monitoring and quality assurance requirements. However, EPA believes
that almost all units that would qualify for a 25-ton cutoff for only
one pollutant would meet the cutoff for SO2, not
NOX, and would already be using Appendices D and E. A unit
using a fuel flowmeter to determine SO2 mass emissions under
Appendix D likely uses the same fuel flowmeter to determine
CO2 emissions and heat input. Additionally, the same fuel
flowmeter is used to determine NOX emissions under Appendix
E. Even if the unit were allowed to use the proposed low mass emissions
excepted methodology for SO2 in lieu of Appendix D, the unit
would still have to install, certify, operate, maintain, quality
assure, and report from a fuel flowmeter to determine NOX
emission rate and heat input. Accurate heat input is important since
heat input is used to calculate NOX mass emissions. In
short, the cost of operation, maintenance, and quality assurance of the
fuel flowmeter would not be removed simply by removing the requirement
to monitor SO2. Even if a unit that qualified under the low
mass emissions excepted methodology for SO2 but not for
NOX was currently monitoring with Appendix D, for
SO2 and heat input, and using a NOX CEM, for
NOX emission rate, using the excepted methodology for
SO2 but not for NOX would have little benefit
since the installation, certification, and quality assurance testing of
the fuel flowmeter would still be required to determine heat input.
Therefore, today's proposed low mass emissions excepted methodology
would be provided as an option only if the unit has low mass emissions
of both SO2 and NOX. EPA solicits comment on this
approach and on whether any benefit of allowing the excepted
methodology for one pollutant only would outweigh the added complexity
in the excepted methodology.
EPA also considered whether a tonnage cutoff for CO2
emissions was appropriate as part of the proposed applicability
criteria for low mass emissions units. However, the proposed excepted
methodology under Sec. 75.19 would require the use of a standard
emission factor (in lb of NOX/mmBtu) for NOX to
determine eligibility for the exception. This would effectively
establish an upper limit on the annual heat input for a given fuel and
boiler type at the level that would allow the unit to meet the tonnage
cutoff applicability requirements. Because CO2 emissions are
directly proportional to heat input, there would be a built-in annual
CO2 emissions cutoff inherent in the methodology.
4. Continuing Applicability Criteria
In drafting today's proposal, EPA also considered how to ensure
that after individual units initially qualified to use the reduced
monitoring exception, they could continue to use the exception only if
they continued to have de minimis emissions. Many of the units that
would qualify as low mass emissions units under the proposal have low
emissions either because they use pipeline natural gas and/or because
they operate infrequently. In both of these situations, it is
conceivable that a unit's emissions could become significant if the
unit's fuel or hours of operation were to change. Most gas-fired units
are capable of burning oil, but generally do so only when pipeline
natural gas is not available. However, if the prices of gas and oil
were to change such that oil became far more economical than gas, some
gas-fired units might switch to burning high sulfur oil. Similarly,
increases in demand for electricity could cause some peaking units to
operate more frequently, thereby generating more emissions. Therefore,
EPA is proposing that in order to ensure that emissions from units
using the reduced requirements would remain de minimis, units would
have to continue to meet the applicability criteria in order to qualify
as low mass emissions units. Because of the conservative heat input and
in some cases, conservative emission factors, the Agency believes that
meeting the applicability criteria of less than 25 tons of both
SO2 and NOX when calculating the emissions using
the low mass emissions excepted methodology, will ensure that the
actual emissions of the low mass emission units will be below those
levels. Therefore, once the methodology is implemented, the on-going
applicability would only require that the limits be met with the
calculated mass emissions, i.e., the facilities would be required to
continue to meet the 25-ton cutoffs on an annual basis, as determined
using the emission calculation procedures in proposed Sec. 75.19.
It would, therefore, be necessary for low mass emissions units to
report NOX mass emissions, in addition to the required
SO2 mass emissions and NOX emission rate, in
order to determine continuing applicability. A continuing applicability
provision of this nature would prevent a unit from continuing to use
the reduced requirements when its emissions were no longer negligible.
If a unit initially met the applicability criteria but failed to meet
one or both of the annual 25-ton cutoffs in a future year, the unit
would become disqualified from using the exception. Sufficient time
would be necessary to purchase, install, and certify CEMS or the
equipment necessary for monitoring under Appendices D and/or E.
Therefore, a unit would not be disqualified until two calendar quarters
after the quarter in which the 25-ton cutoff is exceeded and would not
be required to certify and report from
[[Page 28041]]
monitoring systems until then. If that unit changes, or is projected to
change, its fuel or amount of operation in the future so that it would
again meet the 25-ton SO2 and NOX cutoffs, the
unit could again qualify as a low mass emissions unit. However, if the
unit initially qualified based on projected operating hours and fuel
usage and then was disqualified the unit could not use projected data
to qualify again. The unit would need to monitor using CEMS, an
approved alternative monitoring system, or an optional protocol under
Appendices D and/or E, where applicable, for at least an additional
three years in order to accumulate three years of actual data.
5. Reduced Monitoring and Quality Assurance Requirements
As discussed above, today's proposed rule would allow facilities to
use a maximum rated hourly heat input value and an emission rate factor
to determine the mass emissions from a low-emitting unit for each hour
of actual operation. This approach would involve no actual emissions
monitoring and no quality assurance activities. Instead, the facility
would only need to keep track of whether the unit combusted any fuel
for a particular hour and what type of fuel was combusted. In this way,
the proposed revisions would significantly reduce the burden on
affected facilities, while still ensuring that emissions are not
underreported.
6. Reduced Reporting Requirements
Some utilities have mentioned that they find it troublesome to
spend as much time or more reviewing quarterly report submissions for
small, infrequently operating gas-fired units as they spend reviewing
quarterly report submissions for large coal-fired units (see Docket A-
97-35, Items II-D-75, II-E-25). EPA agrees that facility environmental
personnel should be able to spend a greater percentage of their time
focusing on units with higher emissions than on low mass emissions
units, which, as discussed above, account for such a small portion of
total emissions. Thus, today's proposed rule would simplify the
reporting requirements for low-emitting units so that facilities could
spend less of their environmental department resources on units with
negligible emissions. For units that rely on the procedures in proposed
Sec. 75.19(c), the owner or operator would have no requirements related
to records or reports of certification testing and would be exempt from
all of the specific recordkeeping requirements in Secs. 75.54(b)
through (e) or 75.57(b) through (e) relating to operating parameter and
emissions records. Instead, the rule would require only that an initial
certification application, containing data supporting the applicability
demonstration, and a monitoring plan be submitted and that limited
hourly, quarterly, and year-to-date cumulative data be reported on a
quarterly basis. The hourly record would only be reported for hours of
unit operation, and an hour in which the unit combusted fuel for any
portion of the hour would be considered a full hour, for simplicity.
One utility has suggested that it would be less burdensome if it
could simply report its quarterly cumulative emissions, without
reporting any supporting hourly data; other utility representatives
have indicated that it would be no more burdensome to report an hourly
default emission value if the utility were already reporting hourly
operating information (see Docket A-97-35, Item II-E-25). For purposes
of modeling air quality, the Agency considers hourly operating
information far more valuable (e.g., for modeling discrete periods of
ozone exceedance) than just a quarterly emission value with no time or
date mentioned. Furthermore, because facilities already keep track of
the operation of their units for business purposes, keeping track of
and reporting hourly operating information should not be a substantial
burden. According to industry representatives, however, allowing
facilities to record and report default emission values instead of
hourly measured values would significantly speed up their review of
quarterly reports prior to submission to the Agency (see Docket A-97-
35, Item II-E-25). Thus, requiring facilities to report hourly
operational data and the default emissions data for the fuel burned
that hour, but not hourly measured emissions or heat input in
additional record types, would preserve the Agency's ability to model
air quality while imposing far less burden upon facilities than the
current part 75 requirements. Furthermore, because hourly default
values would be employed, the need for missing data procedures would be
eliminated and the Data Acquisition and Handling System (DAHS) could be
greatly simplified. In fact, the reporting requirements for a low mass
emissions unit could most likely be fulfilled with the use of a
commercially available spreadsheet software package. EPA has
incorporated this approach into today's proposed rule.
D. Quality Assurance Requirements for Moisture Monitoring Systems
Background
Section 75.11(b) of the original 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 (see
Secs. 75.13(c), 75.16(e), and Equations F-14b, F-16, F-17 and F-18 in
Appendix F) or when determining NOX emission rate in lb/
mmBtu (see section 3.2 in Appendix F, and Equations 19-3 through 19-5,
19-8, and 19-9 in Method 19 of Appendix A to part 60).
As presently codified, part 75 does not specify any quality
assurance requirements for moisture measurement devices. Implementation
has shown this to be an unfortunate omission in the rule, since
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. The Agency does not know the
extent of inaccuracy that currently exists in the measurement of
moisture by affected units but believes it is important to require
certification and quality assurance of moisture monitors--just as is
required for other CEMS used under part 75--because the success of the
SO2 trading system depends on accurate monitoring.
[[Page 28042]]
Discussion of Proposed Changes
Today's proposal would incorporate into part 75 quality assurance
requirements for moisture monitoring systems. Section 75.11(b) would be
revised to require the owner or operator to install, maintain, operate,
and quality assure a moisture monitoring system. Proposed Sec. 75.11(b)
also specifies that a moisture monitoring system may either consist of:
(1) a continuous moisture sensor; (2) an oxygen 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 DAHS component capable of determining moisture from a lookup
table, i.e., a psychrometric chart (this third option would apply only
to saturated gas streams following wet scrubbers). Corresponding
changes would be made to Secs. 75.12, 75.13(c) and 75.16(e) to require
that a quality assured moisture monitoring system be used whenever
moisture corrections are needed to accurately account for
NOX emissions, CO2 emissions, or heat input.
Requirements for the initial certification of moisture monitoring
systems are proposed in three new sections, Secs. 75.20(c)(5), (c)(6),
and (c)(7). To make room for the new sections, existing
Sec. 75.20(c)(3) would be deleted; existing Secs. 75.20(c)(4) and
(c)(5) would be redesignated as Secs. 75.20(c)(3) and (c)(4); and
existing Secs. 75.20(c)(6), (c)(7), and (c)(8) would be redesignated,
respectively, as Secs. 75.20(c)(8), (c)(9), and (c)(10). The
certification requirements for continuous moisture sensors are found in
proposed Sec. 75.20(c)(6) and include a 7-day calibration error test
and a relative accuracy test audit (RATA). For moisture monitoring
systems consisting of one or more wet- and dry-basis oxygen analyzers,
the proposed certification requirements are found in Sec. 75.20(c)(5)
and include 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. Corresponding revisions to
Sec. 75.22(a)(4) are proposed, specifying that EPA Method 4 (either the
standard procedure or the midget impinger procedure) would be used as
the reference method for the moisture RATAs. For saturated gas streams,
if a lookup table is used to determine the hourly stack gas moisture
content, the certification requirement in proposed Sec. 75.20(c)(7)
would consist of a DAHS verification. At a minimum, the DAHS
verification would have to demonstrate, at three temperatures covering
the normal range of stack temperatures, that the software extracts the
proper moisture value from the lookup table and applies it correctly to
the emission calculations. In today's proposal, a new Sec. 75.4(i)
would also be added, requiring owners or operators to complete all of
the applicable moisture monitoring system certification tests specified
in proposed Secs. 75.20(c)(5), (c)(6), and (c)(7) no later than January
1, 2000.
Proposed performance specifications for moisture monitoring systems
are found in sections 3.1, 3.2, 3.3, and 3.5 of Appendix A to part 75.
These specifications would apply to continuous moisture sensors and to
wet- and dry-basis oxygen analyzers. The proposed calibration error
specification in section 3.1 for continuous moisture sensors is 3.0
percent of span. A new section, 2.1.5, would be added to Appendix A,
defining the span of a moisture sensor as equal to the full-scale range
of the instrument and requiring that the range be consistent with
section 2.1 of Appendix A. 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 in sections 2.1.3, 3.1, 3.2, and 3.5 of Appendix A would be
the same as the current specifications for O2 monitors. The
proposed relative accuracy (RA) specification for moisture monitoring
systems is found in a new section, 3.3.6, in Appendix A and would be
equal to 10.0 percent. An alternative RA specification would also be
provided in section 3.3.6, i.e., the relative accuracy would also be
acceptable if the difference between the mean difference of the
reference method measurements and the moisture monitoring system
measurements is within 1.0 percent H2O. A
relative accuracy specification of 10.0 percent is being proposed in
order to maintain consistency with the relative accuracy requirements
for the other program monitors (SO2, NOX, flow
rate, and CO2). The Agency notes that moisture RATAs have
not previously been required by any other EPA continuous monitoring
regulation, and therefore there is no relative accuracy database upon
which to draw. However, moisture data are sometimes collected using EPA
Method 4 during each run of a part 75 gas monitor RATA to convert the
gas reference method readings from a dry basis to a wet basis.
Therefore, some part 75 sources that currently account for moisture
using wet- and dry-basis oxygen analyzers or a moisture sensor should
be able to construct moisture RATAs from previous test data by
comparing the Method 4 moisture data from the gas monitor RATAs against
the readings recorded by the moisture sensor or O2 analyzers
at the time of the gas RATAs. EPA encourages those facilities that
currently make moisture corrections in their emission equations to
perform this type of data analysis, if possible, and to provide comment
on the appropriateness of the proposed moisture relative accuracy
specification.
On-going QA requirements for moisture monitoring systems are also
proposed in sections 2.1.1, 2.1.4, 2.2.1, 2.3.1.1, and 2.3.1.2 of
Appendix B to part 75. Proposed section 2.1.1 of Appendix B would
require daily calibrations of moisture monitoring systems. Continuous
moisture sensors would be calibrated in accordance with the
manufacturers' recommended procedures. Proposed section 2.1.4 would
give control limits for the daily calibrations (i.e., 1.0
percent O2 for oxygen analyzers and 6.0 percent
of span for continuous moisture sensors). Proposed section 2.2.1 would
require quarterly linearity checks of wet- and dry-basis oxygen
analyzer(s). Proposed section 2.3.1.1 would require semiannual RATAs of
moisture monitoring systems, and proposed section 2.3.1.2 would specify
that if a moisture monitoring system achieves a relative accuracy of
7.5 percent or if the mean difference between the CEMS and
reference method values is within 0.7 percent
H2O, the system qualifies for an annual, rather than
semiannual RATA frequency.
Missing data procedures for moisture are included in today's
proposal in a new section, Sec. 75.37. The proposed missing moisture
data procedures are as follows:
(1) Begin by using the following ``initial'' missing data
procedures as of the date and time of provisional certification of the
moisture monitoring system or as of January 1, 2000 (whichever is
earlier). Substitute 0.0 percent moisture for each hour of missing data
if no prior quality assured data exist, and for the first 720 hours of
quality assured monitor operating data, substitute, for each hour of
each missing data period, the average of the ``hour before'' and ``hour
after'' moisture values.
(2) After 720 hours of quality assured data have been obtained,
provided that the moisture data availability is 90.0
percent, substitute the average of the ``hour before'' and ``hour
after'' values for each hour of the missing data period.
(3) When the percent data availability for moisture is below 90.0
percent, substitute 0.0 percent moisture for each hour of the missing
data period.
[[Page 28043]]
These proposed missing data procedures are considerably simpler
than the corresponding procedures for SO2, NOX,
CO2, and flow rate, in that they do not include the concepts
of lookback periods, 90th, or 95th percentile values. However, the
procedures are also somewhat less representative than the missing data
procedures for SO2, NOX, CO2, and flow
rate, because the most conservative possible value (0.0 percent
moisture) is substituted when the moisture monitor data availability
drops below 90.0 percent. The Agency solicits comment on whether the
simpler (but less accurate) missing data procedures or the more complex
(but more representative) procedures are more appropriate.
Finally, Secs. 75.57(c) and 75.59(a) (revised versions of
Secs. 75.54(c) and 75.56(a)) would be added in today's proposal to
require that records be kept of the following: (1) Component-system
identification code for the moisture monitoring system; (2) hourly
average moisture readings (including, if applicable, hourly averages
from each wet- and dry-basis O2 analyzer); (3) percent data
availability for the moisture monitoring system; (4) daily and 7-day
calibrations of moisture monitoring systems; (5) linearity tests of
each wet and dry oxygen analyzer used to determine moisture; and (6)
relative accuracy tests of moisture monitoring systems.
In summary, EPA is proposing quality assurance (QA) procedures for
moisture monitoring systems because the Agency believes that
continuous, quality assured, direct measurement of the stack gas
moisture content or continuous measurement of surrogate parameters,
such as wet- and dry-basis oxygen concentrations, is the best way to
ensure the accuracy of the reported emission data when moisture
corrections must be applied. However, the Agency is willing to consider
and solicits comment on simpler alternative methods of accounting for
the stack gas moisture content, such as using a conservative default
moisture value. Any proposed alternative methodology submitted to the
Agency for consideration would have to provide a comparable level of
accuracy and would have to ensure that emissions and heat input are not
under-reported.
E. Certification/Recertification Procedural Changes
Background
Currently, Sec. 75.20 lays out the process for certifying
monitoring systems. Section 75.20(a) specifies the requirements for
initial certification, including the contents of a certification
application, when the application must be submitted and the process for
reviewing and acting on an application. Sections 75.20(a)(3) and (4) of
the existing rule establish a certification application review period
of 120 days (after receipt of a complete application) for EPA to review
an application and issue an approval or disapproval. For a continuous
emission monitor (CEM), initial certification includes the following
tests: relative accuracy, bias, linearity (pollutant monitors only), 7-
day calibration error, cycle response time (pollutant monitors only),
missing data, and formula verification. All of these tests must be
passed for a CEM to be certified and produce valid quality assured
data. Once a CEMS is certified, Sec. 75.20(b) specifies that if
something changes that significantly affects the ability of the CEM to
accurately measure concentration or volumetric flow, the affected
monitoring system(s) must be recertified. Recertification includes one
or more of the initial certification tests. All required
recertification tests must be passed, and a recertification application
must be submitted in order for a CEM to be recertified. Section
75.20(b)(5) of the existing rule establishes a 60 day review period for
recertification applications. Separate but similar certification and
recertification test requirements apply for a monitoring system other
than a CEM, i.e., an excepted monitoring system under Appendix D or E,
an alternative monitoring system under subpart E, or a system under
proposed Appendix I.
Submittal requirements for certification and recertification
applications are included in Secs. 75.60 and 75.63 of the current part
75. Generally, these provisions require submittal of certification test
results in electronic formats, with some information required to be
submitted in hardcopy format. Certification or recertification test
results also must be submitted electronically in quarterly reports
under Sec. 75.64. Finally, Sec. 75.61 requires the designated
representative to provide advance notice to the applicable state or
local agency and EPA Regional Office of certification and
recertification testing.
In many respects, monitoring plan requirements are tied to the
certification/recertification process because a modification to the
monitoring system that requires a recertification application also
usually requires a monitoring plan update. In addition, because it
contains the information about what type of equipment is located where,
the monitoring plan is an essential tool in the review of a
certification or recertification application. Section 75.53 specifies
the content of monitoring plans and when changes to the plan are
required. Section 75.62(a) specifies the submission requirements for
monitoring plans.
Based on EPA's initial experience with part 75 implementation and
the numerous questions and problems encountered in the review of
certification and recertification applications and monitoring plans,
the Agency believes that the certification and recertification
provisions and the related sections of the rule are possibly neither
sufficiently detailed nor clear. Therefore, in today's rulemaking, EPA
is proposing to revise those provisions and sections in order to
improve the certification/recertification process. The issues addressed
in today's proposed rule include the following: (1) whether a
particular provision applies to initial certification, recertification,
or both; (2) the scope of events that require submittal of a
recertification application; (3) the review period lengths for initial
certification and recertification applications; (4) the criteria
governing disapproval of an incomplete certification or recertification
application; (5) the format (electronic or hardcopy) in which test
notifications, certification and recertification applications, and
monitoring plans are to be submitted; (6) which EPA Regional Offices
and state and local agency offices must receive test notifications,
certification and recertification applications, and monitoring plans,
and whether the submittal and notice requirements can be waived; and
(7) when a monitoring plan needs to be revised. The proposed revisions
on these topics and the rationale for the changes are discussed below.
The Agency notes that today's package of proposed revisions to part
75 includes other substantive revisions to the certification and
recertification provisions in part 75. These are discussed elsewhere in
this preamble. The provisions of most significance are related to
certain proposed QA/QC revisions, back-up monitoring systems, CEM data
validation issues, and the new Appendix I procedures. See sections
III.D, O, R and T of this preamble for further discussion.
Discussion of Proposed Changes
The proposed revisions discussed in this section affect Sec. 75.20
generally, as well as specific aspects of Secs. 75.20(a)(4), (b)(1),
(b)(5), and (g)(6); 75.21(e)(1); 75.53(b); new Sec. 75.53(e) and (f);
75.60(b); 75.61(a); 75.62(a); 75.63(a) and
[[Page 28044]]
(b); 75.64(a), (b) and (d) and the addition of Sec. 75.59 as a revised
version of Sec. 75.56. Proposed revisions to Sec. 75.20 would clarify
which provisions apply to initial certification, recertification, or
both. Proposed revisions to Sec. 75.20(b)(1) and (g)(6) would provide a
narrow definition of recertification events, thereby significantly
reducing the number of monitoring system changes, configuration changes
or changes in the manner of operation that would require submission of
a recertification application. Proposed revisions to Sec. 75.20(b)(5)
would make the lengths of the review periods the same for initial
certification and recertification applications. Proposed revisions to
Sec. 75.20(a)(4) would clarify what constitutes a complete
certification or recertification application and also would more
clearly define EPA's authority to disapprove an incomplete application.
Proposed revisions to Sec. 75.53(b) would expand the universe of
monitoring system changes that require monitoring plan revisions to
include any change that would make the information in the current plan
inaccurate (currently, only changes that require recertification
require monitoring plan changes). Sections 75.53(e) and (f), which are
revised versions of existing Sec. 75.53(c) and (d), would clarify which
elements of a monitoring plan must be submitted in electronic format
and which elements must be submitted in hardcopy format. Section
75.53(e) would revise existing Sec. 75.53(c) so that after January 1,
2000 an owner or operator would have to report the unit stack height in
the monitoring plan. Section 75.59 (a revised version of Sec. 75.56)
would specify the minimum required content (as of January 1, 2000) for
the hardcopy portion of a certification or recertification application.
Section 75.60(b) would more clearly define the general requirements for
submittal of reports and petitions. Section 75.61(a) would allow for
certification and recertification test notices to be sent in various
alternative media and would allow for EPA or a State or local agency to
waive test notices in some circumstances. Section 75.62(a) would be
revised to clarify when monitoring plans are to be submitted and to
whom elements of the monitoring plan must be submitted. Similarly,
Sec. 75.63(a) would be revised to detail which elements of a
certification or recertification application are to be submitted
electronically, which elements are to be submitted in hard copy, and to
whom the various elements would be submitted. Section 75.63(b) would
clarify when and how failed tests are to be reported in a certification
or recertification application. Finally, Sec. 75.64(a) would specify
that the hardcopy monitoring plan is not to be submitted with a
quarterly report. The rationale for these changes is discussed below.
Rationale
1. Initial Certification Versus Recertification
Several provisions in the current rule refer either to
certifications or to certification applications; however, it is not
always clear whether these provisions apply solely to initial
certifications or whether they also apply to recertifications.
Therefore, today's proposed revisions would make a number of minor text
edits throughout Sec. 75.20 for clarification. There are, however, some
events that do not fit neatly under the definition of initial
certification or recertification (e.g., construction of a new stack
with a new CEM at an existing unit when a scrubber is installed). This
element of subjectivity in classifying an event as a certification or
recertification makes it desirable for the certification and
recertification processes to be as similar as possible. Having one
general process with one set of rules rather than having two separate
processes also makes program implementation easier. Currently, the main
differences between initial certifications and recertifications are the
types of tests required and the lengths of the application review
periods. Today's proposed rule revisions would attempt to minimize
these differences to the extent possible in order to bring greater
uniformity and consistency to the certification and recertification
process.
(a) Scope of Recertification Events. The proposed revisions would
narrow the scope of the types of changes to a monitoring system that
would be classified as ``recertification events'' and would require
submittal of a recertification application. Sections 75.20(b)(1) and
(g)(6) would define a recertification event as any change that requires
the performance of an accuracy test of a monitoring system, i.e.,
either a relative accuracy test audit (RATA) of a CEMS, an accuracy
test of a fuel flowmeter, or a retest to develop the Appendix E
NOX correlation curve. For changes to a monitoring system or
process that do not require a system accuracy test but require one or
more of the other (lesser) quality assurance tests to be performed
(e.g., linearity test or 7-day calibration error test), those other
required tests would be classified as diagnostic tests rather than as
recertification tests in Sec. 75.20(b)(1) of the proposal. For
instance, a source would be required to conduct a linearity check after
replacing a capillary tube in a gas analyzer with a tube from a like
model and manufacturer (see Docket A-97-35, Item II-I-9, Policy Manual,
Question 13.13). However, because this change to the CEMS does not
require a RATA, it would not be considered a recertification event.
Therefore, no recertification application would be required, and the
linearity test would be considered a diagnostic test. Note that even
though diagnostic tests would not be classified as recertifications,
the recertification data validation procedures in proposed
Sec. 75.20(b)(3) of today's rule would apply to these tests. EPA
believes that the proposed narrowing of the definition of a
recertification event will significantly reduce the number of required
recertification applications and will make the submittal requirements
for initial certifications and recertifications more consistent.
(b) Recertification Review Period. Consistent with the proposed
narrowing of the definition of a recertification event, EPA also
proposes to revise Sec. 75.20(b)(5) by increasing the recertification
application review period from 60 days to 120 days to make it the same
as the review period for initial certifications. The advantage of
making the two review periods consistent is that there would be no need
to distinguish which requirements are applicable to which events. Some
events combine aspects of initial certification and of recertification.
For example, the certification of a new CEMS on a new stack at an
existing unit when a scrubber is installed can be thought of as initial
certification because it is an entirely new system in a new location;
however, this event also involves aspects of recertification because it
is an existing unit which has been reporting emissions from certified
systems. Therefore, the Agency believes that making the review periods
the same would reduce confusion and case-by-case determination of how
long the review period should be for a given application. The Agency
believes that it would be more effective to establish consistent
procedural requirements for both initial certification and
recertification events, rather than attempting to classify each event
as an initial certification or recertification.
In making the review periods consistent, EPA considered reducing
the length of the review period for initial certifications. EPA
considered both the
[[Page 28045]]
time it takes to complete a thorough technical review of an application
and the time it takes to resolve issues raised during that technical
review. The resolution of issues raised during a review can take a
significant amount of time because it involves coordination between the
source submitting the application, the applicable state and/or local
air agency, the applicable EPA Regional Office, and the Acid Rain
Division at EPA headquarters. Therefore, even though EPA would
anticipate receiving fewer recertification applications under today's
proposed revisions, EPA believes that a 120-day review period is
necessary for recertifications (which, according to today's proposed
definition of a recertification event, would involve the review of
monitoring system accuracy tests) in order to coordinate resolution of
issues raised during the technical review of an application.
EPA recognizes that there are concerns with increasing the
recertification review period to longer than 60 days, as more hours of
data could be invalidated if an application were disapproved. However,
EPA believes that the criteria for approval of monitoring system
certification tests are clear and that when an application is
submitted, the owner/operator should know whether or not the
performance specifications of part 75 have been met. In EPA's
experience of four years of implementation, disapprovals are rarely
issued; in fact, less than 2 percent of all monitoring system
applications submitted between 1993 and September 1997 were disapproved
(see Docket A-97-35, Item II-A-4). In most cases where applications
have been disapproved, the owner or operator should have been aware of
the deficiencies before the application was submitted. Additionally,
EPA has found that a longer review period has allowed more time to
resolve minor deficiencies which could have served as grounds for
disapproval, but which, given sufficient time, were often resolved
without issuing a notice of disapproval and without invalidating any
hourly emissions data.
2. Disapproval of an Incomplete Application
Section 75.20(a)(4) of the existing rule requires EPA to issue a
``notice of approval or disapproval of the certification application
within 120 days of receipt of the complete certification application.''
This provision implies that an application must be complete in order to
issue a disapproval. In attempting to implement this provision, EPA has
encountered the problem of incomplete applications. The Agency has, in
most of these instances, issued a notice of incompleteness to the
source. However, affected sources have not always complied with the
incomplete notices and have sometimes failed to submit the information
requested to complete the application in a timely manner. Therefore,
EPA proposes to clarify that EPA may disapprove an incomplete
certification or recertification application if the submittal deadline
is passed. Before a disapproval would be issued for an incomplete
application, the designated representative would receive a notice of
insufficiency and be given a reasonable period of time to complete the
application. If the complete application was not received by this
extended deadline, EPA could issue a notice of monitoring system
disapproval. The Agency believes that this provision will result in
faster resolution of incomplete certification or recertification
applications, thereby eliminating extended periods of uncertainty about
data validation status.
3. Submittal Requirements for Certification and Recertification
Applications
The current rule requires the owner or operator to submit
certification and recertification applications to the Administrator
(i.e., the Acid Rain Division of EPA) and to the appropriate EPA
Regional Office and state or local air agency. Hardcopy test results
must be submitted, as well as an updated monitoring plan and electronic
test results. The electronic test results must also be submitted to the
Administrator as part of the next quarterly report.
Sections 75.20(a)(4)(ii), 75.59, and 75.63 of today's proposal
would revise and clarify the completeness, format, and submittal
requirements for certification and recertification applications. For a
certification or recertification application to be considered complete,
the appropriate information specified in proposed Sec. 75.63 would be
sent to the Administrator, to the EPA Regional Office, and to the state
and local air agency. Under proposed Sec. 75.63, the Administrator
would receive only a hardcopy application form and would not receive
any hardcopy test results, unless specifically requested. The
Administrator would, however, receive certification and recertification
test results electronically in the quarterly report. In most cases, the
electronic test results would be submitted in the quarter in which the
testing is completed. However, there may be occasional exceptions to
this, for initial certification testing and for recertification
testing, when a series of tests spans two consecutive calendar
quarters.
The local and State agencies, as well as the EPA Regional Office
would receive a hardcopy application form, electronic test results, and
hardcopy test results. For recertification tests, today's proposal
would allow the EPA Regional Office or the state or local air agency to
waive the requirement for a hardcopy recertification test report for
their respective offices. The EPA Regional Office or the state or local
agency could also reinstate that requirement at a later date. EPA
Regional Offices and state and local agencies have historically
received hardcopy certification and recertification reports with
varying contents and formats. Section 75.59(a)(10) would specify the
minimum content for hardcopy certification and recertification reports
for gas and stack flow CEMS. Section 75.63(a)(2)(iii) would limit the
amount of reporting for ``non-recertification events'' that require
diagnostic tests. For a diagnostic test, the only reporting requirement
would be to submit the applicable electronic test results in the next
quarterly report. For DAHS verifications, no reporting would be
required; instead, records of the tests would be maintained on-site in
a manner suitable for inspection.
This series of revisions is intended both to clarify the elements
of a complete application, and to clarify how and to whom the essential
information should be submitted. By not requiring hardcopy test reports
to be sent to the Administrator and by allowing the EPA Regional Office
or state or local agencies to waive hardcopy recertification test
reports, the Agency believes that unnecessary hardcopy reporting to
offices that do not intend to review the reports will be eliminated.
Finally, Sec. 75.63(b) would clarify that for failed certification
or recertification tests, only tests that affect data validation would
need to be reported. For example, if the ordinary rules of data
validation, rather than the retrospective validation procedures, were
applied and a test failure occurred during the initial certification
testing for a new unit, only the passed test would be reported if the
test was subsequently repeated and passed. However, if the conditional
data validation procedures set forth in Sec. 75.20(b)(3) of today's
proposal had been utilized during that same initial certification, the
failed test would have to be reported because it would affect the data
validation of hourly emissions.
[[Page 28046]]
4. Decertification Applicability
The proposed revisions to Sec. 75.21(e)(1) would clarify that
excepted monitoring systems under Appendix D, E, or I or an alternative
monitoring system under subpart E may be decertified in accordance with
Sec. 75.21(e)(1). The proposed revisions would also clarify that
decertification would apply to both an initial certification and a
recertification. EPA believes that logic and consistency dictate the
need for these changes.
5. Recertification Test Notice
Section 75.61(a) would be revised to reduce the burdens associated
with submitting notices of recertification tests. The proposed
revisions would allow EPA or the state agency to waive notification
requirements for recertification tests. Currently, a designated
representative must notify EPA and the state agency prior to commencing
certification or recertification testing so that EPA or a state
representative has an opportunity to observe the testing. Allowing the
recertification notification requirement to be waived and providing
more media options for notifications will help conserve paper, reduce
the reporting burden, and provide more flexibility to facilities when
scheduling tests. In addition, the Agency solicits comment on whether
Sec. 75.61 should be revised to state that the requirement for written
notification could be satisfied by mail, facsimile, or e-mail, subject
to approval by the agency receiving the notification.
6. Monitoring Plans
In Secs. 75.53(e) and (f), which are revised versions of
Sec. 75.53(c) and (d), and Sec. 75.62, today's proposal clarifies
completeness and formatting requirements for monitoring plans. In
Sec. 75.53(e), the existing provisions would be separated into two
separate paragraphs (e)(1) and (e)(2) to clarify which parts of the
monitoring plan must be submitted in electronic format and which
elements must be submitted in hardcopy format. In addition, a number of
minor changes would be made to clarify the actual required content of
the plan. Similarly, in Sec. 75.53(f), the same type of revisions would
be made to clarify the electronic versus hardcopy elements of
monitoring plans for specific situations (Appendix D, E, and I units,
units claiming an opacity exemption, and units with add-on emission
controls). These proposed revisions are generally consistent with
existing implementation of the monitoring plan reporting requirements
and primarily would serve to clarify possibly ambiguous elements of the
current rule. The revisions reflected in Sec. 75.53(e) would add a
requirement to electronically report in the monitoring plan the unit
stack height above ground level and the stack base elevation above sea
level. EPA understands that these data are readily available to unit
owners and operators. EPA collects stack heights for some units, e.g.,
for new or modified sources subject to 40 CFR Sec. 51.166. However,
stack height data is not currently collected for all of the units
affected under title IV of the Act. Moreover, the stack height data
that the Agency has is inconsistent, i.e., some of the data are for
stack height above sea level, some are for above ground level, and some
are undefined. Stack height data is necessary to improve the modeling
of plume height and transport of sulfates and nitrates as part of
acidic deposition and other atmospheric modeling. EPA conducts
atmospheric modeling as part of the congressionally-mandated program of
air pollution monitoring, analysis, modeling, and inventory research
under section 103 of the Act. Such modeling is also used to analyze the
impact of the Act on the public health, economy, and environment,
pursuant to section 312 of the Act. (See also, e.g., Human Health
Benefits From Sulfate Reductions Under Title IV of the 1990 Clean Air
Act Amendments at 3-6 through 3-11 (EPA, 1995)). EPA is also proposing
to collect the Energy Information Administration (EIA) flue
identification numbers associated with each unit. While this data is
already reported to EIA, it is difficult to correlate it with the unit
and stack level data reported to EPA. By having sources specify for
each unit and stack the corresponding flue identification number
reported to EIA, it will be easier to correlate the emissions data
reported to EPA to other data that is reported to EIA and is used for
atmospheric modeling purposes, such as stack exit temperature and
velocity.
Section 75.62 would be revised to clarify which parts of the
monitoring plan must be submitted to the EPA Regional Office and state
and local agencies, and when such submittals are required. The
Administrator would receive an electronic monitoring plan at the
following times: (1) no later than 45 days prior to the initial
certification application; (2) at the time of a recertification
application, if a change in the hardcopy monitoring plan information is
associated with the recertification event; and (3) in each electronic
quarterly report. The EPA Regional Office and state and local agency
would receive the required hardcopy monitoring plan 45 days prior to an
initial certification. Thereafter, hardcopy monitoring plan information
(changed portions, only) would be submitted as follows: (1) with a
recertification application, if a change in the hardcopy monitoring
plan information is associated with the recertification event; and (2)
within 30 days of any other event with which a hardcopy monitoring plan
change is associated. Finally, today's proposed rule would require a
complete monitoring plan to be kept on-site in a form suitable for
inspection (this could include an electronic portion which could be
printed out for inspection). These revisions are intended to clarify
the monitoring plan format and submission requirements, but are
generally consistent with existing practices.
Today's proposal would also clarify when revisions must be made to
the monitoring plan. Currently, only changes that require
recertification require monitoring plan revisions. The EPA recognizes,
however, that many changes affecting the information in a monitoring
plan would not require recertification. Therefore, Sec. 75.53(b) would
be revised to require that the owner or operator update a monitoring
plan whenever information in the monitoring plan changes (e.g., a
change to a serial number for a component of a monitoring system), and
Sec. 75.62 would require submission of the revised monitoring plan in
the next quarterly report or, for hardcopy portions, within 30 days of
the change. This revision would assure that the monitoring plan does
not contain outdated, erroneous information.
Section 75.64(a) would clarify that no hardcopy monitoring plan is
to be submitted with a quarterly report.
7. Submittal Requirements for Petitions and Other Correspondence
Section 75.60(b)(5) would clarify what hardcopy information is sent
to the Administrator for petitions and other communications. These
revisions would clarify the existing rule, but would not represent a
significant change in the requirements for these types of submittals.
F. Substitute Data
1. Missing Data Procedures for CO2 and Heat Input
Background
In the May 17, 1995 rule, two new sections, Secs. 75.35 and 75.36,
were added to part 75. These two new sections provided, respectively,
missing data procedures for CO2 and heat input,
[[Page 28047]]
which were not provided in the original January 11, 1993 rule. Section
75.35 specifies that for CO2, the initial missing data
procedures of Sec. 75.31 are to be followed for the first 720 quality
assured monitor operating hours following initial certification.
Thereafter, provided that the CO2 data availability (as of
the last hour of the previous quarter) is maintained above 90.0 percent
and provided that the length of any CO2 missing data period
does not exceed 72 consecutive hours, a simple average of the ``hour
before'' and ``hour after'' CO2 concentrations is used to
fill in missing data periods. However, if the monitor availability as
of the last hour in the previous quarter is below 90.0 percent or if a
CO2 missing data period exceeds 72 consecutive hours in
length (regardless of the percent monitor availability), then the fuel
sampling procedures of Appendix G must be used to provide substitute
CO2 data.
Section 75.36 has a parallel structure to Sec. 75.35. For units
that determine unit heat input by using a flow monitor and a diluent
(CO2 or O2) monitor, the initial missing data
procedures of Sec. 75.31 are to be followed for the first 720 quality
assured monitor operating hours (for the diluent monitor) and for the
first 2,160 quality assured monitor operating hours (for the flow
monitor), following initial certification. Thereafter, the standard
missing data procedures of Sec. 75.33 are to be followed for the flow
monitor. For the diluent monitor, the on-going missing data provisions
of Sec. 75.36 are nearly identical to those for CO2 in
Sec. 75.35 (i.e., use an ``hour before hour after'' missing data
algorithm, provided that the monitor availability is 90.0
percent and the missing data period length is 72 hours).
However, when the diluent monitor availability is < 90.0 percent or
when the diluent missing data period exceeds 72 hours, Sec. 75.36
specifies that the owner or operator must use the procedures in section
5.5 of Appendix F to determine the hourly heat input.
Utility representatives have asked EPA to consider revising the
missing data procedures for CO2 and heat input (see, e.g.,
Docket A-97-35, Items II-D-20, II-D-30, II-E-13, and II-E-14). The
utilities object to several elements of the current procedures. They
suggest that the Appendix G procedures are burdensome and that the
missing data procedures are considerably different from the standard
missing data procedures for SO2, NOX, and flow
rate, which are based solely on historical data and monitor
availability and require no additional procedures such as fuel
sampling.
Discussion of Proposed Changes
EPA has reconsidered the provisions of Secs. 75.35 and 75.36 in
light of the concerns raised by the regulated community, and is
proposing revisions to the diluent gas missing data procedures for
CO2 and for heat input determinations. The Agency proposes
that the same missing data routines prescribed in Sec. 75.33(b) for
SO2 pollutant concentration monitors also be applied to the
CO2 and O2 data streams that are used to
determine CO2 emissions and heat input. The diluent gas
substitute data values would therefore be determined in a purely
mathematical way, based on historical data and the percent monitor data
availability; no fuel sampling procedures would be required.
Note that these proposed revisions would require the percent
monitor data availability to be known on an hourly basis. This would
require the percent availability for CO2 and O2
monitors to be updated hourly within the data acquisition system. EPA
realizes that this would involve software modifications, and in cases
where the unit heat input is determined using a flow monitor and an
O2 diluent monitor in accordance with Equation F-17 or F-18,
some new recordkeeping provisions would also be required. The necessary
recordkeeping provisions have been proposed in Sec. 75.57(g). To allow
time for software revisions to be made, the revised missing data
procedures in Secs. 75.35 and 75.36 would not take effect until January
1, 2000. The owner or operator could, however, opt to use the new
procedures prior to January 1, 2000.
EPA believes that today's proposed revisions to the missing data
procedures for CO2 and heat input determinations would be
relatively easy to implement because the missing data routines for
SO2 monitors are well-established and are familiar to both
the regulated community and to software vendors. The Agency believes
that the proposed revised missing data procedures would ensure that
data availability remains high and would, over time, reduce the cost of
compliance with the requirements of part 75.
2. Prohibition Against Low Monitor Data Availability
Background
Under the current rule, when a unit uses SO2, flow rate,
and NOX monitoring systems to account for its emissions, for
each clock hour in which a CEMS fails to provide quality assured data,
a substitute data value must be reported to EPA in accordance with the
standard missing data procedures of Sec. 75.33. The method required for
determining the appropriate substitute data values under Sec. 75.33
depends on several factors, such as the overall monitor data
availability and the length of the missing data period. For monitor
data availabilities 90.0 percent, the substitute data value
(which is reported for each clock hour of the missing data period) will
normally be the arithmetic average of the readings from the hour before
and the hour after the missing data period. At other times, it will be
the 90th (or 95th) percentile value from a lookback period of 720 (for
SO2) or 2,160 (for NOX and flow rate) quality
assured monitor operating hours. When the data availability drops below
90.0 percent, the substitute data value for SO2 will be the
maximum concentration recorded in the last 720 quality assured monitor
operating hours, and for flow rate and NOX, the substitute
data value will be the maximum flow rate or NOX emission
rate recorded in the last 2,160 quality assured monitor operating hours
at the corresponding load range.
Based on four years of program implementation, EPA believes that
the standard missing data procedures need to be strengthened. As
presently written, the missing data algorithms lack a safeguard which
will ensure that high monitor data availability continues to be
maintained in future years. In the current version of Sec. 75.33, no
distinction is made between data availabilities of 89.0 percent, 50.0
percent or 10.0 percent. For all three of these data availability
percentages, the substitute data value is the same (i.e., the maximum
value in a lookback period of 720 or 2,160 quality-assured monitor
operating hours). This has potentially serious consequences. For
example, if the substitute data value from the lookback period is non-
punitive or perhaps is even favorable to the facility (e.g., if a low-
sulfur fuel was burned during the lookback period), there would be
little incentive to repair a malfunctioning CEMS in a timely manner and
emissions could possibly be under-reported for a long period of time.
Currently, part 75 does not specifically address this ``gaming
activity.''
Discussion of Proposed Changes
In order to maintain the credibility of the SO2
allowance accounting system and to ensure that affected units continue
to comply with their part 76 NOX emission limits, monitor
data availability must not be allowed to deteriorate indefinitely
without clear and significant consequence to the facility. Therefore,
in today's rulemaking, EPA is proposing to add a
[[Page 28048]]
safeguard to part 75 to ensure that this does not happen. A new
paragraph 75.33(d) would be added, which would make it a violation of
the primary measurement requirement of Sec. 75.10(a) to allow the
annual monitor data availability to drop below 80.0 percent for
SO2, NOX, flow rate, or CO2. Based on
an analysis conducted on data availability information for the third
quarter of 1996, EPA believes that affected facilities will easily be
able to comply with the 80.0 percent data availability criterion (see
analyses in Docket A-97-35, Item II-B-16). The results of that analysis
indicated a mean percent monitor data availability of 96.9 percent for
SO2, 95.0 percent for NOX, and 96.6 percent for
flow rate. Although there were 13 (out of 995 total) SO2
monitors, 21 (out of 997 total) flow monitors, and 46 (out of 1365
total) NOX monitoring systems with percent monitor
availabilities below 80.0 percent in the 4th quarter of 1996, the
Agency expects that many of these systems would be exempt from the
prohibition based on a limited number of operating hours in the
previous year (see Docket A-97-35, Item II-A-8).
The proposed prohibition would not apply to units that have only a
limited number of operating hours (less than 3000 hours of operation in
the previous 12 calendar quarters) because such units can have a low
data availability percentage without necessarily having extended
monitor downtime incidents. In addition, no violation would occur if
the low monitor availability is caused by a sudden and reasonably
unforeseeable event beyond the control of the owner or operator (such
as destruction of monitoring equipment by fire or flood). The owner or
operator would, however, be required to notify the Administrator, in
writing, within 7 days of the occurrence of such catastrophic events
and also to provide notification to the EPA Regional Office and to the
appropriate State agency. The owner or operator would be further
required to submit a corrective action plan, including an
implementation schedule. Thus, this proposed prohibition should not
result in violations of part 75, except for situations involving poor
operation and maintenance practices, which are clearly not beyond the
control of the owner or operator.
Another option considered by the Agency was to modify the standard
missing data algorithms for SO2, NOX, and flow
rate as follows. Under this option, the algorithms for monitor data
availabilities of 90.0 percent to 100.0 percent would remain unchanged.
The algorithms currently used for all monitor data availabilities below
90.0 percent would be retained, but these would apply only to data
availabilities between 80.0 percent and 89.9 percent. Finally, a new
algorithm would be added for monitor data availabilities below 80.0
percent. When the data availability drops below 80.0 percent, the
appropriate maximum substitute data value would have to be used (i.e.,
the maximum potential concentration for SO2 or
CO2, the maximum NOX emission rate, or the
maximum potential flow rate). EPA believes that requiring maximum
values to be reported when the data availability drops below 80.0
percent would provide incentive to the affected sources to keep their
monitors well-maintained. Because any changes to the standard missing
data algorithms would require software modifications, this option, if
adopted, would not take effect until January 1, 2000. The Agency has
not proposed this option because it would require software changes for
all affected units even though very few units have data availabilities
that fall below 80.0 percent. The Agency seeks comment, however, on
whether this option should be used instead of the proposed prohibition
given that it is more consistent with the structure of the missing data
requirements in part 75 and would be self-implementing without any need
to initiate enforcement actions to achieve the desired result of
continued high data availabilities that assure accurate reporting of
emissions.
The Agency also emphasizes that the required data availability for
the Acid Rain Program would remain at 100.0 percent even if the
proposed prohibition is adopted, meaning that substitute data would
have to be supplied for any periods in which data from a certified
monitoring system are not available. This approach is in sharp contrast
to most other CEMS programs that do not rely on substitute data. In
those programs, the Agency, as well as State and local agencies, expect
and often require much higher data availabilities than 80.0 percent.
Based on the number of units with data availability higher than 95.0
percent under the Acid Rain Program, CEMS data availability less than
95.0 percent may well indicate a failure to properly operate and
maintain a CEMS. Many agencies rely on that 95.0 percent availability
level to target systems for inspection and other compliance-related
follow-up actions. In addition, agencies have adopted various required
minimum data availabilities for CEMS that far exceed the 80.0 percent
level selected for the prohibition proposed in today's rulemaking.
It is also important to note that monitor availability under part
75 and monitor downtime under other programs are not always the same.
Under part 75, a source may have actual monitoring data that are
suspect, based on an evaluation of various quality assurance
activities. In this situation, the owner or operator may, as a
conservative measure, report substitute data rather than the actual
data. In contrast, this type of missing data substitution does not
occur under most other programs. In most programs, the suspect data
would simply be invalidated and no emission data would be reported for
those hours.
Therefore, because of the structure of the missing data provisions
in the Acid Rain Program and the generally applicable economic
incentive to achieve high data availabilities under part 75, it would
be improper to equate the proposed prohibition in today's rulemaking
with a required minimum data availability requirement established for
other programs that do not have the same features. The Agency does not
intend that this proposed provision should serve as a precedent for
evaluating the appropriate achievable data availability for other
programs. Consistent with current practices, the Agency would continue
to expect CEMS to achieve high data availability and that, generally,
monitor downtime in excess of 5.0 percent may warrant appropriate
investigation and follow-up activities.
G. General Authority to Grant Petitions Under Part 75
Background
Section 75.66(a) provides generally that a designated
representative of a unit subject to part 75 may submit a petition to
the Administrator. Sections 75.66(b) through (h) address petitions to
the Administrator on the specified topics of alternative flow
monitoring methods, alternatives to standards incorporated by
reference, alternative monitoring systems, parametric monitoring
procedures, missing data for units with add-on emission controls,
emission or heat input apportionments, and the partial recertification
process. Each of these subsections set forth the items which must be
included with a particular type of petition. In addition, Sec. 75.66(i)
states that, for any other petition to the Administrator under part 75,
the designated representative for an affected unit shall include
sufficient information for the evaluation of such petition.
[[Page 28049]]
Discussion of Proposed Changes
Today's proposal would revise Sec. 75.66(a) to state clearly that
the designated representative of an affected unit may petition the
Administrator for authorization to apply an alternative to any
requirement under part 75 or incorporated by reference in part 75,
regardless of whether another section of part 75 explicitly allows such
a petition concerning the particular requirement. EPA views this change
as a clarification to the general authority already provided by
Secs. 75.66(a) and (i). The proposed rule would also be amended to
include new paragraphs (i) through (l), which would set forth the
specific requirements for other petitions that are explicitly allowed
by other sections of the rule but which are not currently included in
this section. In addition, the proposed rule, at Sec. 75.66(m), would
also indicate the appropriate documentation to be submitted for
petitions under subsection (a), except those under subsections (b)
through (l), where the required documentation is already specified. The
required documentation in subsection (m) would be: (1) Identification
of the unit; (2) information explaining why the proposed alternative
should be used instead of the existing part 75 provision; (3)
descriptions and, if applicable, diagrams of the equipment and
procedures to be used in the proposed alternative; and (4) information
demonstrating that the proposed alternative is consistent with the
purposes of the provision for which an alternative is requested and is
consistent with the purposes of part 75 and of section 412 of the Act.
Rationale
As presently codified, EPA is concerned that the rule does not
state clearly what types of petitions may be submitted under
Sec. 75.66. In particular, existing subsection (i) could be interpreted
as referring only to petitions that are mentioned in other sections of
part 75 and that are not specifically listed in Sec. 75.66(b) through
(h). EPA has not interpreted Sec. 75.66(i) in this manner. In
administering the Act, EPA has inherent discretion to grant de minimis
exceptions from statutory or regulatory requirements, where EPA
determines that holding the regulated entity to the applicable
requirement would yield a gain of trivial or no benefit, provided
Congress has not unambiguously demonstrated its intent to foreclose
such exceptions. See, e.g., Public Citizen v. Young, 831 F.2d 1108, 113
(D.C. Cir. 1987); Alabama Power Co. v. Costle, 636 F.2d 323, 360-61
(D.C. Cir. 1979). Since the issuance of part 75 in 1993, EPA has
accepted, and, in some cases exercised its discretion and granted,
petitions under Sec. 75.66 that requested exceptions and that were not
specifically referenced in Sec. 75.66(b) through (h) or elsewhere in
part 75 (see Docket A-97-35, Item II-B-17). Such petitions have
included, for example, a request to set a CO2 span lower
than that required by part 75 in order to more accurately quality
assure the CO2 monitor. Another petition requested an
alternative to the requirement to perform an annual RATA on a unit that
was scheduled to shutdown, prior to the deadline for performing the
RATA, in order to install a scrubber, construct a new stack, and
install and certify new CEMS. A petition was also submitted for
permission to use a propane sampling frequency as specified in the
State operating permit and to then calculate SO2 emissions
by using the highest sulfur content recorded during the previous 365
days and report these data in quarterly reports. These petitions were
submitted for the purpose of requesting alternatives to various
requirements of part 75, even though the ability to petition the Agency
on these issues was not referenced explicitly in other sections of part
75 or in Sec. 75.66(b) through (h). In most cases, the circumstances
leading to the request for an alternative to a part 75 requirement were
not anticipated during the drafting of part 75 regulations. In fact,
today's proposal revises several part 75 requirements to allow for
alternatives that were originally requested and approved through the
petition process set forth in Sec. 75.66. The Agency continues to
believe that the general provision allowing petitions for alternatives
to part 75 requirements is necessary to enable EPA to address
circumstances that were not foreseen during the development of such
requirements. This is important since circumstances can sometimes vary
significantly from boiler to boiler. While the response to comment
document for the January 11, 1993 rule (see Docket A-91-69, Item V-C-1,
Issue # M-8.8.2) might be read to bar petitions for exceptions from any
provision of part 75, EPA maintains that such a reading would be
inconsistent with the regulatory language of Secs. 75.66(a) and (i)
that allow such petitions, and with the established practice of the
Agency in administering part 75.
The existing Sec. 75.66(i) states that for petitions other than
Sec. 75.66(b) through (h) petitions submitted under the section, the
designated representative should include sufficient information for the
evaluation of the petition. No other information is provided concerning
the contents of such petitions. As Secs. 75.66(b) through (h) all
provide a list of the type of information that should be included in
petitions submitted under the respective sections, the Agency believes
that, in addition to amending Sec. 75.66(a) to clarify that petitions
may be submitted for circumstances that may not be covered by other
sections authorizing petitions to the Administrator, it is appropriate
to provide units with a list of the type of information that should be
included with the petition. Similarly, EPA believes that it is
appropriate to add to the section provisions setting forth the
information requirements for those petitions that are explicitly
allowed under other sections of part 75 but that are not listed in the
existing Sec. 75.66. All these revisions would make the petition
process more uniform and minimize confusion regarding what information
EPA would require in order to accept and consider any petition for an
alternative to a part 75 requirement.
H. NOX Mass Monitoring Provisions for Adoption by
NOX Mass Reduction Programs
Background
Part 75 contains requirements for monitoring NOX
emissions with a continuous emission monitoring system or other
approved method. Owners and operators are required to calculate hourly,
quarterly average, and annual average NOX emission rates (in
lb/mmBtu). Part 75, however, currently contains no requirements for
reporting NOX mass emissions (in tons). Other NOX
emission reduction programs being developed pursuant to title I of the
Act (such as the NOX Budget Program in the Ozone Transport
Region) are expected to require reporting of NOX mass
emissions from many of the units affected under the Acid Rain Program.
To streamline reporting burdens under multiple programs and to allow
for the administration of multi-state NOX mass trading
programs, the Agency believes it appropriate to amend part 75 to
include provisions for monitoring, recording, and reporting
NOX mass emissions that could apply to such trading
programs. These provisions would provide standard procedures--resulting
in precise, reliable, accessible, and timely emissions data--that could
be adopted under a state or federal NOX mass emission
reduction program. To the extent that these standard provisions are
adopted, the burden on industry would be reduced and the administration
of the programs would be facilitated, in
[[Page 28050]]
that the Agency or implementing states would not need to develop
NOX mass monitoring provisions anew and industry would not
need to become familiar with multiple approaches to NOX mass
monitoring.
Discussion of Proposed Changes
The proposed NOX mass emissions provisions would apply
only where EPA, states, or groups of states incorporate them and
mandate their use through a separate regulatory action. The proposed
amendments would make changes to Secs. 75.1, 75.2, 75.4, 75.16, 75.17,
Appendix D, section 2.1.2.2, and Appendix F, section 5.5. They would
also add a new subpart H containing new Secs. 75.70, through 75.73 and
a new section 8 in Appendix F containing sections 8.1, 8.1.1, 8.1.2,
8.1.3, 8.1.4, 8.2, 8.3, 8.3.1, and 8.3.2.
Section 75.1, the purpose and scope section, would be amended to
broaden the scope by adding that part 75 will also set forth provisions
for monitoring and reporting NOX mass emissions that EPA,
states, or groups of states may require sources to use to demonstrate
compliance with a NOX mass emission reduction program.
Section 75.2 would be amended to add that the provisions of part 75 may
also apply to sources subject to a state or federal NOX mass
emission reduction program.
The compliance date section, Sec. 75.4(a), would be altered to
state that the provisions relating to monitoring and reporting of
NOX mass emissions become applicable on the deadlines
specified in the applicable state or federal NOX mass
emission reduction program requiring the use of part 75 to monitor and
report NOX mass emissions.
Section 75.16 would be amended to state that title IV affected
units using the provisions of part 75 to monitor and report
NOX mass emissions under a state or federal NOX
mass emission reduction program would have to meet the heat input
monitoring and determination requirements in both Sec. 75.16 and in
subpart H, Secs. 75.71 and 75.72. Section 75.17 would be amended to
state that title IV affected units using the provisions of part 75 to
monitor and report NOX mass emissions under such a program
would have to meet the NOX emission monitoring and
determination requirements in both Sec. 75.17 and subpart H,
Secs. 75.71 and 75.72.
The applicable procedures for the monitoring and determination of
NOX mass emissions would be added in proposed subpart H,
Secs. 75.70, 75.71, and 75.72 and corresponding recordkeeping and
reporting requirements would be set forth in Sec. 75.73.
Section 75.70 would set forth the general requirements including:
definitions, compliance dates, incorporation by reference, initial
certification and recertification procedures, quality assurance and
quality control requirements, substitute data requirements, and
requirements regarding petitions. In general these provisions for
monitoring NOX mass would mirror the provisions for
monitoring of SO2, NOX, and CO2 for
compliance with title IV. However, because the program would be a state
program, rather than a federal program, there would be some differences
in the administrative requirements. These differences would be most
pronounced for units that were not subject to Acid Rain emission
limitations and were not already subject to the provisions of part 75.
The major differences in administrative requirements would involve the
process for petitioning under Sec. 75.66 and the process for certifying
and recertifying monitors. Under the existing Acid Rain Program, the
Administrator must approve all petitions under Sec. 75.66. Under this
proposal, petitions for units that were only subject to the provisions
of part 75 because they were subject to a state or federal
NOX mass emission reduction program, would have to be
approved by both the permitting authority for the applicable
NOX mass program and the Administrator. The permitting
authority would also be responsible for reviewing and approving or
disapproving certification and recertification applications for such
units.
Section 75.71 sets forth the general monitoring methodologies that
would be allowed for different types of units. The proposal would
require units to determine hourly NOX mass emissions (in lb)
by monitoring NOX emission rate (in lbs/mmBtu) and heat
input (in mmBtu/hr) on an hourly basis and by multiplying those two
values and the hourly unit operating time (in hour or fraction of an
hour) together. Coal units and other units that burn solid fuel and
that are covered by subpart H would be required to measure
NOX emission rate using a NOX emission rate CEM
consisting of a NOX concentration CEM and a diluent CEM
(CO2 or O2 CEM) and to measure heat input using a
diluent CEM and a continuous volumetric flow monitor. All gas- and oil-
fired units covered by subpart H would be allowed to use that approach
or, alternatively, could measure NOX emission rate using a
NOX emission rate CEM and heat input by using a fuel
flowmeter and performing fuel sampling and analysis. This alternative
for determining heat input from gas- and oil-fired units is set forth
in Appendix D of part 75. Gas and oil units that qualify as either
peaking units or low mass emission units under part 75 would also have
additional lower cost monitoring methodologies available to them.
Peaking units, for example, would have the option to do source testing
to create heat input versus NOX emission rate correlation
curves. Then, based on hourly measurement of heat input from a fuel
flowmeter and fuel sampling and analysis using the provisions in
Appendix D to part 75, the heat input vs NOX emission rate
correlation curves would be used to estimate the hourly NOX
emission rate. This rate would be used in conjunction with hourly
measured heat input to determine NOX mass. A unit that
qualifies as a low mass emission unit would have the option to use a
fuel-type and boiler-type specific default NOX emission rate
and the unit's maximum rated hourly heat input to determine
NOX mass emissions. The low mass emissions unit provisions
are in proposed Sec. 75.19.
Section 75.72 sets forth the specific requirements for monitoring
emissions at units that share common stacks and/or common pipes, for
units that emit to multiple stacks and for units that receive fuel from
multiple pipes. These provisions mirror similar provisions in
Sec. 75.16 for monitoring SO2 mass emissions from similar
units and groups of units.
Appendix D, section 2.1.2.2 would indicate that the heat input
apportionment procedures of that section would not be applicable for
units whose compliance with this part is required under a
NOX mass emissions reduction program. Instead, the unit
would have to meet the heat input monitoring and determination
requirements in subpart H, Secs. 75.71 and 75.72.
The applicable procedures for calculating NOX mass
emissions would be added in proposed section 8 of Appendix F. Section
8.1 of Appendix F contains proposed equations for determining hourly
NOX mass emissions, section 8.2 contains proposed equations
for determining quarterly, cumulative annual and ozone season
NOX mass emissions, and section 8.3 contains specific
provisions for monitoring NOX emissions from a common stack.
Additionally, revisions to section 5.5 of Appendix F would indicate
that the heat input calculation procedures of section 5.5.3 would not
be applicable for units whose compliance with this part is required
under a NOX mass emissions reduction program.
[[Page 28051]]
Rationale
(a) Authority to Propose NOX Mass Provisions. The
authority for the proposed NOX mass provisions rests in two
separate portions of the Act. First, section 412(a) states that the
owner or operator of an affected source under title IV must monitor and
quality assure data for sulfur dioxide and nitrogen oxide for each
affected unit at the source. 42 U.S.C. 7651k(a). This section does not
limit the nitrogen oxide data requirement to emission rate data in lb/
mmBtu or to data necessary for compliance with emission limits
established under title IV. Indeed, oil-and gas-fired units have been
required to report NOX emission rate data under part 75 even
though only existing coal units are subject to NOX emission
limits under title IV. (See 58 FR 3590, 3644, January 11, 1993). Thus,
the Agency believes that providing for reporting NOX mass
emissions under part 75 is an appropriate exercise of the authority
under section 412, particularly since NOX mass emissions
reporting may be required under a separate applicable requirement.
Second, independently of the authority granted by section 412,
section 114(a) of the Act gives the Administrator broad authority to
collect data for ``the purpose of developing or assisting in the
development of any implementation plan under section 110 or 111(d)'',
``of determining whether any person is in violation of any such
standard or a requirement of such a plan'', or ``carrying out any other
provision of [the] Act'' (except certain provisions of title II
concerning mobile sources). Section 114 is, of course, not limited to
sources that are affected units under title IV. Moreover, section
301(a)(1) authorizes the Administrator ``to prescribe such regulations
as are necessary to carry out his functions'' under the Act, including
the functions specified in section 114. Thus, EPA maintains that the
Agency is authorized to adopt provisions in part 75 that could govern
monitoring of NOX mass emissions, especially where such
information is expected to support States' efforts to attain ambient
air quality standards.
From a policy perspective, now is the appropriate and most
efficient time to adopt these changes. In July 1997, EPA Administrator
Carol Browner announced a series of initiatives to reform environmental
data management and collection (see Docket A-97-35, Item II-I-21). The
new initiatives are intended to streamline reporting requirements and
increase coordination across different programs that affect the same
sources. There are a number of examples of ongoing efforts to
streamline the reporting of emissions for utility units. One example is
a proposal to revise the NSPS NOX standards for utility and
industrial boilers subject to reporting under 40 CFR part 60. That
proposal would allow facilities to submit NSPS reports through part 75
reporting (see 62 FR 36948, July 9, 1997). Another example is the Ozone
Transport Commission's NOX Budget program. That program is
expected to require utility sources and certain industrial sources in
the northeast to reduce emissions of NOX through a trading
program similar to the Acid Rain SO2 trading program. On
January 31, 1996, the OTC released the Model Rule which outlines
procedures for the monitoring and reporting of NOX mass
emissions; these procedures are based on the monitoring and reporting
requirements set forth in part 75 (see Docket A-97-35, Items II-I-7 and
II-I-22). Today's proposal would facilitate the coordination of
reporting under the Acid Rain Program and NOX mass programs
like the OTC NOX Budget Program.
In addition, the Agency believes it is appropriate to include these
requirements in the current proposal because the Acid Rain affected
units may be undertaking DAHS software changes to respond to the other
proposed revisions to part 75 if they are adopted. The Agency would
enable facilities to coordinate the necessary software changes by
proposing the revised reporting requirements to allow for
NOX mass emission reporting at this time along with the
other part 75 revisions. Although EPA is proposing this requirement now
to facilitate software changes, the requirement to actually record and
report NOX mass emission data under part 75 generally would
not become effective for any unit unless and until a program requiring
such recording and reporting is implemented for that particular unit
(EPA notes that, as discussed elsewhere in Section III.C.4. of this
preamble, a limited group of title IV affected units (i.e., low mass
emissions units) would be required to record and report NOX
mass emissions for purposes of the Acid Rain Program.) In addition, if
a state elected to require the use of these requirements to support a
state NOX mass emission monitoring and reporting
requirement, these requirements would not become federally enforceable
until those requirements were approved by EPA as part of the SIP.
(b) Monitoring Methodology. The proposed requirement would require
sources to determine NOX mass as a function of hourly
average NOX emission rates, heat input rates, and unit
operating time. EPA is proposing this approach because it accurately
accounts for NOX mass emissions without requiring any
changes to the current missing data routines and quality assurance
requirements in part 75. An alternative to this approach, not included
in today's proposal, would be to measure total mass emissions using a
NOX pollutant concentration monitor, a volumetric flow
monitor and unit operating time, analogous to the approach taken
currently for SO2 emissions. This methodology would have two
advantages: first, there would be less missing data from a
NOX pollutant concentration monitor than from a
NOX CEMS which (under the existing and proposed rule)
contains both a NOX pollutant concentration monitor and a
diluent monitor; and second, it would avoid possible overestimation
from a bias adjustment factor applied to the NOX system to
correct bias in the diluent monitor (see Docket A-97-35, Item II-D-96).
However, this methodology would also have a number of
disadvantages. In order to monitor NOX as total mass
emissions using a NOX pollutant concentration monitor and a
volumetric flow monitor, several major changes would need to be made to
part 75. The entire concept of a NOX CEMS--and the quality
assurance tests and missing data procedures associated with the
NOX CEMS--might need to be revised, to include either a
NOX CEMS with only a NOX pollutant concentration
monitor and a DAHS (in which case, a separate flow monitoring system
would also be required in order to determine NOX mass), or a
NOX CEMS with a NOX pollutant concentration
monitor, a volumetric flow monitor, and a DAHS. Since the relative
accuracy standard currently in part 75 for NOX systems is in
lb/mmBtu, it would be necessary to establish a new relative accuracy
standard for NOX concentration in ppm if the NOX/
flow method described above were incorporated into the final rule. Bias
adjustment would also have to occur on the newly defined NOX
CEMS. It would also be necessary to create a missing data procedure
either for NOX concentration in ppm or for hourly
NOX mass emission rate in lb/hr. Hourly NOX mass
emission rate would be calculated using the same formula as for
SO2 mass emission rate (Equation F-1 or F-2), only using a
constant of 1.194 x 10-7(lb/scf)/ppm NOX. In
addition, this methodology would not easily support the monitoring and
reporting of NOX emission rate data in lb/mmBtu.
[[Page 28052]]
Therefore, in order to meet the emission rate reporting requirements,
affected sources under title IV would still be required to maintain a
diluent CEMS and the current NOX emission rate missing data
procedures. The Agency has not proposed this approach because it does
not believe that the benefits of slightly reduced amounts of missing
data for NOX mass and removal of the bias adjustment factor
for the diluent monitor justify the complication of having two separate
procedures for monitoring NOX emissions from a given unit.
Nevertheless, the Agency requests comment on whether this approach to
measuring mass emissions should be used in lieu of the proposed heat
input and emission rate approach for sources required to report
NOX mass.
(c) Common Stack and Pipe Monitoring. The Agency notes that the
proposed procedures for monitoring NOX emission rate at a
common stack to determine NOX mass emissions under the
proposed Sec. 75.72 procedures are different than the procedures
currently allowed for monitoring NOX emission rate in
Sec. 75.17. The Agency is concerned that the Sec. 75.17 provisions
would be too imprecise for measuring NOX mass emissions
because the two values used to determine NOX mass emissions
(NOX emission rate and heat input) are not required to be
measured at the same location. In the existing rule, NOX
emission rate may be monitored at the unit level in the duct leading to
the common stack and heat input can be determined from measurements at
the common stack and then apportioned to the individual units using
unit load. While this heat input apportionment method has been allowed
for Acid Rain purposes, it is not accurate in all cases because it does
not account for different heat rates from the units exhausting to the
common stack and does not account for differences in operating time at
the units. It has been allowed by the Agency for Acid Rain purposes
because apportioned heat input determined under Sec. 75.16 (e) had only
a limited effect on emissions trading (i.e., on the SO2
allowance program). Although apportioned heat input determined under
Sec. 75.16(e) is used to determine compliance with the reduced
utilization provisions of the Acid Rain Program, the apportioned heat
input estimate was deemed accurate enough for that purpose and for the
relatively small number of units and short period involved.
Determinations of reduced utilization are required only for Phase I
units during 1995-1999 and for opt-in units. However, for purposes of a
NOX mass trading program, the heat input value would be used
in the calculation to determine NOX mass, and an imprecise
unit level heat input value could cause the NOX mass
emissions from some units to be underestimated. The NOX mass
trading program could be undermined by the lack of a consistent
emissions value for each NOX allowance. Therefore, the
proposed provisions for monitoring heat input and NOX
emission rate from units in a NOX mass trading program would
be similar to the provisions that are currently used for monitoring
SO2 mass emissions at a common stack at Sec. 75.16. The
provisions for monitoring SO2 mass emissions require that
the two values needed to determine SO2 mass emissions, stack
flow rate and SO2 concentration, be monitored at the same
location. The Agency is proposing that, for purposes of determining
NOX mass emissions, a facility could use the same location
options currently available for SO2: the facility could
either monitor both NOX emission rate and heat input at the
common stack level or monitor them both at the unit level. The Agency
is also proposing a third option: heat input could be monitored at the
unit level and summed to the common stack level, while NOX
emission rate could be monitored at the common stack level. Even though
this option would allow NOX emission rate and heat input to
be measured at different locations, it does not have the inherent
inaccuracies described above because it does not require heat input
apportionment.
Similarly, the optional procedures currently allowed for the
apportionment of heat input measured at a common pipe in Appendix D,
section 2.1.2.2 are not available for units with a common pipe under
subpart H. As discussed above for common stacks, the Agency is
concerned that the heat input apportionment under Appendix D, section
2.1.2.2 provisions would be too imprecise for the purpose of
calculating NOX mass emissions. In the existing rule, heat
input can be determined from measurements at the common pipe and then
apportioned to the individual units using unit load. For purposes of
calculating NOX mass emissions under subpart H for a unit
which is supplied fuel from a common pipe, the measurement of fuel flow
rate would have to be made at the pipe leading to the individual unit
in order to determine unit level heat input.
The Agency solicits comment on the proposed approach for monitoring
NOX mass emissions at a common stack or pipe and whether it
is appropriate to mirror the common stack and pipe provisions for
SO2 mass emissions.
(d) Multiple duct/stack monitoring. The current provisions for
monitoring NOX emission rate, in Secs. 75.17(c)(1) and (2),
allow the owner or operator to determine NOX emission rate
for a unit that exhausts through multiple ducts or stacks using a Btu-
weighted sum of the NOX emission rates measured in each duct
or stack or by monitoring NOX emission rate in only one duct
or stack. The new proposed Sec. 75.72 would set forth specific
requirements for monitoring NOX mass in multiple ducts or
stacks and would in some cases place a number of limits on the options
in Sec. 75.17(c) and in some cases not allow the options in
Sec. 75.17(c). The proposed options for monitoring NOX mass
are similar to the existing provision in Sec. 75.16(d) for monitoring
SO2 mass emissions at multiple ducts/stacks. They are also
similar to the provisions being used in the OTC NOX Budget
Program to determine NOX mass in similar situations.
The new proposed Sec. 75.72 does not contain an option for any
units to use a Btu-weighted sum of the NOX emission rates
measured in each duct or stack. The reason that this option is not
appropriate is that in order to use this option to determine a unit's
NOX emission rate, the owner or operator of the unit would
have to monitor both NOX emission rate and heat input in
each duct or stack. (As discussed above, the heat input apportionment
method allowed under Sec. 75.17 is not sufficiently accurate for a
NOX mass program.) These two values allow the calculation of
NOX mass and, therefore, there is no reason to determine a
Btu-weighted sum for purposes of this subpart.
The new proposed Sec. 75.72 would not allow coal units to monitor
NOX emission rate in only one duct or stack. The proposal
would also not allow gas and oil units to monitor the NOX
emission rate in only one duct or stack, unless heat input is
determined using the provisions of Appendix D to this part and the
owner or operator makes a demonstration that the emission rate would
always be the same in both ducts or stacks. Reasons that the emission
rate might vary include the use of add-on emission controls in the
ducts or stacks or venting of emissions to one duct or stack and not
the other.
These limitations are required for monitoring mass emissions (in
lbs), but are not necessary for monitoring emission rate (in lbs/mmBtu)
at coal units or gas and oil units that use continuous volumetric flow
monitors, because, for reasons discussed above, monitoring mass
requires the monitoring of both emission rate and heat input. Since the
amount of stack
[[Page 28053]]
flow that is vented to each duct or stack could vary significantly
depending upon the location and use of dampers and induction fans in
the ducts or stacks, it is necessary to measure volumetric flow in both
ducts or stacks in order to determine heat input for the unit(s). In
order to accurately use these heat input values to determine
NOX mass, it is also necessary to measure NOX
emission rate in both ducts or stacks. Therefore, proposed Sec. 75.72
would require monitoring of heat input and NOX emission rate
in both ducts or stacks for coal units and gas-and oil-fired units that
use continuous volumetric flow monitors and exhaust to multiple ducts
or stacks.
Since gas-and oil-fired units that are using the procedures in
appendix D of part 75 to determine heat input based on fuel consumption
do not have to measure volumetric flow in the duct or stack in order to
determine heat input, EPA believes it is appropriate to allow these
units to measure NOX emission rate in only one duct or stack
if they can demonstrate to both the permitting authority and the
Administrator that the NOX emission rate in either duct or
stack is representative of the NOX emission rate in each
duct or stack. Therefore, proposed Sec. 75.72 allows gas-and oil-fired
units that are using the procedures in appendix D of part 75 to measure
NOX emission rate in only one duct or stack if they can
demonstrate to both the permitting authority and the Administrator that
the NOX emission rate in either duct or stack is
representative of the NOX emission rate in each duct or
stack.
(e) Reporting of NOX Mass Emissions. The Agency also
notes that the proposed procedures differ in two key respects from the
way data is currently reported under part 75. The first difference is
that the proposal would require reporting of hourly NOX mass
emissions, in lbs, (instead of hourly mass emission rate, in lb/hr, as
is currently required for the reporting of SO2 under part
75). The OTC NOX Budget Program is expected to require the
reporting of hourly mass emissions, in lb, rather than hourly mass
emission rates, in lb/hr, because of experience under the Acid Rain
Program with reporting hourly SO2 and CO2 mass
emission rates. As discussed in Section III.R.1 of this preamble, the
reporting of hourly SO2 and CO2 mass emission
rates has been a source of some confusion in the implementation of the
Acid Rain Program. For the reasons presented in Section III.R.1 of this
preamble, EPA is not proposing to change the existing SO2
and CO2 reporting requirements. However, the existing part
75 does not require any NOX mass emission reporting, and in
order to avoid the problems experienced under the Acid Rain Program and
to be consistent with the OTC NOX Budget Program, EPA
proposes here to base the new NOX reporting on mass
emissions in pounds. Maintaining consistency with the provisions
expected to be adopted for the OTC NOX Budget Program is
important to ensure that a central body such as EPA would be able to
effectively administer the program if states opted to participate in a
multi-state NOX trading program larger than the Ozone
Transport Region covered by the OTC NOX Budget Program.
The second key difference is that, in addition to reporting a
quarterly and cumulative annual total emissions value, the proposed
revisions would also require reporting of a cumulative ozone season
total value. Generally, the ozone season extends from May 1 to
September 30 of every year. The cumulative ozone season emissions would
be reported with the second quarter and third quarter reports submitted
to EPA. The reason that reporting would be required on an ozone season
basis is that one of the main reasons the data is being collected is to
support other programs designed to control emissions during the ozone
season.
(f) Role of EPA and States/Localities in Administering the
Monitoring Portion of a NOX Trading Program. The Agency also
notes that another important potential difference between the use of
this part to support the Acid Rain Program under Title IV of the CAA
and the use of this part to support other NOX mass emission
reduction programs is the role that EPA and the state or local
permitting authority that may establish such a program will play. Under
the Acid Rain Program, even though many states have assumed the role of
the permitting authority under Phase II of the program, EPA still
retains authority to issue approvals and disapprovals related to all of
the monitoring and reporting issues, such as certification of
monitoring systems under Sec. 75.20, approval of petitions under
Sec. 75.66 and approvals of alternate monitoring petitions under
Sec. 75.48. EPA believes that if a NOX mass emission
reduction program is approved as part of a SIP or if EPA agrees to work
with individual or groups of states to help administer the monitoring
and reporting portion of a NOX mass emission reduction
program, EPA would still have to be involved in the approval process.
The level of this involvement might vary depending upon the
specific type of approval or disapproval. It also would vary depending
upon whether or not the unit had an Acid Rain emission limitation. For
instance, EPA would play a significant role in the approval of an
alternate monitoring petition under Sec. 75.48 or any other petitions
under Sec. 75.66. For a unit with an Acid Rain emission limitation, any
petition would already have to be approved by EPA. In order to
streamline the process for these sources, EPA believes that EPA should
continue to issue approvals and disapprovals of petitions. However,
since sources would also be using the monitored data to meet SIP
requirements, EPA would take this action in consultation with the
applicable state. For units that are not subject to an Acid Rain
emission limitation, EPA would still need to be involved in petition
determinations. There are two primary reasons that this involvement
would be necessary. The first would be as part of EPA's typical role in
assuring that any alternative to the approved SIP will still result in
the air quality benefit that would have been derived if the permitting
authority had not deviated from the SIP. The second would be as part of
EPA's role in administering the emissions tracking portion of a
NOX mass emission reduction program. If EPA was not involved
and a state approved, for a unit, an alternative that allowed
variations to the reporting requirements, EPA might not be able to
administer the emissions tracking portion of the program for that unit.
Similarly, for approval and disapproval of certification applications
and recertification applications, EPA believes that there should be two
separate requirements; one for units subject to an Acid Rain emission
limitation, and one for units not subject to an Acid Rain emission
limitation. For units subject to an Acid Rain emission limitation, EPA
would still approve or disapprove certification and recertification
applications. This would streamline the process for units since they
would only have to deal with one regulatory agency for both programs.
For units not subject to an Acid Rain emission limitation, the
permitting authority would approve certification and recertification
applications. EPA requests comment on this approach and whether the
respective roles of the Administrator and the permitting authority
should be different for units that are subject to both an Acid Rain
emission limitation and to a NOX mass emission reduction
program and for units that are subject solely to a NOX mass
emission reduction program.
[[Page 28054]]
I. Span and Range Requirements
Background
The span and range requirements for part 75 continuous emission
monitoring systems are found under section 2.1 of Appendix A to the
January 11, 1993, rule, as amended on May 17, 1995. Sections 2.1.1,
2.1.2, 2.1.3 and 2.1.4 of Appendix A give the specific span and range
requirements for SO2 monitors, NOX monitors,
diluent (O2 and CO2) monitors, and flow rate
monitors, respectively.
The span of a CEMS provides an estimate of the highest expected
value for the parameter being measured by the CEMS. For instance, the
span value of an SO2 monitor should be an approximation,
based on the type of fuel being combusted, 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. Part 75 span values are used to determine the
appropriate reference gas concentrations and reference signals for
daily calibration of the CEMS; the reference concentrations and signal
values 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 to the January 11, 1993
rule specified procedures for determining the span values for four
parameters: 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 results from the previous 12 months (using the highest
sulfur content and lowest heating value in Equation A-1a or A-1b). The
SO2 span value was then obtained by multiplying the MPC by
1.25 and rounding the result upward to the next highest multiple of
100.0 ppm. The MPC values for NOX were specified in the rule
and were based on the type of fuel being combusted (e.g., 800.0 ppm for
coal-firing and 400.0 ppm for oil-firing). The NOX span
value was then determined by multiplying the MPC by 1.25 (e.g., 1000.0
ppm for coal-firing and 500.0 ppm for oil-firing). 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 either using
Equation A-3a (or A-3b) or from historical test data (i.e., from
velocity traverses conducted at or near maximum load). Then, the span
value was obtained by multiplying the MPV by 1.25 and rounding the
result upward to the next highest multiple of 100 feet per minute
(fpm).
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 were
used to reduce SO2 emissions), a second, ``low-scale'' span
and range would be required. The low scale of the CEMS would be defined
as 1.25 times the ``maximum expected concentration'' (MEC). The
original rule was prescriptive regarding the method of determining the
MEC. For SO2, the MEC was to be calculated using Equation A-
2; for NOX, an MEC value of 320.0 ppm was to be used for
coal-firing and 160.0 ppm for oil-or gas-firing.
In the first two years of Acid Rain Program implementation, it
became increasingly clear to both the regulated community and to EPA
that the span and range provisions of part 75 lacked sufficient
flexibility and clarity. The NOX provisions were
particularly problematic, being overly prescriptive in some instances
and sometimes requiring two spans and ranges when a single,
appropriately-sized range would suffice. Also, the units of the flow
rate span were expressed in terms of velocity (i.e., feet per minute),
and this was not consistent with either the units of measure used for
daily monitor calibrations or the units used for electronic reporting
of flow rate data.
The May 17, 1995 rule attempted to address these deficiencies, as
follows. For SO2, an alternative means of determining the
MPC, in lieu of using historical fuel sampling data, was added; the MPC
could be based upon 30 days of historical CEMS data. The use of
historical CEMS data was also allowed as an option for MEC
determinations, instead of using Equation A-2. For NOX, the
method of determining the MPC was made less prescriptive. First, 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. The MPC value from this list could be used in lieu of the
fuel-based MPC prescribed in the original rule. Second, two alternative
methods of determining the MPC or MEC were added, i.e., from historical
CEMS data or from emission test results. Finally, flexibility was added
to the dual-range requirements for NOX monitors so that, in
many instances, the span and range requirements of part 75 could be met
on a site-specific basis, using a single span and range.
The span provisions for CO2 and O2 were not
significantly changed in the May 17, 1995 rule. For flow rate, however,
a more detailed procedure for determining the span value was added.
This addition was considered necessary because during the first year of
program implementation it came to light that there are actually two
important span values associated with flow rate: (a) the
``calibration'' span value used for daily calibrations, and (b) the
``flow rate'' span value in units of standard cubic feet per hour
(scfh). These two span values are both derived from the MPV, but are
almost invariably expressed in different units of measure, and,
therefore, the two spans are generally not equal numerically. For
instance, the calibration span value for the daily calibration of a
differential pressure-type flow monitor, expressed in units of inches
of water, is a small number (generally less than 5.0 in.
H2O); while the flow rate span value, in scfh, is a very
large number, usually in the tens or hundreds of millions.
The May 17, 1995 rule also revised the procedures for adjusting the
span and range of SO2, NOX, and flow monitors.
Sections 2.1.1.4, 2.1.2.4, and 2.1.4 of Appendix A to the original rule
had specified that span and range adjustments were required whenever
the MPC, the MEC, or the MPV changed significantly. 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 revised sections 2.1.1.4, 2.1.2.4, and 2.1.4
of Appendix A to 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. Finally, the May 17,
1995 rule specified that whenever the range of a gas monitor is
adjusted, a linearity test is required, and a calibration error test
must be done when the range of a flow monitor is adjusted.
Discussion of Proposed Changes
Since promulgation of the May 17, 1995 rule, EPA has continued to
receive questions and comments about the span and range sections of
part 75. Many of
[[Page 28055]]
the questions and comments have centered on the adjustment of span and
range. The following questions are typical: When must the span and
range be changed? What constitutes a ``significant'' change in the MPC,
MEC, or MPV? When a span and range adjustment is required, what are the
deadlines for making the changes and for completing the required
linearity test? How should full-scale exceedances be reported? There
also appears to be some lingering confusion and misunderstanding about
how to determine the flow rate span values and how to calculate the
maximum potential flow rate (MPF) and the NOX maximum
emission rate (MER) (see Docket A-97-35, Items II-B-8, II-D-67, and II-
E-31). In view of this, EPA believes that the span and range sections
of the rule are still not sufficiently clear, flexible, or detailed and
are in need of further revision. In June, 1996, a national part 75 CEM
Implementation Workgroup meeting was held in Washington D.C. to discuss
possible revisions to part 75. One of the principal topics of
discussion was span and range (see Docket A-97-35, Item II-E-32).
Today's rulemaking proposes comprehensive revisions to sections 2.1
through 2.1.4 of Appendix A, based in part on the discussions of the
June, 1996 meeting. The principal changes are described in paragraphs
(1) through (5), below.
1. Maximum Potential Values
The basic procedure for determining the maximum potential of
SO2 concentration would be unchanged by today's proposal.
However, two new provisions would be added to section 2.1.1.1 of
Appendix A to prevent overestimation of the MPC. The first of these
provisions would allow the exclusion of clearly anomalous fuel sampling
results when determining the MPC. The second provision would apply to
units for which the designated representative certifies that the
highest sulfur fuel is never combusted alone, but is always blended or
co-fired with other fuel(s) during normal operation. For such units,
the MPC would be calculated using best estimates of the highest sulfur
content and lowest gross calorific value expected for the blend or fuel
mixture and inserting these values into Equation A-1a or A-1b. The best
estimates of the highest percent sulfur and lowest GCV for a blend or
fuel mixture would be derived from weighted-average values based upon
the historical composition of the blend or mixture in the previous 12
(or more) months.
The alternative procedure for determining the MPC of SO2
based upon quality assured historical CEMS data would be retained, but
it is proposed that the MPC be based, at a minimum, upon the previous
720 quality assured monitor operating hours, rather than the previous
30 unit operating days. This is to ensure that a sufficient quantity of
valid data is used for the MPC determination. Making the determination
based on 30 unit operating days does not provide that assurance,
particularly for units that may only operate for a few hours a day
(e.g., peaking units). Revised section 2.1.1.1 would also specify that
for a unit with add-on SO2 emission controls, the historical
CEMS data option may only be selected if the certified SO2
monitor used to determine the MPC is located at the control device
inlet.
For NOX, the general procedures for determining the MPC
would also remain the same, i.e., either: (1) use the MPC value
prescribed in the original rule, (2) use the unit-specific value listed
in Table 2-1 or 2-2, or (3) determine the MPC by emission testing or
from historical CEM data. However, the following changes to section
2.1.2.1 of Appendix A are proposed. First, a statement would be added
that the MPC would have to be based upon the combustion of whichever
fuel or blend combusted at the unit produces the highest level of
NOX emissions. Second, an advisory statement would be added,
noting that the initial MPC value determined for a unit that is not
equipped with low-NOX burners (LNB) would have to be re-
evaluated if a low-NOX burner system is subsequently
installed and optimized. Third, if historical CEMS data are used to
determine the MPC, the determination would have to be based on the
previous 720 (or more) quality assured monitor operating hours (instead
of the previous 30 unit operating days). Fourth, units with add-on
NOX emission controls could only use the historical CEM data
option if the historical data represented uncontrolled emissions (e.g.,
if the certified CEMS used to collect the data were located prior to
the control device inlet or, for a unit with seasonal NOX
controls, if the historical data were from a period when the controls
were not operating). Fifth, if emission testing is used for the MPC
determination, sufficient tests would have to be performed at various
loads and excess oxygen levels to ensure that a credible MPC value is
obtained. For units with add-on NOX emission controls, the
emission test data would have to be collected upstream of all controls,
or, for a unit with seasonal controls, during a period when the
controls were not operating. Finally, a specific requirement to
calculate the maximum potential NOX emission rate (MER)
would be added to section 2.1.2.1 of Appendix A. The May 17, 1995 rule
had provided a definition of the MER in Sec. 72.2; however, a
corresponding requirement to calculate the MER was not included in part
75 at that time. The MER is occasionally needed to provide substitute
NOX emission rates during missing data periods. The owner or
operator would be permitted to 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.
For CO2, today's proposed rule would add a new section
2.1.3.1 to Appendix A, which provides a definition of the MPC. The MPC
for CO2 pollutant concentration monitors would be 14.0
percent for boilers and 6.0 percent CO2 for combustion
turbines. Alternatively, the MPC could be based on a minimum of 720
hours of representative quality assured historical CEM data.
For flow rate, the procedure for determining the MPV would be
essentially unchanged by today's proposed rule, i.e., the MPV would
either be determined from Equation A-3a (or A-3b, as applicable) in
Appendix A, or it would be based on velocity traverse data taken at or
near maximum load. However, a procedure for calculating the maximum
potential flow rate (MPF) would be added to section 2.1.4.1 of Appendix
A. The MPF is occasionally used to provide substitute flow rate data;
therefore, a clear, consistent method of determining the MPF is needed.
2. Maximum Expected SO2 and NOX Concentrations
Today's proposal would significantly change the procedures for
determining the maximum expected concentration (MEC) of SO2.
The purpose of the revisions would be to ensure that the proper span(s)
and range(s) are selected for SO2 measurement. Proposed
section 2.1.1.2 of Appendix A would require the MEC to be determined
for units with SO2 controls and also for uncontrolled units
that burn both high- and low-sulfur fuels (or blends) as primary or
backup fuels (e.g., high- and low-sulfur coal or different grades of
fuel oil).
The revised procedures for determining the MEC for SO2
would be as follows. For units with emission controls, Equation A-2 in
Appendix A would be used to calculate the MEC. For uncontrolled units
that burn both high-sulfur and low-sulfur fuels or blends as primary or
backup fuels, Equation A-1a or A-1b in Appendix A (which in the
[[Page 28056]]
current rule is reserved for MPC calculations) would be used to
determine an MEC value for each fuel or blend, with three important
exceptions. The MEC would not be calculated for: (1) the highest-sulfur
fuel or blend (because it would be duplicative of the MPC calculation);
(2) fuels or blends with a total sulfur content no greater than the
total sulfur content of natural gas, i.e., 0.05 percent
sulfur by weight, because Sec. 75.11(e)(3)(iv) of the current rule
specifies that natural gas combustion does not trigger a dual span and
range requirement for the SO2 monitor (for gas firing, the
MEC and low-scale span values would be too low to be practical for
quality assurance purposes, e.g., < 5 ppm for pipeline natural gas);
and (3) fuels or blends that are combusted only during unit startup,
because such fuels are infrequently used and are not representative of
normal unit operation.
Today's proposal would continue to allow the same flexibility in
the SO2 MEC determination that was introduced in the May 17,
1995 rule. That is, if a certified SO2 CEMS is already
installed, the owner or operator could determine the MEC based upon
historical continuous monitoring data, in lieu of using mathematical
equations. If this option were chosen for a unit with SO2
controls, the MEC would be the maximum SO2 concentration
measured at the control device outlet by the CEMS over the previous 720
or more quality assured monitor operating hours with the unit and the
control device both operating normally. For units that burn both high-
and low-sulfur fuels or blends as primary and backup fuels and have no
SO2 controls, the MEC for each fuel would be the maximum
SO2 concentration measured by the CEMS over the previous 720
or more quality assured monitor operating hours in which that fuel or
blend was the only fuel being burned in the unit.
Today's rule also proposes to change the way in which the MEC is
determined for NOX. Revised section 2.1.2.2 of Appendix A
would require a determination of the MEC during normal operation for
units with add-on NOX controls capable of reducing
NOX emissions to 20.0 percent or less of the uncontrolled
level (i.e., steam injection, water injection, selective catalytic
reduction or selective non-catalytic reduction). 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. The MEC would be determined in one of three ways: (1)
using Equation A-2 in Appendix A; or, if that equation is not
appropriate, (2) by emission testing or (3) by using historical CEMS
data from the previous 720 (or more) quality assured monitor operating
hours. Revised section 2.1.2.2 would give specific guidelines and
procedures by which to obtain the MEC when the emission testing or CEMS
data options are selected. All CEMS or emission test data used for the
MEC determination would be taken under stable operating conditions with
all control devices and methods operating properly.
3. Span and Range Values
For SO2, NOX, and flow rate, respectively,
revised sections 2.1.1.3, 2.1.2.3 and 2.1.4.2 of Appendix A would allow
the high-scale span value to be between 100.0 and 125.0 percent of the
maximum potential value (i.e., the MPC or MPV), rounded off
appropriately. This is a change from the current rule which requires
the high span to be set at 125.0 percent of MPC or MPV, rounded off
appropriately. However, the change is not expected to be disruptive,
because properly sized span values previously determined by multiplying
the MPC or MPV by 1.25 could continue to be used. The change would
allow the owner or operator to set the span value in such a way that a
small exceedance of MPC or MPV would not require a span change (see
paragraph 5, ``Adjustment of Span and Range,'' below). The added
flexibility in span selection would also allow different units with
similar (but not identical) MPCs for SO2 and/or
NOX to use the same span value and to use the same
calibration gas concentrations, which could result in cost savings for
some facilities. In 1996, EPA received and approved a petition from one
utility to equalize the SO2 span values at several of its
coal-fired units (see Docket A-97-35, Items II-C-23, II-D-71).
For CO2 and O2 monitors, today's proposal
would revise section 2.1.3 of Appendix A to allow the owner or operator
maximum flexibility in selecting an appropriate span value. The
CO2 or O2 span value would not be determined in
the same way as an SO2, NOX, or flow rate span
value. Rather, for CO2 monitors installed on boilers, any
convenient span value between 14.0 percent and 20.0 percent
CO2 representing the percent diluent in the flue gas would
be acceptable. For combustion turbines, any 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. However, if the O2
concentrations are expected to be consistently below 15.0 percent, an
alternative span value of less than 15.0 percent could be used,
provided that an acceptable technical justification was included in the
monitoring plan. The proposed rule would also allow purified instrument
air containing 20.9 percent O2 to be used as the high level
calibration gas for oxygen monitors having span values greater than or
equal to 21.0 percent O2.
There are two principal reasons why EPA is proposing increased
flexibility in the selection of the CO2 and O2
span values. The first is to encourage greater accuracy in the diluent
gas measurements. The revisions would allow the span value to be
customized so that the concentration of the upscale calibration gas
used for daily calibrations can be as close as possible to the actual
average CO2 or O2 concentrations in the stack. In
1996, EPA received and approved a petition from one utility to use a
CO2 span value of 15.0 percent for its coal-fired units,
rather than the 20.0 percent span value required by part 75 (see Docket
A-97-35, Items II-C-20, II-D-68). The second reason for revising the
CO2 and O2 span requirements is to eliminate
unnecessary high-level span and range requirements. The current rule
requires a high span value of 20.0 percent for all CO2 and
O2 monitors. However, there are many units (e.g., combustion
turbines) for which the diluent gas concentrations are so low that the
guideline in the current section 2.1 of Appendix A (i.e., that the
majority of the readings be within 25.0 to 75.0 percent of full-scale)
cannot be met unless a second, low-scale span and range are used. For
most of these units, there are technical and safety reasons why the
diluent concentrations must remain low; therefore, it is unreasonable
to require a high range to be maintained if a lower range will suffice
and can never be exceeded. During the Phase II certification process,
EPA approved CO2 span values of 10.0 percent for a number of
combustion turbines and waived the high-scale range requirement (see
Docket A-97-35, Items II-C-19, II-C-21, II-D-64).
Today's proposal would not change the basic way in which the full-
scale range setting of a monitor is determined. The range would still
have to be set greater than or equal to the span value. However, the
guideline for selecting an appropriate full-scale range in section 2.1
of Appendix A would be revised as follows. With few exceptions, the
full-scale range would be selected so that, to the extent practicable,
the readings during typical unit operation fall between 20.0 and 80.0
percent of full-scale; this represents a slight increase in flexibility
from the ``25-to-75 percent of
[[Page 28057]]
full-scale'' guideline in the current rule. Today's proposal would also
emphasize that section 2.1 is only a guideline and would cite three
specific cases in which it is inapplicable. Specifically, the guideline
would not apply to: (1) quality assured SO2 readings
obtained during the combustion of natural gas or fuel with equivalent
total sulfur content (because the resulting SO2 emissions
are too low to be subject to the span and range requirements); (2)
quality assured SO2 or NOX readings on the high
range for an affected unit with SO2 or NOX
emission controls and two span values (because the high range is not
the normal operating range for the unit); and (3) quality assured
SO2 or NOX readings 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 are
associated with periods of high control device efficiency (because it
is not necessary to re-range a monitor based on non-representative
hours of exceptional control performance).
For flow monitors, today's rule proposes to revise section 2.1.4.2
of Appendix A to more clearly define the ``calibration span value''
(which is the span expressed in the units of measure used for the daily
calibrations) and the ``flow rate span value'' (which is the span
expressed in the units used for electronic data reporting, i.e., scfh).
The proposed rule defines these two span values in considerable detail
and outlines how to use them. EPA believes that this will result in
greater consistency in implementation of the part 75 flow rate
monitoring requirements.
4. Dual Span and Range Requirements for SO2 and
NOX
In today's rule, revisions are proposed to the dual span and range
requirements for SO2 and NOX monitors in sections
2.1.1.4 and 2.1.2.4 of Appendix A. The revised provisions are
essentially the same for both pollutants. 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 determined under revised section 2.1.1.2 or 2.1.2.2 of Appendix
A would be compared against the maximum potential concentration (MPC)
determined under proposed sections 2.1.1.1 or 2.1.2.1. If this
comparison shows any of the MEC values to be < 20.0 percent of the MPC,
a low-scale span would be required. If several of the MEC values are
found to be < 20.0 percent of the MPC, then the low-scale span would be
based upon whichever MEC value is closest to 20.0 percent of the MPC.
The low-scale span value would be determined in a manner similar to the
high-scale span, i.e., by multiplying the MEC by a factor between 1.00
and 1.25 and rounding off the result appropriately.
When both a high-scale span and a low-scale span are required for
SO2 or NOX, proposed sections 2.1.1.4 and 2.1.2.4
would allow the owner or operator to use either of the following
monitor configurations to meet the dual-range requirement: (1) a single
analyzer with two ranges, or (2) two separate analyzers connected to a
common probe and sample interface. The use of other monitoring
configurations would be subject to the approval of the Administrator.
The monitor configurations would be represented in the monitoring plan
as follows: (a) the high and low ranges could be designated as two
separate, primary monitoring systems; (b) the high and low ranges could
be designated as separate components of a single, primary monitoring
system; or (c) one range (the ``normal'' range) could be designated as
a primary monitoring system, and the other range as a non-redundant
backup monitoring system. The high and low ranges would be quality
assured according to their designation in the monitoring plan. Primary
monitoring systems would have to meet the QA requirements for primary
systems in Sec. 75.20(c), Appendix A, and Appendix B, with the
following exception: relative accuracy test audits (RATAs) would be
required only on the normal range. For units with emission controls,
the low range would be considered normal; for other units, the range in
use at the time of the scheduled RATA would be considered normal. Non-
redundant backup systems would have to meet the applicable QA
requirements for ``like-kind replacement analyzers'' in proposed
Sec. 75.20(d).
Today's rule would add a new alternative provision under sections
2.1.1.4 and 2.1.2.4 of Appendix A for dual-span units with
SO2 or NOX emission controls. The new provision
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 (based on uncontrolled emissions). This value would be reported
whenever the SO2 or NOX concentration exceeded
the full-scale of the low-range analyzer. The default high-range value
is being proposed for controlled units that seldom, if ever, experience
full-scale exceedances of the low monitor range during normal operation
(e.g., units that have a permit condition requiring cessation of unit
operation when a full-scale exceedance occurs or units that experience
low-range exceedances only during startup). EPA solicits comment on the
proposed approach of using a default high-range value in lieu of a high
range monitor and on the value of the default.
EPA specifically requests comment on whether the proposed dual-span
monitoring configurations, monitoring system designations, and quality
assurance requirements are adequate, or whether there are additional
configurations (e.g., one range with two spans, two separate analyzers
with separate probes, etc.) that should be included in the rule.
Finally, when two spans and ranges are required, proposed revised
sections 2.1.1.4 and 2.1.2.4 of Appendix A would specify that the low
range would have to be used to record emission data when the
SO2 or NOX concentrations are expected to be
consistently below 20.0 percent of the MPC (i.e., when a fuel or blend
with a MEC value < 20.0 percent of the MPC is combusted). And if the
full-scale of the low range is exceeded, the high range would be used
to record data (or, if applicable, the default high range value would
be reported).
5. Adjustment of Span and Range
In today's rule, detailed guidelines and procedures are proposed
for adjusting the span and range of the CEMS in revised sections
2.1.1.5, 2.1.2.5, 2.1.3.2 and 2.1.4.3 of Appendix A. The intent of
these provisions is to ensure that each owner or operator assesses the
adequacy of all CEMS span values on at least a quarterly basis (and
whenever operational changes are planned) and, based on that
assessment, makes any necessary adjustments to the spans or ranges in a
timely manner. EPA believes that the proposed procedures are
sufficiently flexible so that frequent span and range adjustments will
not be necessary. The procedures are primarily directed at CEMS with
improperly-sized spans and ranges, to bring them into full conformance
with part 75 requirements or for future changes in unit operation
(e.g., fuel switch or low-NOX burner installation) that may
significantly affect the level of emissions or flow. All required span
or range adjustments would have to be made no later than 45 days after
the end of the quarter in which the need to adjust the span or range is
identified, unless the span change would require new calibration gases
to be ordered for daily calibration error and linearity tests, in which
case, the owner or operator would have up to
[[Page 28058]]
90 days after the end of the quarter to make the span adjustment.
The revised procedures for span and range adjustment would be as
follows. First, if the maximum value upon which the high span value is
based (i.e., the MPC or, for flow rate, the MPF) is exceeded during a
calendar quarter, but the span is not exceeded, the span or range would
not have to be adjusted. However, for missing data purposes, if any
quality assured hourly concentration or flow rate exceeds the MPC or
MPF by 5.0 percent during the quarter, a new MPC or MPF
would have to be defined, equal to the highest value recorded during
the quarter, and a monitoring plan update would be required. Second,
for the high measurement range, if any quality assured reading 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, equal to the highest on-scale reading recorded during the
quarter, and the span value would also have to be changed. If the new
span value exceeded the current full-scale range setting, then a new
range setting would also be required. Similar span adjustment
requirements would apply to the low scale if the two measurement ranges
are used separately for distinctly different modes of operation (e.g.,
during the combustion of different fuels), rather than being used in
combination to provide a continuum of measurement range capability.
The proposed procedures for responding to full-scale exceedances
are as follows. Whenever the full-scale of a high monitor range is
exceeded, excluding hours of non-representative operating conditions
(e.g., a trial burn of a new fuel), corrective action would be required
to adjust the span and range. In addition, any time the range is
exceeded, 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.
The Agency believes that 200.0 percent of the range is sufficiently
conservative to ensure that emissions would not be under-reported. One
utility that experienced a full-scale exceedance of the high
SO2 monitor range estimated from the results of fuel
sampling that the SO2 concentration was approximately 150.0
percent of full-scale during the incident (see Docket A-97-35, Item II-
D-24).
For units with two span values and two measurement ranges for a
particular parameter (e.g., SO2), when the full-scale of the
low range is exceeded, provided that the high monitor range is
available to record emission data, no corrective actions would be
required. However, if, at the time of the low-range exceedance or
during the continuation of the low-range exceedance, the high range is
either out-of-service or out-of-control for any reason (and therefore
is not available to record quality assured data), the MPC would have to
be reported until the readings either returned to the low scale or
until the high scale returned to service and was able to provide
quality assured data. However, if the reason the high scale is
unavailable is because of a high scale exceedance, 200.0 percent of the
high range value would be reported for each hour of the exceedance.
Proposed sections 2.1.1.5(e), 2.1.2.5(e), and 2.1.4.3(e) of
Appendix A would require that the monitoring plan be updated whenever
changes are made in the maximum potential values, maximum expected
values, span values, or full-scale range settings. The updates would be
made in the quarter in which the changes become effective. The proposed
sections 2.1.1.5(e) and 2.1.2.5(e) of Appendix A would further require
a linearity test to be done whenever the span of a gas monitor is
adjusted, if the span change is significant enough to require new
calibration gases for daily calibration error tests and linearity
checks. Finally, proposed sections 2.1.4.3(c) and (d) of Appendix A
would require a calibration error test to be done whenever a flow
monitor span or range is adjusted (unless the adjustment requires a
significant change to the flow monitor that would require
recertification under Sec. 75.20(b)).
J. Quality Assurance/Quality Control (QA/QC) Program
1. QA/QC Plan
Background
Section 1 of Appendix B to part 75 as originally promulgated on
January 11, 1993 sets forth provisions for developing and implementing
a quality control program. As part of the quality control program,
section 1 requires that the source develop and maintain a quality
control plan that documents how the equipment used to report emissions
data for part 75 is maintained and quality assured. While the
provisions in sections 1.1, 1.2, and 1.4 of Appendix B to part 75 are
applicable only to continuous emissions monitoring systems, the
provisions in sections 1.3 and 1.5 of the existing rule are more
generally applicable to all monitoring systems under part 75. The
quality assurance requirements for excepted monitoring systems under
Appendices D and E and for alternative monitoring systems under subpart
E are provided in the respective Appendices or subpart of part 75, as
revised; however, specific guidelines for the quality control plans for
these systems are not given.
Based on the experience of state and EPA inspectors at Acid Rain
field audits, there has been confusion and inconsistency among industry
sources regarding the contents of the quality control plan. In some
cases, utility staff have requested further guidance from EPA on what
the quality control plan should contain. Based on this experience, the
Agency believes that the quality control program provisions in section
1 of Appendix B need to be revised. Specifically, the rule needs to be
clarified in two areas: (1) the applicability of the QA/QC program
(i.e., do the provisions apply to all monitoring systems, only to CEMS,
or only to specific excepted or alternative monitoring systems?); and
(2) the recordkeeping requirements for repair and maintenance events.
In addition, several utilities have asked EPA to consider deleting the
requirement to maintain an inventory of spare parts, which they believe
to be unnecessary and burdensome.
Discussion of Proposed Changes
The proposed revisions discussed in this section affect section 1
of Appendix B to part 75. The terms ``quality control program and
plan'' would be changed to ``quality assurance/quality control program
and plan.'' The scope of section 1 would be expanded to include QA/QC
program provisions for excepted monitoring systems under Appendices D,
E, and I and alternative monitoring systems under subpart E. Section 1
would also be reordered to separate the requirements applicable to all
monitoring systems (section 1.1) from the requirements specific to CEMS
(section 1.2). The preventative maintenance provisions, in section 1.3
of the existing rule, would be moved to section 1.1.1 of the proposal,
and would be revised to delete the requirement to maintain an inventory
of spare parts. A new section 1.1.3 would be added to specify the
requirements for maintaining records of testing, maintenance, and
repair activities. QA/QC program requirements specific to excepted
monitoring systems under Appendices D, E, and I would be added in
section 1.3. These provisions would require written procedures to be
maintained for fuel flowmeter testing, primary element inspection, and
fuel sampling and analysis as well as requiring a description of
equipment and records of testing to be maintained. Section 1.3.6 would
make the
[[Page 28059]]
recordkeeping requirements consistent with the quality assurance
requirements of section 2.3.1 of Appendix E. Section 1.3.7 would
specify which QA/QC program requirements apply for excepted monitoring
systems under Appendix I. Finally, section 1.4 would define the QA/QC
program requirements for alternative monitoring systems approved under
subpart E, based on the quality assurance requirements of subpart E.
Rationale
The Agency believes that the manner in which quality assurance/
quality control (QA/QC) and maintenance-related activities are
performed can have a significant effect upon the accuracy of the data
reported by a monitoring system. Therefore, today's proposal seeks to
ensure that adequate records are kept to document that each monitoring
system and its ancillary components is being maintained and operated in
a proper manner. Section 1 in Appendix B to part 75 would, therefore,
be amended to provide sources with General guidance regarding QA/QC
program requirements. However, the Agency recognizes that QA/QC
programs may vary from site to site and that many sources have already
developed and implemented an effective QA/QC program. It is the
Agency's intent to allow each source the flexibility to develop and
implement a QA/QC program that will result in the reporting of accurate
emissions data through proper equipment calibration, maintenance and
troubleshooting procedures.
(a) Inventory of Spare Parts. Section 1.3 of Appendix B to part 75
in the January 11, 1993 rule requires that an inventory of spare parts
be maintained as part of the QA/QC program. The intent of this
requirement is one of the fundamental goals of a QA/QC program, i.e.,
to maximize the availability of quality-assured data from the
monitoring system. Since maintenance and repairs are required in order
to keep the monitoring system operating properly, the need for
replacement parts will arise over the term of use of the monitoring
equipment. In order to minimize the amount of time when the system is
unable to provide data because a new part is needed, the existing rule
requires that the source maintain an inventory of spare parts. The
Agency has received comments on this requirement from both affected
utilities and from state inspectors arguing that it is unnecessary and
cumbersome (see Docket A-97-35, Item II-D-49, II-E-28). Commenters have
suggested that different approaches have been effectively employed to
ensure that spare parts are available in a timely manner; however, not
all of these approaches require that an inventory of spare parts be
kept on-site. For example, some spare parts may be available on a very
timely basis from a local supplier, making it unnecessary to maintain
spare parts on-site. The Agency believes that these different
approaches may be adequate substitutes for keeping an on-site inventory
of spare parts. Therefore, the requirement to maintain an inventory of
spare parts would be removed in today's proposal, although the
objective of an effective QA/QC program, i.e., to maximize data
availability, would not change.
(b) Maintenance Records. The Agency believes that maintaining
records of monitoring system maintenance and repairs is an essential
component of an effective QA/QC program. Several utilities have
indicated that they agree and have instituted QA/QC programs which
include maintaining such records (see, e.g., Docket A-97-35, Item II-D-
88). However, some EPA and state inspectors have found that not all
sources keep adequate records of maintenance and repairs in their QA/QC
program. EPA believes that this failure to keep adequate records
compromises the effectiveness of the QA/QC program. Therefore, today's
proposal would require each source to maintain proper records of all
testing, maintenance, or repair activities performed on any monitoring
system or component. Additionally, today's proposal would require that
these records and any additional supporting documentation be made
available for review during an audit.
(c) Excepted Monitoring System Requirements. The required quality
assurance activities for excepted monitoring systems are set forth in
the respective Appendices D, E, or I. Today's proposed revisions in
section 1.3 of Appendix B would specify that information on the
approved methods, test procedures and test results must be maintained
on-site suitable for inspection as part of the QA/QC program. The
proposed revisions would consolidate all of the QA/QC requirements in
Appendix B rather than having them spread out in Appendices D, E, and
I.
2. Flow Monitor Polynomial Coefficient
Background
Many of the stack gas volumetric flow rate monitors currently in
use by affected sources use software polynomial coefficients to convert
electrical signals from the monitors into flow rate values that are
electronically reported to the Acid Rain Division. The flow rate values
generated from these monitors are used by the source's data acquisition
and handling system (DAHS) to compute hourly mass emission rates of
SO2, CO2, and hourly heat input rates. Currently,
affected sources are not specifically required to report, record, or
document the numerical values of the polynomial coefficients used by
their flow monitors.
Discussion of Proposed Changes
Proposed Sec. 75.59(a)(5)(vi) and proposed revisions to section
1.1.3 of Appendix B would require the current values of the flow
monitor coefficients to be recorded and would require records to be
kept of any changes or adjustments to the coefficient values. The
proposed revisions in Sec. 75.20(b) define flow monitor coefficient
adjustment as an event which requires recertification.
Rationale
(a) Recordkeeping of Coefficients. The agency has recently become
aware (by a comment received in response to a request for review of the
Acid Rain Audit Manual) of a potentially serious omission in the flow
monitor recordkeeping requirements of part 75 (see Docket A-97-35, Item
II-D-92). The commenter indicated that part 75 lacks a requirement to
document the values of the polynomial coefficients which are programmed
into the software of most flow monitoring devices, and that the Acid
Rain CEM audit manual does not recommend that Agency or state auditors
check the coefficient values. The values of the polynomial coefficients
are important because they are directly related to the accuracy of a
flow monitor. The coefficient values are usually established at three
different load levels (low, mid, and high), in a process called
``linearization'' or ``characterization'' of the monitor. Linearization
is done in an attempt to ensure that the flow monitor reads accurately
across all load levels. The Agency agrees with the commenter that the
flow monitor variables are a critical component of the flow monitoring
system and that the adjustment of those variables represents a
significant change to the flow monitoring system. Therefore, today's
rulemaking proposes to add Sec. 75.59(a)(5)(vi) to require owners and
operators of affected sources to record the numerical values of the
flow monitor polynomial coefficients used during initial certification
of the monitor and during each subsequent relative accuracy test audit
(RATA). In
[[Page 28060]]
addition, section 1 of Appendix B to part 75 would be revised to
require that any changes to the flow monitor polynomial coefficients be
documented and maintained as part of the QA/QC program maintenance
records. Section 1 of Appendix B would also be changed to require the
source to document procedures related to the adjustment of flow monitor
variables in its QA/QC plan. The values of the flow monitor
coefficients and the related adjustment procedures would be required to
be kept on-site, in a format suitable for review by an inspector during
an audit.
(b) Recertification After Adjustment of Coefficients. Since
changing the flow monitor polynomial constants relinearizes the
instrument, significantly altering the monitored reading, today's
proposed rule would amend Sec. 75.20(b) to require recertification
subsequent to any flow monitor polynomial coefficient change. Since a
three level RATA is the only part 75 quality assurance test that checks
the linearity of a flow monitor, the recertification would require a
three level RATA.
K. Calibration Gas Concentration for Daily Calibration Error Tests
Background
All part 75 gas monitoring systems are required by section 2.1.1 of
Appendix B of the current rule to pass daily calibration error tests,
in order to validate emission data from the CEMS. The procedures for
conducting the daily calibration error tests are found in section 6.3.1
of Appendix A. Each daily calibration error test consists of injecting
two protocol gases of known concentration into the CEMS and comparing
the responses of the instrument to the tag values of the protocol
gases. The two required gas concentrations for the calibration error
tests are zero-level (i.e., 0.0 to 20.0 percent of the span value of
the instrument) and high-level (80.0 to 100.0 percent of span).
The span values of part 75 SO2 and NOX
monitors are determined by multiplying the maximum potential
concentration (MPC) by 1.25 and rounding the result upward to the
nearest 100.0 ppm. For CO2 and O2 monitors, a
span value of 20.0 percent O2 or CO2 is
prescribed. These span values have been deliberately oversized to
prevent full-scale exceedances from occurring. Consequently, the
SO2, NOX, CO2, and O2
readings obtained during normal unit operation are generally well below
the span values and typically range from about 25.0 to 75.0 percent of
full-scale. Because of the oversized span values, the concentrations of
the high-level calibration gases used for daily calibration error tests
are often much higher than the actual pollutant and diluent gas
concentrations in the stack. As a result, the representativeness of the
daily calibration error test can be questioned, because the test does
not always check the accuracy of an analyzer on the part of the scale
where most of the readings occur. For instance, typical CO2
concentrations for many part 75 units range from about 10.0 to 12.0
percent CO2 (i.e., 50.0 to 60.0 percent of the span value).
However, when CO2 analyzers are calibrated, the high-level
calibration gas concentrations (i.e., 16.0 to 20.0 percent
CO2 ) are considerably higher than normal stack emissions.
In view of this, EPA believes it would be appropriate to allow the
owner or operator to have greater flexibility in selecting a
representative upscale gas for daily calibrations. One State agency has
successfully implemented this type of flexibility in its CEM program.
The State's CEM rule specifies the acceptable range of values for the
upscale calibration gas, but adds the following qualifying statement,
``* * *unless an alternative concentration can be demonstrated to
better represent the normal source operating levels *-*-*'' (see Docket
A-97-35, Item II-D-72).
Discussion of Proposed Changes
Today's rule proposes to add flexibility to the procedures for
conducting the calibration error tests of part 75 gas monitors to
encourage daily calibrations to be done more representatively. Section
6.3.1 of Appendix A would be revised so that, beginning on January 1,
2000, either the mid-level gas (50.0 to 60.0 percent of span) or the
high-level gas (80.0 to 100.0 percent of span) could be used as the
upscale calibration gas for daily calibration error tests. A
corresponding change would be made to the procedure for calculating the
calibration error in section 7.2.1 of Appendix A. Prior to January 1,
2000, the owner or operator would have the option of using the mid-
level calibration gas for daily calibrations if it better represents
the typical stack gas concentrations than the high-level gas.
L. Linearity Test Requirements
Background
Section 75.20(c) of the current part 75 rule requires a 3-point
linearity test of each SO2 and NOX pollutant
concentration monitor and each diluent gas (O2 or
CO2) monitor, as part of the initial certification process.
A linearity test consists of a series of nine reference calibration gas
injections at three different known concentration levels (low, mid, and
high) to establish the accuracy of a gas analyzer across its
measurement range. The procedures for conducting linearity tests are
found in section 6.2 of Appendix A to part 75. Section 6.1 of Appendix
A specifies that linearity tests must be done while the unit is
operating.
After the initial certification of a gas monitoring system, section
2.2 of Appendix B to part 75 requires periodic linearity tests to be
performed. A linearity check is required during each unit operating
quarter or, for bypass stacks, during each quarter in which flue gases
are discharged through the stack. For units with two span values for a
particular parameter (e.g., units with add-on SO2 controls),
linearity tests must be conducted on both the ``low'' and ``high''
monitor ranges. Successive linearity tests are, to the extent
practicable, to be conducted no less than 2 months apart.
Utility representatives have asked EPA to consider changing the
requirement for the unit to be operating when linearity tests are done
(see Docket A-97-35, Items II-D-20, II-D-65, II-E-13, II-E-14). This
has been requested because owners and operators of peaking units and
other units that operate on an ``on-call'' basis have experienced
difficulty in complying with the requirement for the unit to be on-line
during linearity tests. For instance, a unit may only operate for a few
hours in a quarter and not be needed again until the next quarter. In
such a situation, the utility might be forced to re-start and operate
the unit (whether or not it is needed) to comply with the linearity
test requirement. Some of the utility representatives have also
expressed the opinion that for certain monitoring technologies (e.g.,
dry extractive), on-line and off-line linearity tests are essentially
equivalent.
Discussion of Proposed Changes
1. Unit Operation During Linearity Tests
Today's rule proposes to revise the linearity test requirements of
part 75 to make them easier with which to comply. EPA agrees that the
current linearity test requirements of part 75 lack flexibility and
that compliance with the requirements is particularly difficult for
infrequently operated units. However, the Agency does not agree with
the utility representatives that have suggested allowing off-line
linearity tests as the best solution to the problem. Nor is the Agency
proposing to allow technology-specific exemptions to the on-line
linearity test requirement.
[[Page 28061]]
Rather, today's proposal would retain the requirement for linearity
tests to be performed while the unit is combusting fuel at conditions
of typical stack temperature and pressure. A clarifying statement would
be added to section 6.2 of Appendix A, indicating that the unit does
not have to be generating electricity during the test. But EPA would
continue to require that a linearity test be performed while the unit
is combusting fuel at conditions of typical stack temperature and
pressure in order to test the monitoring system under the same
conditions as when the monitor is measuring emissions, in order to
account for any temperature and pressure effects. An on-line linearity
test challenges a CEMS while it is in equilibrium with the stack
environment and has been sampling stack gas continuously for a period
of time.
2. Linearity Test Frequency
The Agency proposes instead to add flexibility to the linearity
test requirements by changing the basis upon which the frequency of
linearity tests is determined and by providing a linearity grace
period. In today's proposal, section 2.2 of Appendix B would be revised
to require that a linearity test be performed in each ``QA operating
quarter'' rather than in each ``unit operating quarter'' or ``bypass
stack operating quarter.'' For linearity tests, a QA operating quarter
would be defined in the same way as for RATAs, i.e., as a calendar
quarter in which the unit operates for at least 168 hours (or, for
common stacks, a quarter in which effluent gases discharge through the
stack for at least 168 hours). EPA believes that the QA operating
quarter methodology would, in most instances, enable the owner or
operator of a peaking unit or other infrequently operated unit to
complete an on-line linearity test within the calendar quarter in which
it is due. However, the following additional changes would be made to
further ensure that the linearity test requirements can be met: (1) the
requirement to perform successive linearity tests at least 2 months
apart would be reduced to allow successive tests to be done one month
(30 days) apart; and (2) a new section, 2.2.4, would be added to
Appendix B, providing a 168 unit operating hour grace period after the
end of each QA operating quarter in which to complete the required
test. Thus, to make it easier for infrequently operated units to
complete the required linearity tests in the quarters in which they are
due, the required waiting time between successive linearity tests would
be reduced. And, if circumstances should prevent a linearity test from
being completed in the QA operating quarter in which it is due, the
test could be done during the grace period. If the required linearity
test were not completed by the end of the grace period, data from the
monitor would be considered invalid from the hour after the grace
period expires until the hour of completion of a subsequent successful
linearity test.
For infrequently operated units, certain calendar quarters would
not qualify as QA operating quarters. Therefore, in accordance with
today's proposed rule, no linearity tests would be required in those
quarters. However, this exemption from linearity testing would not be
without limit. Proposed section 2.2.2 of Appendix B would allow no more
than four consecutive calendar quarters to elapse following the quarter
in which the last linearity test was conducted, without a subsequent
linearity test having to be performed. That is, a linearity test would
either have to be done by the end of the fourth consecutive elapsed
calendar quarter since the last test or within a 168 unit operating
hour grace period after the end of the fourth consecutive elapsed
quarter. Data from the monitor would become invalid if the linearity
test was not completed by the end of the grace period and would remain
invalid until a linearity test was successfully completed.
Today's proposal would also change the requirement for units with
two span values for a particular parameter (e.g., units with add-on
SO2 controls) to perform quarterly linearity tests on both
the low and high monitor ranges. Section 2.2.1 of Appendix B would be
revised to require a linearity test of a monitor range only if that
range is used to report data during the QA operating quarter. However,
under proposed section 2.2.3(e) of Appendix B, at least one linearity
test of each range would still be required every four calendar quarters
to maintain data validation on the range.
3. Linearity Test Method
Today's proposal would add two new requirements to section 6.2 of
Appendix A: (1) that all linearity tests must be done ``hands-off,''
meaning that no adjustments of the CEMS other than certain calibration
error adjustments would be permitted prior to or during the linearity
test period; and (2) to the extent practicable, each linearity test
would have to be completed within a period of 24 unit operating hours.
These proposed provisions are intended to ensure greater consistency in
the way in which linearity tests are conducted and to ensure that the
tests are completed in a timely manner. The allowable calibration
adjustments prior to and during a linearity test would be defined in
proposed section 2.1.3 of Appendix B. For a further discussion, see
Section O of this preamble, ``CEM Data Validation,'' below.
4. Exemptions
Finally, section 6.2 of Appendix A would be revised to exempt
SO2 and NOX monitors with span values of 30 ppm
or less from the linearity test requirements of part 75. At these low
span values, the linearity test begins to lose its significance. For
example, typical low, mid, and high calibration gases for a span value
of 30.0 ppm would be 24.0 ppm, 18.0 ppm, and 9.0 ppm, respectively. The
appropriate linearity performance specification in section 3.2 of
Appendix A is 5.0 ppm at each calibration gas level.
Therefore, in this illustration, the monitor reading could be 14.0 ppm
for both the ``low'' and ``mid'' gases or 20.0 ppm for both the ``mid''
and ``high'' gases. Even though a valid straight line comparing the
reference gas concentrations and the monitor readings cannot be
constructed from such data, the monitor would still appear to pass the
linearity test.
M. Flow-to-Load Test
Background
The current quality assurance requirements for flow rate monitoring
systems in Appendices A and B to part 75 include daily calibration
error tests, daily interference checks, quarterly leak checks (for
differential pressure type monitors only), and semiannual or annual
relative accuracy test audits. 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 purports to check flow monitor
accuracy, but, as explained below, the ability of the test to
accomplish this objective is somewhat questionable.
There is a distinct difference between the daily calibration error
test of a flow rate monitor and the calibration error test of a gas
monitor. To calibrate a gas monitor, a protocol gas of known
concentration is sent through the monitoring system and analyzed. This
generally serves as a reliable indicator of the system's ability to
accurately measure pollutant or diluent gas concentrations, because the
calibration closely simulates the sampling and analysis of stack gas by
the monitoring
[[Page 28062]]
system. A flow monitor calibration error test, on the other hand, does
not provide the same level of assurance of data quality. Generally, a
flow monitor calibration 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 is not a ``true'' calibration of the monitor, since it does not
evaluate the system's ability to measure an actual stack gas flow rate.
In order to perform true daily flow monitor calibrations, two reference
stack gas flow rates would have to be generated and measured. Practical
considerations preclude such calibrations from being done, however,
because the unit load level would have to be significantly varied
during each operating day, and suitable reference method measurements
(e.g., velocity traverses using EPA Method 2) would have to be made
daily at each calibration load level.
Because of the limited usefulness of the flow monitor daily
calibration error test, 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. For instance, the
sensors of DP and thermal-type monitors are subject to plugging and/or
fouling, which will cause the monitors to read lower than true and can
result in under-reporting of emissions. One utility observed a
substantial increase in the readings from its flow monitor after the
sensors were cleaned during a unit outage. Apparently, the sensor
problems had not been detected by the daily calibration error tests
(see Docket A-97-35, Item II-E-29). A second utility experienced a
gradual deterioration of the monitor's performance in the 9-month
period following the RATA. By the sixth month (at load levels and
CO2 concentrations virtually identical to the conditions at
the time of the RATA), the flow monitor readings were consistently 15.0
to 20.0 percent lower than the baseline average flow rate measured by
EPA Reference Method 2 during the RATA. However, during the 9-month
period, the flow monitor had consistently passed its daily calibration
error tests (see Docket A-97-35, Item II-B-11). During a State
inspection of a third utility, the inspector observed a consistent 20.0
to 30.0 percent difference between the hourly flow rates measured by
the primary and redundant backup flow monitors even though both
monitors had been passing their daily calibration error tests. In this
instance, the primary flow monitor was being used for data reporting
and was reading higher than the redundant backup monitor; therefore, it
is unlikely that emissions were being under-reported. Had the primary
monitor malfunctioned and the redundant backup been used, however,
emissions would have been significantly under-reported (see Docket A-
97-35, Item II-B-10).
Discussion of Proposed Changes
In view of the apparent shortcomings of the flow monitor daily
calibration error test, EPA proposes to add a new flow monitor quality
assurance test, the ``flow-to-load test,'' to part 75. The flow-to-load
test, which would be performed quarterly, is described in proposed
sections 7.7 of Appendix A and 2.2.5 of Appendix B. The proposed
quarterly flow-to-load test would be required beginning in the first
quarter of the year 2000.
The basic premise of the flow-to-load 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 (see Docket A-97-35, Items II-B-9, II-D-69).
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 (see Docket A-97-35, Items
II-B-9, II-D-73, II-D-74, II-D-76, II-D-83, II-D-84). The flow-to-load
ratio, or a normalized ratio, can thus serve as a quantitative
indicator of flow monitor accuracy from quarter to quarter until the
next RATA is performed.
The quarterly flow-to-load ratio test would be conducted as
follows. The owner or operator would be required to determine
Rref, a reference value of the ratio of flow rate to unit
load, each time that a successful normal-load flow RATA is performed.
The value of Rref would be reported in the electronic
quarterly report required under Sec. 75.64, along with the completion
date of the associated RATA. If two load levels (e.g., mid and high)
are designated as normal, the owner or operator would determine a
separate Rref value for each normal load level. The
reference flow-to-load ratio would be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TP21MY98.059
In the equation above, Rref is the reference value of
the flow-to-load ratio from the most recent normal-load flow RATA;
Qref is the average stack gas volumetric flow rate (in scfh)
measured by the reference method during the normal-load RATA; and
Lavg is the average unit load during the normal-load flow
RATA. For a common stack, Lavg would be the sum of the
operating loads of all units that discharge through the stack. For a
unit that discharges its emissions through multiple stacks or ducts,
Qref would be the sum of the total volumetric flowrates that
discharge through all of the stacks (or ducts). The reference flow-to-
load ratio would be rounded off to 2 decimal places.
As an alternative, the owner or operator could calculate a
reference value of the gross heat rate (GHR) in lieu of
Rref. In order to exercise this option, quality assured
diluent gas (CO2 or O2) data would have to be
available for each hour of the most recent normal-load flow RATA. The
reference value of the GHR would be determined as follows:
[GRAPHIC] [TIFF OMITTED] TP21MY98.060
In the equation above, (GHR)ref is the reference value
of the gross heat rate at the time of the most recent normal-load flow
RATA; (Heat Input)avg is the arithmetic average hourly heat
input during the normal-load flow RATA; and Lavg is the
average unit load during the normal-load flow RATA. In calculating
(Heat Input)avg, the average volumetric flow rate measured
by the reference method during the RATA would be used in conjunction
with the average diluent gas concentration measured during the RATA,
substituting these values into the applicable heat input equation in
Appendix F.
After establishing the reference flow-to-load or GHR value, an
evaluation of the flow-to-load ratio or GHR would be required for each
primary and redundant backup flow monitor on a quarterly basis. The
owner or operator would be required to evaluate the flow-to-load ratio
in each ``QA operating quarter'' (i.e., each quarter in which the unit
or stack operates for at least 168 hours). At the end of each QA
operating quarter, the owner or operator would calculate the flow-to-
load ratio for every hour during the quarter in which: (1) the unit (or
combination of units, for a common stack) operated within
10.0 percent of Lavg, the average load during
the most recent normal-load flow
[[Page 28063]]
RATA; and (2) a quality assured hourly average flow rate was obtained
with a certified flow rate monitor. The owner or operator would have
the option of using either bias-adjusted flow rates or unadjusted flow
rates in the hourly flow-to-load ratios, provided that all of the
ratios were calculated the same way. EPA had originally considered
proposing that only unadjusted flow rates should be used to calculate
the flow-to-load ratios. However, in response to comments received from
CEMS Utility Workgroup members, the Agency is proposing to allow either
unadjusted or bias-adjusted flow rates to be used, on the condition
that the acceptance criteria for the flow-to-load test would be more
stringent if bias-adjusted flow rates are used (see Docket A-97-35,
Item II-D-82).
For a common stack, the ``load'' in each hourly flow-to-load ratio
would be the sum of the hourly operating loads of all units that
discharge through the stack. For a unit that discharges its emissions
through multiple stacks (or for a unit that monitors total flow rate in
multiple ducts or breechings), the ``flow'' in the flow-to-load ratio
would be the combined hourly volumetric flow rate through all of the
stacks (or ducts). Each hourly flow-to-load ratio would be rounded off
to 2 decimal places.
Alternatively, the owner or operator could calculate the hourly
gross heat rate (GHR) values in lieu of the hourly flow-to-load ratios.
However, an hourly GHR could only be determined for those hours within
10.0
for which quality assured flow rate and diluent gas (CO2 or
O2) concentration data are available from a certified CEMS
or reference method. The owner or operator could use either bias-
adjusted flow rates or unadjusted flow rates to determine the hourly
GHR values.
The calculated hourly flow-to-load ratios (or gross heat rates)
would be analyzed at the end of the quarter. A separate data analysis
would be performed for each primary and each redundant backup flow rate
monitor used to record and report data during the quarter. Each
analysis would be based on a minimum of 168 hours of data. If two RATA
load levels are designated as normal, the analysis would be performed
at the higher load unless fewer than 168 data points were available at
that load, in which case, the analysis would be performed at the lower
load. If, for a particular flow monitor, fewer than 168 hourly flow-to-
load ratios (or GHR values) were available at any normal load level, a
flow-to-load (or GHR) evaluation would not be required for that monitor
for that calendar quarter.
For each flow monitor, Eh, the difference (absolute
value) between each hourly flow-to-load ratio and Rref,
would be expressed as a percentage of Rref (or, if the GHR
is used, the absolute difference between each hourly GHR value and
(GHR)ref would be expressed as a percentage of
(GHR)ref). Then, Ef, the arithmetic average of
all of the Eh values, would be calculated. Note that
Rref would always be based upon the most recent normal-load
RATA, even if that RATA was performed in the calendar quarter being
evaluated.
The owner or operator would be required to report the results of
each quarterly flow-to-load (or GHR) evaluation in the electronic
quarterly report required under Sec. 75.64. The results of a quarterly
flow-to-load (or GHR) evaluation would be considered acceptable, and no
further action would be required if the average absolute percentage
difference (Ef) did not exceed the following limits:
(i) 15.0 percent, if Lavg for the most recent normal
load flow RATA is 50 megawatts (or 500 klb/hr
of steam) and if unadjusted flow rates were used in the calculations;
(ii) 10.0 percent, if Lavg for the most recent normal
load flow RATA is 50 megawatts (or 500 klb/hr
of steam) and if bias-adjusted flow rates were used in the
calculations;
(iii) 20.0 percent, if Lavg for the most recent normal
load flow RATA is < 50 megawatts (or < 500 klb/hr of steam) and if
unadjusted flow rates were used in the calculations;
(iv) 15.0 percent, if Lavg for the most recent normal
load flow RATA is < 50 megawatts (or < 500 klb/hr of steam) and if
bias-adjusted flow rates were used in the calculations.
If Ef exceeded the applicable limit, the owner or
operator would have two available options: (1) perform a RATA, as
described in proposed section 2.2.5.2 of Appendix B, unless a monitor
malfunction is diagnosed and corrected, in which case an abbreviated
flow-to-load test could be performed, in lieu of a RATA, in accordance
with section 2.2.5.3 of Appendix B and discussed below; or (2) re-
examine the hourly data used for the flow-to-load or GHR analysis and
recalculate Ef, after excluding all non-representative
hourly flow rates. If the owner or operator were to choose option (2),
i.e., to recalculate Ef, only the flow rates for the
following hours would be considered non-representative and could be
excluded from the data analysis:
(1) Any hour in which the type of fuel combusted was different from
the fuel burned during the most recent normal-load RATA. The type of
fuel would be different if the fuel is in a different state of matter
(i.e., solid, liquid, or gas) or is a different classification of coal
(e.g., bituminous versus sub-bituminous) than the fuel burned during
the RATA;
(2) Any hour in which an SO2 scrubber was bypassed;
(3) Any hour in which ``ramping'' occurred, i.e., the hourly load
differed by more than + 15.0 percent from the load during the preceding
hour or the subsequent hour;
(4) If a normal-load flow RATA was performed and passed during the
quarter being analyzed, any hour prior to completion of that RATA; and
(5) If a problem with the accuracy of the flow monitor was
discovered during the quarter and corrected, any hour prior to
completion of the subsequent diagnostic test described in proposed
section 2.2.5.3 of Appendix B, confirming that the corrective actions
were successful.
After identifying and excluding any non-representative hourly data
in accordance with (1) through (5) above, the owner or operator could
analyze the remaining data a second time. At least 168 representative
hourly ratios or GHR values at normal load would have to remain in
order to perform the analysis; otherwise, the flow-to-load (or GHR)
analysis would not be required for that monitor for that calendar
quarter.
If, after re-analyzing the data, Ef is found to be
within the applicable limit in (i), (ii), (iii), or (iv), above, then
no further action would be required. However, if Ef is still
outside the applicable limit, the monitor would be declared out-of-
control as of the first hour of the quarter following the quarter in
which the flow-to-load test was failed. The owner or operator would
then perform a RATA as described in proposed section 2.2.5.2 of
Appendix B, unless, as the result of an investigation, an instrument
malfunction is discovered and corrected as described in proposed
section 2.2.5.1 of Appendix B.
If a problem with the monitor is identified, all corrective actions
(e.g., non-routine maintenance, repairs, major component replacements,
re-linearization of the monitor, etc.) would have to be documented in
the operation and maintenance records for the monitor. Data from the
monitor would remain invalid until a ``probationary'' calibration error
test of the monitor was passed following completion of all corrective
actions, at which point data from the monitor would be assigned a
``conditionally valid'' status. The owner or operator would then
perform an abbreviated flow-to-load test (found in proposed section
2.2.5.3 of Appendix B) to verify that the corrective actions were
[[Page 28064]]
effective, unless the linearity of the flow monitor was affected by the
corrective actions (e.g., by the changing of its polynomial
coefficients). If the flow monitor linearity was affected, the owner or
operator would no longer have the option of performing the abbreviated
flow-to-load test in section 2.2.5.3 of Appendix B, but would instead
be required to perform a 3-load recertification RATA in accordance with
the recertification test period and data validation procedures of
Sec. 75.20(b)(3).
The abbreviated flow-to-load test in proposed section 2.2.5.3 of
Appendix B is based on a recertification policy developed jointly by
EPA, several utility representatives, and one flow monitor vendor (see
Docket A-97-35, Items II-B-1, II-D-70, II-I-9, and II-I-16). Use of the
abbreviated flow-to-load test would not be limited to situations in
which a quarterly flow-to-load test has been failed. Rather, the test
could be performed after any documented repair, component replacement,
or other corrective maintenance to a flow monitor (except for changes
affecting the linearity of the flow monitor, such as adjusting the flow
monitor coefficients) to demonstrate that the repair, replacement, or
other corrective maintenance has not significantly affected the
monitor's ability to accurately measure the stack gas volumetric flow
rate. Data from the monitoring system would be considered invalid from
the hour of commencement of the repair, replacement, or other
corrective maintenance until the hour in which a ``probationary''
calibration error test is passed following completion of the repair,
replacement, or other corrective maintenance and any associated
adjustments to the monitor. The abbreviated flow-to-load test would
have to be completed within 168 unit operating hours of the
probationary calibration error test (or, for peaking units, within 30
unit operating days, if that is less restrictive). Data from the
monitor would be considered ``conditionally valid'' (as defined in
Sec. 72.2) beginning with the hour of the probationary calibration
error test.
Following a flow-to-load test failure, the abbreviated flow-to-load
test could be performed if the investigation into the cause of the test
failure revealed a problem with the flow monitor and the problem was
subsequently corrected without having to re-linearize the flow monitor.
The test procedures would be as follows. The unit(s) would be operated
in such a way as to reproduce, as closely as practicable, the exact
conditions at the time of the most recent normal load flow RATA. To
achieve this, the load should be held constant to within
5.0 percent of the average load during the RATA, and the diluent gas
(CO2 or O2) concentration should be maintained
within 0.5 percent CO2 or O2 of the
average diluent concentration during the RATA. For common stacks, to
the extent possible, the same combination of units and load levels that
were used during the RATA should be used. When the process parameters
have been set, a minimum of 6 and a maximum of 12 consecutive hourly
average flow rates would be recorded using the flow monitor(s) for
which Ef was outside the applicable limit. For peaking
units, a minimum of 3 and a maximum of 12 consecutive hourly average
flow rates would be required. The corresponding hourly load values and,
if applicable, the hourly diluent gas concentrations would also be
recorded. The flow-to-load ratio or the GHR would be calculated for
each hour in the test hour period using proposed Equation B-1 or B-1a
in Appendix B. Then, Eh would be determined for each hourly
flow-to-load ratio or GHR using proposed Equation B-2 in Appendix B.
Finally, Ef , the arithmetic average of the Eh
values, would be determined.
The results of the abbreviated flow-to-load test would be
considered acceptable, and no further action would be required if the
value of Ef did not exceed the applicable limit specified in
proposed section 2.2.5.1 of Appendix B. All conditionally valid data
recorded by the flow monitor would then be considered quality assured,
beginning with the hour of the probationary calibration error test that
preceded the abbreviated flow-to-load test. However, if Ef
was found to be above the applicable limit, all conditionally valid
data recorded by the flow monitor would be considered invalid back to
the hour of the probationary calibration error test that preceded the
abbreviated flow-to-load test, and a single-load RATA would be
required, in accordance with proposed section 2.2.5.2 of Appendix B.
When a single-load RATA is performed because the owner or operator
is unable to reconcile a quarterly flow-to-load test failure, either by
excluding non-representative hours and recalculating Ef or
by passing the abbreviated flow-to-load test after performing component
replacement or other corrective maintenance on the flow monitor, then
data from the monitor would remain invalid until the hour of successful
completion of the single-load RATA.
Rationale
EPA believes that the proposed methodology for the quarterly flow-
to-load test is fundamentally sound. It has been developed through a
series of teleconferences and face-to-face meetings between EPA,
members of the regulated community, and State and local agency
personnel (see Docket A-97-35, Items II-D-77, II-D-80, II-D-81, II-D-
82, II-D-85, II-E-23, II-E-24, II-E-25, II-E-26, and II-E-28). In
addition, some provisions of the flow-to-load test were revised
following pre-proposal comment. Specifically, the proposal reflects, in
section 2.2.5.1 (b) of Appendix B to part 75, a commenter's request
that if a quarterly flow-to-load test is failed and the monitor
malfunction is discovered and corrected (without the need to
relinearize the monitor), the correction could be verified using the
abbreviated flow-to-load test in lieu of performing a single load RATA
(see Docket A-97-35, Item II-D-42).
The proposed tolerance limits set forth in paragraphs (i), (ii),
(iii), and (iv) of section 2.2.5 of Appendix B are believed to be both
reasonable and achievable. When these tolerance limits are met, it
provides a strong indication that the flow monitor is still accurate to
within 10.0 percent of the reference method baseline established during
the last normal-load flow RATA and would, therefore, appear to be in
control with respect to the relative accuracy requirements of part 75.
An extra tolerance of 5.0 percent has been incorporated into the limits
to account for imprecision in the flow-to-load methodology. An extra
5.0 percent tolerance has also been added for smaller units (i.e.,
normal load less than 50 megawatts or 500 klb/hr of steam), because the
flow-to-load ratio or GHR for such units is very sensitive to small
variations in load (see Docket A-97-35, Item II-B-7).
To test the viability of the proposed tolerance limits, 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 (see Docket A-97-35, Items II-A-1,
II-A-2, II-A-3). 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.,
baseloaded and peaking units, single fuel units, and units that burn
multiple fuels). The flow-to-load test was applied to each unit or
stack in the manner described above, except that no hours within
10.0 percent of Lavg were excluded from the
data analysis. The data from these same units plus one additional
multiple-stack unit were
[[Page 28065]]
analyzed a second time, with each flow-to-load ratio being multiplied
by the diluent gas concentration. This is similar, but not identical,
to calculating the GHR. Once again, no hours within 10.0
percent of Lavg were excluded. In both analyses, unadjusted
flow rates were used in the ratios. The results of the two data
analyses were nearly the same. Only one failure of the quarterly flow-
to-load test was observed in each analysis (i.e., the failure rate was
< 5.0 percent). The average value of Ef was 6.1 percent for
the analysis without the diluent gas corrections and 6.4 percent for
the analysis with the diluent gas corrections. A few units and stacks
had a much lower Ef value when the diluent correction was
applied, but in most cases, the diluent correction had relatively
little effect. These results suggest that the flow-to-load test can
provide EPA with the necessary assurance that flow monitors continue to
generate accurate data from one RATA to the next. The results also
indicate that the test should be relatively easy to pass if flow
monitors are properly maintained and operated.
Because of the added quality assurance that would be provided by
performing the flow-to-load or GHR test each quarter, EPA has
reconsidered the scope of the other quality assurance tests for flow
monitors. In today's proposed rule, the Agency is proposing to reduce
the annual 3-load flow RATA requirement to a 2-load RATA and to reduce
the frequency of 3-load RATAs to once every five years (and whenever a
flow monitor is re-linearized). In addition, single-load flow RATA
testing would be allowed in lieu of the annual 2-load test if the
facility could demonstrate that a unit has operated at a single load
level for at least 85.0 percent of the time in the four ``QA operating
quarters'' prior to the scheduled RATA. (See Section N.2 of this
preamble, below, for further discussion.) The Agency believes that,
taken together, these proposed changes will reduce the cost and burden
of quality assurance testing for flow monitors, while ensuring high
data quality. The proposed reduction in the amount of required RATA
testing is considered feasible because of the increased quality
assurance provided by the quarterly flow-to-load test. EPA requests
comment on the proposed revisions to flow monitor quality assurance
requirements.
N. RATA and Bias Test Requirements
Background
Section 6.5 of Appendix A to the January 11, 1993 rule, as amended
on May 17, 1995 and November 20, 1996, requires relative accuracy test
audits of all primary and redundant backup SO2,
NOX, CO2, and flow monitoring systems to be
performed during the initial certification of the CEMS. A RATA consists
of a series of 9 or more simultaneous test runs, comparing measurements
made by the continuous monitoring system against an EPA reference test
method. The procedures for conducting RATAs are found in section 6.5 of
Appendix A to part 75.
Following the initial certification of a CEMS, section 2.3 of
Appendix B to part 75 requires that periodic RATAs of gas and flow
monitors be performed to quality assure the data from the CEMS on an
on-going basis. The frequency at which relative accuracy testing is
required depends upon the results of the last RATA of a monitoring
system. Part 75 currently requires RATAs to be performed semiannually,
unless a monitoring system achieves a low enough relative accuracy to
qualify for an annual test frequency. The Agency has always interpreted
``semiannually'' to mean that the deadline for the next RATA is the end
of the second calendar quarter following the quarter in which a RATA is
successfully completed, and ``annually'' to mean that the next RATA is
due by the end of the fourth calendar quarter following the quarter in
which a RATA is successfully completed. For monitors installed on
peaking units and bypass stacks, however, the RATA deadlines are based
on operating quarters, not calendar quarters. That is, the next RATA is
due either at the end of the second or fourth unit operating quarter
(for peaking units) or bypass stack operating quarter following the
quarter in which a RATA is successfully completed.
For SO2, NOX, and CO2 monitors,
the RATAs are to be conducted while the unit is operating at normal
load and while combusting the fuel that is normal for the unit. Flow
monitor RATAs are to be conducted at three different loads, evenly
spaced over the operating range of the unit. When a flow monitor is on
a semiannual RATA frequency, a normal-load RATA rather than a 3-load
RATA may be conducted to satisfy the semiannual test requirement, but a
3-load RATA is still required annually. Note that for flow monitors
installed on peaking units and bypass stacks, 3-level flow RATAs are
not required; RATAs are performed only at the normal load.
For SO2, NOX, and flow monitoring systems,
section 7.6 of Appendix A requires that each time a RATA is
successfully completed, a bias test be performed to determine if the
system has a low measurement bias. If a monitoring system fails the
bias test, a ``bias adjustment factor'' (BAF) must be applied to all
subsequent emission data reported from that monitoring system. For 3-
load flow RATAs, the bias test is done at the normal load. If a flow
monitor fails the normal-load bias test, then a BAF must be calculated
at each of the three load levels, and the highest of the three BAFs is
applied to all flow data reported from the monitor.
When a RATA is due, section 2.3.1 in Appendix B of the rule allows
the owner or operator two attempts to achieve an annual RATA frequency
and/or a favorable BAF. If a second attempt is made, the RATA frequency
and BAF obtained in the second RATA supersede the results of the first
RATA. Once the RATA frequency has been established as semiannual or
annual, section 2.3.1 of Appendix B specifies that (to the extent
practicable) the next RATA of the CEMS may not be done until at least
four months have elapsed.
Finally, Sec. 75.21(a)(6) of the November 20, 1996 rule provides an
exemption from the RATA requirements of part 75 for SO2
monitors installed on units that burn only natural gas or fuel with a
sulfur content no greater than natural gas. For units that burn both
gas and higher-sulfur fuel, such as oil, as primary or backup fuels,
Sec. 75.21(a)(5) requires that the RATA of the SO2 monitor
be done when the higher-sulfur fuel is burned. Section 75.21(a)(7)
further states that calendar quarters in which only fuel with a sulfur
content no greater than natural gas is burned are to be excluded in
determining the deadline for the next SO2 monitor RATA.
Two utility groups, UARG and the Class of '85, have requested that
EPA consider revising the RATA requirements of part 75 to make them
more flexible, easier with which to comply, and less costly. Some of
the possible changes suggested by these groups are as follows: (1)
reduce the frequency of required RATAs; (2) determine RATA deadlines
based on the amount of unit operation since the last RATA, rather than
the number of calendar quarters that have elapsed; (3) remove the
requirement to achieve a more stringent relative accuracy standard in
order to obtain an annual RATA frequency; (4) except for initial
certification, allow flow RATAs to be done at a single load; (5) allow
single-point sampling during gas RATAs; and (6) allow a grace period in
which to complete a RATA whenever a deadline is not met (see Docket A-
97-35, items II-D-20, II-D-30, II-D-65, II-E-13, II-E-14).
[[Page 28066]]
Discussion of Proposed Changes
EPA is proposing revisions to the RATA requirements of part 75
based upon experience gained through implementation of the rule and in
light of the recommendations made by the utility groups. Today's
rulemaking sets forth the proposed changes, which are intended to make
the RATA requirements less burdensome without sacrificing data quality.
1. RATA Frequency
EPA does not propose to revise the basic semiannual and annual RATA
requirements of part 75 or the incentive system by which to obtain an
annual RATA frequency (i.e., to obtain the reduced frequency, a better
percentage relative accuracy is required). Instead, the Agency proposes
to re-define the terms ``semiannual RATA frequency'' and ``annual RATA
frequency,'' and to change the method by which RATA deadlines are
determined.
Today's rule proposes to amend section 2.3 of Appendix B so that
the deadline for the next RATA is determined on the basis of ``quality
assurance operating quarters,'' rather than calendar quarters. This
change would apply, with few exceptions, to all primary and redundant
backup monitoring systems, including monitors installed on peaking
units and bypass stacks. A ``QA operating quarter'' would be defined as
a calendar quarter in which a unit operates for at least 168 hours or,
for common-stacks and bypass stacks, a quarter in which flue gases
discharge through the stack for at least 168 hours.
Any calendar quarter that does not qualify as a QA operating
quarter would be excluded in determining the deadline for the next
RATA. EPA therefore proposes to re-define the term ``semiannual RATA
frequency'' to mean that the next RATA is due at the end of the second
QA operating quarter following the quarter in which a RATA is
successfully completed. Similarly, ``annual RATA frequency'' would mean
that the next RATA is due at the end of the fourth QA operating quarter
following the quarter in which a RATA is successfully completed.
The QA operating quarter methodology has been proposed principally
for the benefit of cycling and peaking units to make the part 75 RATA
requirements easier to meet. The proposed methodology will not greatly
affect base-loaded units, since they seldom operate for less than 168
hours in a quarter. For base-loaded units, the QA operating quarter
method is, in most instances, equivalent to the familiar calendar
quarter scheme for determining RATA deadlines. Note, however, that on
occasion a base-loaded unit may obtain an extended RATA deadline by the
QA operating quarter methodology, e.g., when the unit goes into an
extended outage (planned or forced) and experiences one or more
quarters in which the unit operates for less than 168 hours.
Although the QA operating quarter method allows RATA deadlines to
be extended by the exclusion of quarters in which the unit(s) operate
for less than 168 hours, such exclusion of calendar quarters is not
without limit. Section 2.3.1.1 of Appendix B proposes to allow a
maximum of eight consecutive calendar quarters to elapse following the
quarter in which the last RATA was performed. A RATA would either have
to be performed by the end of the eighth consecutive elapsed calendar
quarter since the last RATA or within a 720 unit operating hour ``grace
period'' following the end of the eighth consecutive elapsed quarter.
Failure to complete a RATA within the grace period would cause data
from the monitoring system to become invalid from the hour of
expiration of the grace period until the hour of completion of a
successful RATA.
Although the proposed QA operating quarter methodology would serve
as the basis for determining the RATA deadline for most routine quality
assurance RATAs, there are five notable instances in the current rule
or in today's proposal where the RATA deadline is either not determined
solely on that basis or is determined entirely on another basis. The
first instance is for a unit that burns both natural gas (or fuel with
equivalent total sulfur content) and other higher-sulfur fuels as
primary or backup fuels and that uses an SO2 monitor to
account for SO2 mass emissions. Section 75.21(a)(7) of the
current part 75 (redesignated as Sec. 75.21(a)(9) in today's proposal)
specifies that irrespective of the number of hours of unit operation in
the quarter, any calendar quarter in which natural gas (or fuel with a
total sulfur content no greater than the total sulfur content of
natural gas) is the only fuel combusted in the unit (i.e., a ``gas-
only'' quarter) is to be excluded in determining the deadline for the
next RATA of the SO2 monitoring system. Section 75.21(a)(5)
of the current rule further states that for such units, the RATA of an
SO2 monitoring system is to be performed only when the
higher-sulfur fuel is being combusted. Second, as discussed in section
III.N.6 of this preamble, Sec. 75.21(a)(7) of today's proposed rule
would conditionally exempt from SO2 RATA requirements any
unit certified by the designated representative to burn fuel(s) with a
sulfur content greater than natural gas only as emergency backup fuel
or for short-term testing, provided that the annual usage of the
higher-sulfur fuel(s) is kept below 480 hours. However if, during any
quarter, the annual usage of the higher-sulfur fuel exceeded 480 hours,
an SO2 RATA would be required either in that quarter or
during a subsequent grace period. Thus, for RATAs of SO2
monitoring systems, it is evident that the number of unit operating
hours in a calendar quarter is not the only consideration that
determines the deadline for the next RATA; the total sulfur content of
the fuel being combusted must also be considered. Third, as discussed
in section III.O.6 of this preamble, for certain non-redundant backup
monitoring systems, Sec. 75.20(d) of today's proposal would require a
periodic RATA every eight calendar quarters (rather than QA operating
quarters). Fourth, as discussed in section III.N.2 of this preamble,
under section 2.3.1.3 of Appendix B in today's proposal, 3-level flow
RATAs would have to be performed once in every period of five
consecutive calendar years (e.g., prior to permit renewal) and whenever
a flow monitor is re-linearized. Fifth, as discussed in section III.O.4
of this preamble, for recertification RATAs, which are not regularly
scheduled tests, but are done on an ``as-required'' basis,
Sec. 75.20(b)(3) of today's proposal specifies that the deadline for
completing such RATAs would be 720 unit operating hours after the start
of the recertification test period.
2. RATA Load Levels
Today's proposed rule would more clearly define the load levels at
which RATAs are done in order to provide greater consistency in the way
that RATAs are performed. The current provisions of part 75 are neither
sufficiently standardized nor clear in defining the appropriate RATA
load levels, particularly for flow RATAs. For example, section 6.5.2 of
Appendix A specifies 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. Also, there is no minimum required
load separation between the audit points at adjacent load levels. If
adjacent audit points are too close together, a 3-level flow evaluation
loses its significance. Finally, while the current rule requires gas
and flow RATAs to be conducted at normal
[[Page 28067]]
load, no definition of normal load is provided. It could be inferred
from the current section 6.5.2 of Appendix A that the ``mid'' load
level is considered normal because it requires the 3-load RATA to be
done at a frequently used low load, a frequently used high operating
load, and a normal load. However, experience in implementing the
program has shown that for many units, the high load level is
considered normal by the facility. For a few units, low load is
considered normal, and for still others, the normal load can depend
upon the time of day or the season of the year.
Proposed section 6.5.2.1 of Appendix A would therefore require the
owner or operator first to define the ``range of operation'' for each
unit or common stack equipped with hardware CEMS. The range of
operation would extend from the minimum safe, stable load to the
``maximum sustainable load,'' which is the higher of: (a) the nameplate
capacity of the unit (less any physical or regulatory deratings), or
(b) the highest sustainable load, based on at least four quarters of
representative historical data. For a common stack, the lower boundary
of the range of operation would be the lowest minimum safe, stable load
for any of the individual units using the stack. The upper boundary of
the range would be obtained by adding together the maximum sustainable
loads of all units using the stack, or if that combined load is
unattainable in practice, by using the highest sustainable combined
load based on at least four quarters of representative historical data.
Three load levels would then be defined in terms of the range of
operation. The ``low'' level would be the lower 30.0 percent of the
range; the ``mid'' level would be the central portion (30.0 percent to
60.0 percent) of the range; and the ``high'' level would be 60.0
percent to 100.0 percent of the range. Proposed section 6.5.2 of
Appendix A would specify that for multi-level flow RATAs, the audit
points at adjacent load levels (e.g., low and mid, or mid and high)
must be separated by no less than 25.0 percent of the range of
operation. The owner or operator would be required to report the upper
and lower boundaries of the range of operation in the electronic
quarterly report required under Sec. 75.64.
Section 6.5.2.1 of Appendix A in today's proposal would further
require the owner or operator to determine, for each unit or common
stack on which CEMs are installed (except for peaking units), the two
load levels (low, mid, or high) that are the most frequently used. The
two-fold purpose of this determination, which would be required, at a
minimum, annually (just prior to the annual quality assurance RATAs and
in the same calendar quarter as the RATAs), would be to identify the
normal load level(s) and to identify the two load levels that are the
most appropriate for annual 2-level flow monitor audits and for flow
monitor bias adjustment factor calculations. To make the determination,
the owner or operator would construct an historical load frequency
distribution (e.g., histogram), depicting the relative number of
operating hours at each of the three load levels, low, mid, and high.
The frequency distribution would be based upon all available data from
the four most recent QA operating quarters, as defined in proposed
section 2.3.1.1 of Appendix B. The load frequency distribution would be
used to determine the percentage of the time (to the nearest 0.1
percent) that each load level (low, mid, and high) has been used in
recent history and thereby to identify the two most frequently used
load levels. A summary of the data used for these determinations would
be maintained on-site in a format suitable for inspection, and the
results of the determinations would be included in the electronic
quarterly report under Sec. 75.64. The proposed revisions discussed in
this paragraph would become effective as of January 1, 2000.
The owner or operator would be required under proposed section
6.5.2.1 of Appendix A to designate the most frequently used load level
(low, mid, or high) as the normal load level for each unit or common
stack (except for peaking units). The owner or operator would also have
the option of designating the second most frequently used load level as
an additional normal load level. Today's proposal would, therefore, not
limit normal load to a single load level. This way of defining normal
load is particularly appropriate for units that operate on a diurnal
cycle and units that operate at distinctly different load levels during
different seasons of the year due to ambient conditions, electrical
demand, etc. EPA believes that the added flexibility in the definition
of normal load (i.e., not confining it to a single load level) will
allow the normal-load RATA requirements of part 75 to be more easily
met. The owner or operator would be required to identify the selected
normal load level(s) in the electronic quarterly report required under
Sec. 75.64. For peaking units, the entire range of operation would, for
simplicity, be considered normal.
Revisions to section 2.3.1.3 of Appendix B are proposed in today's
rule, requiring the routine quality assurance RATAs of flow monitors to
be done as follows. For flow monitors installed on peaking units and
bypass stacks, no changes are proposed; the requirement to perform only
single-load flow RATAs at normal load would be retained. For all other
flow monitors, the routine semiannual and annual RATAs would be done at
2 loads (i.e., the two most frequently used load levels, as identified
in section 6.5.2.1 of Appendix A), with two exceptions: (1) the 2-load
flow RATA could be performed alternately with a single-load flow RATA
at the most frequently used (normal) load level, if the flow monitor is
on a semiannual RATA frequency; and (2) a single-load flow RATA at the
most frequently used load level could be performed in lieu of the 2-
load RATA if, for the four QA operating quarters prior to the quarter
in which the RATA is conducted, the historical load frequency
distribution constructed under section 6.5.2.1 of Appendix A shows that
the unit has operated at the most frequently used load level for
85.0 percent of the time. For all units, the requirement to
perform periodic 3-load flow RATAs would be retained, but the frequency
would be changed from annual to once every five calendar years. A 3-
load RATA would also be required whenever a flow monitor is re-
linearized (i.e., when its polynomial coefficients are changed). EPA is
proposing to reduce the required frequency of 3-load RATAs and to allow
limited use of single-load flow RATA testing principally because of the
added assurance of data quality that will be provided by the proposed
quarterly flow-to-load test.
3. Flow Monitor Bias Adjustment Factors
Today's rulemaking proposes to change the method of determining the
bias adjustment factor for multiple-load flow RATAs. For 2-load RATAs
(which would be done at the two most frequently used load levels as
identified in proposed section 6.5.2.1 of Appendix A), the bias test
would be done at the load level (or levels) designated as normal. If
the monitor were to fail the bias test at any load level designated as
normal, a bias adjustment factor (BAF) would be calculated at both load
levels, and the higher of the two BAFs would then be applied to the
subsequent flow data. For 3-load RATAs, the bias test would be required
at each load level designated as normal under proposed section 6.5.2.1
of Appendix A. If the bias test were failed at any load level
designated as normal, BAFs would be calculated only at the two most
frequently used load levels (not all three
[[Page 28068]]
levels), and the higher of the two BAFs would be applied to subsequent
flow data. Thus, for all multiple-load flow RATAs, the appropriate BAF
would be determined in the same way. For 3-load RATAs, this methodology
for determining the BAF when the normal-load bias test is failed
differs from the current rule, which requires the highest BAF from any
of the three levels to be applied to subsequent data. Experience gained
in the first few years of program implementation has shown that in many
instances, the highest BAF has been from a load level that is seldom
used (generally the low load level), which can result in an
unrepresentatively high BAF being applied to the normal-load flow rate
data.
4. Number of RATA Attempts
Section 2.3.1.4 of Appendix B to today's proposed rule would remove
the restriction limiting to two the number of RATA attempts that may be
done to achieve an annual RATA frequency. In addition, the requirement
that successive RATAs be conducted no less than 4 months apart would be
removed from section 2.3.1 of Appendix B. The proposed rule would
conditionally allow the owner or operator to perform as many RATAs as
are necessary to achieve a better relative accuracy percentage or a
more favorable bias adjustment factor, the condition being that the
data validation procedures for RATAs in proposed section 2.3.2 of
Appendix B would have to be followed (these procedures are discussed in
detail in Section II.O of this preamble, ``CEM Data Validation''). The
Agency believes that this extra flexibility will provide an incentive
for owners or operators to optimize CEMS performance and to eliminate
bias from their monitoring systems and to reduce the frequency of the
required RATAs.
5. Concurrent SO2 and Flow RATAs
Today's proposed rulemaking would delete the requirement for
concurrent SO2 and flow RATA testing from Sec. 6.5 of
Appendix A. This requirement was included in the January 11, 1993 rule
in order to generate a data base from which EPA could determine the
appropriateness of setting a combined flow rate-SO2 system
relative accuracy specification. Section 3.3.5 of Appendix A was
reserved for this future standard, which, if promulgated, would have
become effective on January 1, 2000. After three years of program
implementation, data collection, and evaluation, however, the Agency
believes it is not appropriate or necessary to propose a combined flow
rate-SO2 system relative accuracy standard. Instead, EPA
believes it would be more appropriate to retain the individual relative
accuracy specifications for the SO2 and flow monitors.
Because the historical relative accuracy percentages of the individual
component monitors have proven to be so low (i.e., average relative
accuracy less than 5.0 percent for the period from the first quarter of
1995 through the second quarter of 1996), the Agency believes that it
is not necessary to promulgate the combined standard (see Docket A-97-
35, Item II-I-27). Data analysis from an EPA study (see Docket A-97-35,
Item II-I-14) indicates that quality assuring the individual component
monitors to 7.5 percent relative accuracy (the RA value needed to
qualify for an annual RATA frequency) effectively ensures that a
combined flow rate-SO2 standard of 10.0 to 15.0 percent
relative accuracy will be consistently achieved. That same study also
indicates that meeting a combined flow rate-SO2 standard of
10.0 percent does not necessarily ensure that the individual component
monitor relative accuracies will be 10.0 percent. In view
of this and given that flow monitors are also used to calculate heat
input and CO2 mass emissions, the Agency believes it is
appropriate to maintain individual relative accuracy standards for the
flow monitor and SO2 monitor. EPA solicits comment on its
proposed treatment of this issue.
6. SO2 RATA Exemptions and Reduced Requirements
Today's proposed rulemaking would clarify the RATA requirements for
units that burn principally natural gas and other very low-sulfur
fuels. In Sec. 75.21(a)(6) of the November 20, 1996 rule, an exemption
from SO2 RATA requirements was provided for units that have
SO2 monitors and exclusively burn natural gas (or fuels with
a sulfur content no greater than natural gas). Today's proposed rule
would clarify this exemption from SO2 RATAs by interpreting
the term ``fuel with a total sulfur content no greater than the total
sulfur content of natural gas'' to mean any type of fuel that has a
total sulfur content of less than or equal to 0.05 percent sulfur by
weight. The rationale for this is as follows. In order to meet the
definition of natural gas in Sec. 72.2, the total sulfur content of the
gas cannot exceed 20 grains/100 scf. When this sulfur content is
converted to a weight percentage, it comes out slightly higher than
0.05 percent sulfur by weight (see Docket A-97-35, Item II-B-14).
Consequently, for a unit that has an SO2 monitor and for
which the designated representative certifies that the unit burns only
fuels (whether solid, liquid, or gaseous) with a total sulfur content
of > 0.05 percent sulfur by weight, the SO2 monitor would be
exempted from the part 75 RATA requirements. The Agency takes comment
on this approach and on whether 0.05 percent sulfur by weight is an
appropriate applicability threshold for fuels other than natural gas.
Finally, Sec. 75.21(a)(7) of today's rule proposes reduced RATA
requirements for units with SO2 monitors for which the
designated representative certifies that the units burn fuel(s) with a
total sulfur content greater than the total sulfur content of natural
gas (e.g., distillate oil) only as emergency backup fuel(s) and/or for
short-term testing. For such units, RATA testing of the SO2
monitor would only be required if fuel with a total sulfur content
greater than the total sulfur content of natural gas (i.e., > 0.05
percent sulfur by weight) is combusted for more than 480 hours in a
calendar year. If the higher-sulfur fuel usage were to exceed 480 hours
in a particular year, then an SO2 RATA, conducted while
burning the higher-sulfur fuel, would be required either by the end of
the quarter in which the exceedance occurred or within a 720 unit
operating hour grace period following that calendar quarter. In this
instance, if the grace period were used, proposed section 2.3.3 in
Appendix B would specify that it would begin with the first unit
operating hour in which the higher-sulfur fuel is combusted in the
unit, following the calendar quarter in which the annual usage of the
higher-sulfur fuel exceeded 480 hours. The 480-hour criterion for
maintaining an SO2 RATA exemption is consistent with many
state and local air permits which contain a similar exemption from
particulate emission testing for gas-fired units that burn oil for only
400 to 500 hours per year (see Docket A-97-35, Item II-E-23). EPA
believes that these provisions would effectively eliminate the need to
start up a unit and/or to burn an infrequently used, uneconomical, and
higher-emitting fuel solely for the purpose of performing a RATA of the
SO2 monitor.
7. QA Provisions for SO2 Monitors, for Natural Gas Firing or
Equivalent
In Sec. 75.11(e) of the November 20, 1996 revisions to part 75,
three SO2 compliance options were promulgated for units with
SO2 CEMS during hours in which only natural gas (or gaseous
fuel with a total sulfur content no greater than the total sulfur
content of natural gas) is burned. One of the compliance options was to
allow the use of an SO2 monitoring system, subject to
[[Page 28069]]
certain restrictions and quality assurance provisions. The restrictions
and QA provisions, which are found at Secs. 75.11(e)(3)(i) through
(iv), are as follows: (i) a calibration gas with a concentration of 0.0
percent of span must be used for daily calibration error tests of the
CEMS; (ii) the response of the monitoring system to the 0.0 percent
calibration gas must be adjusted to read exactly 0.0 ppm each time that
a daily calibration error test is passed; (iii) any hourly average of
less than 2.0 ppm recorded by the SO2 monitor while fuel is
being combusted in the unit(s) (including zero and negative averages)
must be reported as a default value of 2.0 ppm; and (iv) if a unit
combusts only natural gas (or gaseous fuel with a total sulfur content
no greater than the total sulfur content of natural gas) and never
combusts any other type of fuel, the SO2 monitor span must
be set to a value not exceeding 200.0 ppm. Compliance with conditions
(i) through (iv) is required by January 1, 1999, except that conditions
(i) and (ii) are always optional for units that combust natural gas
only during unit startup.
The provisions in Secs. 75.11(e)(3)(i) through (iv), as presently
codified, apply only to the combustion of gaseous fuel with a total
sulfur content no greater than the total sulfur content of natural gas.
However, as noted above (under ``SO2 RATA Exemptions and
Reduced Requirements''), today's proposed rulemaking would add an
interpretation of the term ``fuel with a total sulfur content no
greater than the total sulfur content of natural gas'' to
Sec. 75.21(a)(6). The term would include any fuel (whether solid,
liquid, or gaseous) with a total sulfur content of 0.05
percent by weight. EPA believes that it is appropriate to apply the
quality assurance and reporting provisions in Secs. 75.11(e)(3)(i)
through (iv) to the combustion of all fuels with a total sulfur content
0.05 percent by weight. Therefore, in today's proposed
rule, a new section, Sec. 75.21(a)(8) would be added, extending the QA
provisions of Secs. 75.11(e)(3)(i) through (iv) to the combustion of
all types of fuels with a total sulfur content no greater than the
total sulfur content of natural gas. The new requirements would become
effective on January 1, 2000.
Note that EPA has reconsidered one of the four QA provisions for
the use of an SO2 monitor during natural gas (or fuel with
equivalent total sulfur content) combustion in Secs. 75.11(e)(3)(i)
through (iv). Specifically, the Agency believes that
Sec. 75.11(e)(3)(ii), which requires a daily adjustment of the
monitor's calibration to read exactly 0.0 ppm, may be too stringent
because in practice it can be very difficult to attain a reading of
exactly 0.0 ppm with a zero-level calibration gas, particularly when
manual calibration adjustments are made. Therefore, today's rulemaking
proposes to revise Sec. 75.11(e)(3)(ii) as follows. Rather than
requiring a daily adjustment of the SO2 monitor's
calibration, an adjustment would only be required when the ``as-found''
response of the monitor to the zero gas during a daily calibration
error test exceeded the performance specification of the instrument
(i.e., 2.5 percent of span). And instead of requiring the
calibration to be adjusted to exactly 0.0 ppm, the procedures for
routine calibration adjustments in proposed section 2.1.3 of Appendix B
would be followed, to bring the ``as-left'' response of the instrument
(i.e., the response during the additional calibration error test
required by proposed section 2.1.3 of Appendix B) ``as close as
practicable'' to the true value of the zero gas (0.0 ppm).
The Agency solicits comment on the proposed approach for QA
provisions for SO2 CEMS for gas-firing or equivalent.
8. General RATA Test Procedures
Under today's proposal, sections 6.5, 6.5.1, and 6.5.2 of Appendix
A, which describe the general requirements for RATAs, would be
extensively revised. Some of the proposed changes are simply
structural, but others are substantive. For instance, as previously
discussed above under ``Concurrent SO2 and Flow RATAs,'' the
requirement to perform concurrent SO2 and flow RATAs would
be deleted from the regulation. Further, section 6.5 would now
recognize that more than one type of fuel and more than one monitor
range may be considered normal for a particular unit. Also, the
requirement to complete each RATA within 7 consecutive calendar days
would be modified to require that the RATA be completed within 168 unit
operating hours (for single-load flow RATAs and, to the extent
practicable, for 2-load and 3-load flow RATAs). However, for the
multiple-load flow RATAs, up to 720 unit operating hours would be
allowed, if necessary, to complete the testing. This is consistent with
Agency guidance published in March, 1995, Policy Question 8.15 of the
Acid Rain Policy Manual, which discusses allowing up to 30 calendar
days to complete all three levels of a 3-load flow RATA (see Docket A-
97-35, Item II-I-9). Even though the policy says the RATAs at the
individual load levels should be completed within 7 days, thirty days
are acceptable to complete the 3-load RATA in order to account for the
possibility that the unit might shut down in between levels of the RATA
or that certain load levels may be difficult to attain and to hold.
Today's proposal would allow 720 unit operating hours (irrespective of
the number of calendar days) to complete a multiple-load flow RATA. EPA
believes that this proposed requirement provides greater flexibility
than currently allowed.
Sections 6.5.1 and 6.5.2 of Appendix A would be re-titled ``Gas
Monitoring Systems (Special Considerations)'' and ``Flow Monitor RATAs
(Special Considerations),'' respectively. Proposed section 6.5.1
contains a recommendation that, for initial monitor certifications, the
RATA not be commenced until all of the other certification tests have
been completed. Section 6.5.2 would be amended, as previously discussed
under ``Flow RATA Load Levels.'' The definition of normal load would be
revised and the number of loads and the load levels at which flow RATAs
are to be performed would be more clearly defined.
Today's rule proposes changes to section 6.5.6 of Appendix A, which
pertains to RATA traverse point selection. Proposed section 6.5.6 would
allow the following alternative reference method measurement point
locations. For all moisture determinations, a single reference method
point, located at least 1.0 meter from the stack wall, could be used.
For gas RATAs, the owner or operator would have four options: (1) at
any location (including locations where stratification is expected), a
minimum of six traverse points along a diameter, located in accordance
with Method 1 in Appendix A to part 60, could be used; (2) at locations
where stratification is not expected and section 3.2 of Performance
Specification No. 2 (``PS No. 2'') in Appendix B to part 60 allows the
use of a short reference method measurement line (with three points
located at 0.4, 1.0, and 2.0 meters from the stack wall), the owner or
operator could use an alternative 3-point measurement line, locating
the three points 4.4 percent, 14.6 percent and 29.6 percent of the way
across the stack, in accordance with Method 1 in Appendix A to part 60;
(3) at locations where stratification is expected (i.e., after a wet
scrubber or when dissimilar gas streams are combined), the short
measurement line from section 3.2 of PS No. 2 (or the alternative line
described in option (2) above) could be used in lieu of the ``long''
measurement line prescribed in section 3.2 of PS No. 2, provided that a
stratification test is performed prior to each RATA at the location and
certain acceptance criteria
[[Page 28070]]
are met; and (4) 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. EPA's Office of
Air Quality Planning and Standards (OAQPS) has endorsed the use of the
Method 1 traverse points as an alternative to the points prescribed by
PS No. 2 (see Docket A-97-35, Item II-C-22).
Regarding option (3) above, one utility and one stack testing firm
have requested that EPA allow the short measurement line to be used at
scrubbed unit stacks, citing logistical difficulties and safety
concerns associated with using the long measurement line prescribed by
PS No. 2 for sampling locations following wet scrubbers (see Docket A-
97-35, Items II-D-66, II-D-78). Both parties appeared willing to
perform stratification testing to demonstrate that the gas streams are
not significantly stratified. EPA responded to these requests by
issuing policy guidance which discusses allowing the short measurement
line to be used for scrubbed units, provided that stratification test
results show the stratification at the sampling location to be minimal
(see Docket A-97-35, Item II-I-9, Policy Manual, Question 8.25).
Regarding single-point RATA testing (option (4), above), which utility
groups asked EPA to consider, today's proposed rule would allow it on
the condition that a stratification test at the sampling location
demonstrates stratification to be essentially absent.
Sections 6.5.6.1 and 6.5.6.2 of Appendix A in today's proposed rule
provide two stratification test protocols which may be used to
demonstrate that a sampling location qualifies for the alternative RM
measurement point locations allowed under proposed section 6.5.6 (i.e.,
options (3) and (4), above). The first stratification test protocol, in
proposed section 6.5.6.1, is based upon technical guidance issued by
OAQPS (see Docket A-97-35, Item II-I-3) and would consist of measuring
the SO2, NOX, and diluent gas concentrations at a
minimum of 12 traverse points, located in accordance with Method 1 in
Appendix A to part 60. The gas concentration measurements would be made
using Reference Methods 6C, 7E, and 3A in Appendix A to part 60. The
average NOX, SO2, and CO2 (or
O2) concentration at each of the individual traverse points
would be determined, and the arithmetic average NOX,
SO2, and CO2 (or O2) concentrations
for all traverse points calculated. This 12-point test would have to be
passed one time at the sampling location under consideration. Once the
12-point test has been passed at the candidate sampling location, the
second (abbreviated) stratification test protocol, in proposed section
6.5.6.2, could be done prior to subsequent RATAs at the location in
lieu of the 12-point test. The abbreviated test would be done either at
3 points (located in accordance with the long measurement line in PS
No. 2) or at 6 points along a diameter (located according to EPA Method
1 in Appendix A to part 60).
The acceptance criteria for the stratification test results are
given in proposed section 6.5.6.3 of Appendix A. For each pollutant or
diluent gas, the short 3-point reference method measurement line
specified in section 3.2 of PS No. 2 (or the alternative 3-point line
described in proposed section 6.5.6 of Appendix A) could be used for
that pollutant or diluent gas in lieu of the long measurement line in
section 3.2 of PS No. 2, if the concentration at each individual
traverse point differed by no more than 10.0 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 5.0 ppm
or 0.5 percent CO2 (or O2) from the arithmetic
average concentration for all traverse points. Further, for each
pollutant or diluent gas, a single reference method measurement point
located at least 1.0 meter from the stack wall could be used for that
pollutant or diluent gas, 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. Finally, proposed
section 6.5.6.3 would require the owner or operator to keep the results
of all stratification tests on-site, suitable for inspection, as part
of the supplementary RATA records required under Sec. 75.56(a)(7) and
Sec. 75.59(a)(7).
Today's rule also proposes to clarify the sampling strategy for
RATAs in section 6.5.7 of Appendix A. The proposed revisions make it
clear that for gas monitor RATAs, the minimum time per run is 21
minutes, and all of the necessary data for each run (i.e., pollutant
concentration measurements and, if applicable, diluent concentration
data and moisture measurements) would have to be collected, to the
extent practicable, within a 60-minute period. The proposed revisions
would also require the pollutant and diluent concentration measurements
to be made simultaneously during RATAs of SO2/diluent and
NOX/diluent monitoring systems. For flow monitor RATAs, the
minimum time per run would be 5 minutes. A requirement to properly
account for flow pulsations (e.g., by sight-weighted averaging) at each
velocity traverse point would be added, as well as a clear statement
that successive flow RATA runs may be done as rapidly as practicable,
with no required waiting period between runs. Proposed section 6.5.7 of
Appendix A states that a minimum of one set of auxiliary data (moisture
and diluent gas measurements) would have to be collected for every
three RATA runs or for every clock hour of a flow RATA (whichever is
less restrictive). A related change to Sec. 75.22(a)(4) is also
proposed, which would allow the alternative moisture measurement
techniques described in section 1.2 of Method 4 in Appendix A to part
60 to be used for stack gas molecular weight determinations.
9. Reference Method Testing Issues
Discussion of Proposed Changes
Currently, Sec. 75.22 specifies several reference methods
(Reference Methods 2, 2A, 2C, or 2D) as appropriate methods for
determining volumetric flow under part 75. The Agency is currently
conducting a study of the accuracy of Reference Method 2 to determine
whether changes to Method 2 or the addition of other alternatives to
the Method are appropriate. Thus, the Agency anticipates that, in the
future, revisions to Method 2 in part 60 may create alternatives beyond
the specific reference methods specified in Sec. 75.22(a)(2).
Therefore, in Sec. 75.22(a)(2), EPA proposes to add: ``or its allowable
alternatives, except for 2B and 2E'' to Method 2 to automatically
incorporate into part 75 anticipated future revisions to the Method 2
requirements in Appendix A to part 60.
Section 75.22 specifies a number of instrumental reference methods
from Appendix A to part 60 (Reference Methods 3A, 6C, 7E, and 20) as
appropriate test methods for conducting CEMS performance tests under
part 75. These methods require the use of calibration gases to
calibrate the reference analyzers. Currently, however, part 60 does not
require that EPA protocol gas be used when performing instrumental
reference methods. The Agency believes that protocol gas should be used
when performing instrumental reference methods in order
[[Page 28071]]
to achieve accurate results. Therefore, proposed Sec. 75.22(c)(1) would
state that, for purposes of part 75, instrumental reference methods
must be performed using calibration gases as defined in section 5 of
Appendix A to part 75.
10. Alternative Relative Accuracy Specifications and Specifications for
Low-Emitters
One utility group has suggested to EPA (see Docket A-97-35, Item
II-E-13) that there is inconsistency and apparent inequity in the
relative accuracy specifications for units that qualify as low emitters
of NOX and SO2 (i.e., sources with average
SO2 concentrations of 250.0 ppm or less and/or average
NOX emission rates of 0.20 lb/mmBtu or less). Specifically,
they have questioned the appropriateness of the alternative relative
accuracy specifications used to determine the RATA frequency (i.e.,
semiannual or annual). Under section 3.3 of Appendix A and section
2.3.1 of Appendix B to the current part 75 rule, the RATA frequency for
an SO2 monitor installed on a low-emitting SO2
source may be determined in either of two ways: by the normal relative
accuracy specification (i.e. the RATA frequency is semiannual if the
relative accuracy is > 7.5 percent but 10.0 percent, and
annual if 7.5 percent relative accuracy is achieved), or by
the alternative specification (i.e., the RATA frequency is semiannual
if the reference method mean value and CEMS mean value differ by > 8.0
ppm but 15.0 ppm, and annual if the two mean values differ
by 8.0 ppm). For low-emitting NOX sources, the
RATA frequency for the NOX monitoring system is determined
in the identical manner to SO2 when the normal specification
is applied. For the alternative specification, the NOX RATA
frequency is semiannual if the CEMS and reference method mean values
differ by 0.01 lb/mmBtu but 0.02 lb/mmBtu, and
annual if the mean values differ by > 0.01 lb/mmBtu. The 8.0 ppm value
for SO2 was originally determined based on the performance
of a single set of monitors at a facility regulated under subpart Da of
the NSPS in part 60. However, in the first few years of Acid Rain
Program implementation, many part 75 utilities with wet scrubbers have
found it difficult to consistently meet the 8.0 ppm criterion for
obtaining an annual RATA frequency.
The utility group maintains that since, when the normal relative
accuracy (RA) specification is applied, the criterion for obtaining an
annual RATA frequency is to achieve a relative accuracy 25.0 percent
below the RA specification in section 3.3 of Appendix A (i.e., 7.5
percent RA is 25.0 percent below the specification of 10.0 percent),
the criterion for an annual RATA frequency should be essentially the
same when the alternative specification is applied. Under the current
rule, the alternative SO2 specification requires that the
mean CEMS and reference method values differ by no more than 8.0 ppm in
order to obtain an annual RATA frequency. This is 47.0 percent below
the 15.0 ppm alternative RA specification. Similarly for
NOX, the alternative NOX specification for an
annual RATA frequency requires the difference between the CEMS and
reference method mean values to be 0.01 lb/mmBtu, or 50.0
percent below the 0.02 lb/mmBtu alternative RA specification.
EPA agrees that the alternate RA specifications for low emitters of
SO2 and NOX appear to be somewhat inequitable,
and today's rulemaking proposes changes to these specifications. In
proposed section 2.3.1 of Appendix B, the alternative relative accuracy
specification for low emitters of SO2, (i.e., the difference
between the reference method and CEMS mean values) that must be met by
an SO2 monitor in order to obtain an annual RATA frequency
would be changed from 8.0 ppm to 12.0 ppm. For low emitters of
NOX, the alternative low emitter relative accuracy
specification that must be met by a NOX-diluent monitoring
system in order to obtain an annual RATA frequency would be changed
from 0.01 lb/mmBtu to 0.015 lb/mmBtu.
In today's rule, EPA is also proposing an alternative relative
accuracy specification of 0.025 lb/mmBtu for SO2-diluent
monitoring systems to obtain an annual RATA frequency and an
alternative relative accuracy specification of 0.7 percent
CO2 or O2, by which CO2 and
O2 monitors could obtain an annual RATA frequency. During
the investigation of the alternative RA specifications for the
SO2 and NOX-diluent monitoring systems, the
Agency noted that for SO2-diluent systems, part 75 specifies
only an alternative RA criterion of 0.030 lb/mmBtu for a semiannual
RATA frequency, but fails to specify a corresponding alternative RA
criterion for obtaining an annual RATA frequency. Similarly, for
CO2 and O2 monitors, EPA noted that an
alternative relative accuracy specification of 1.0 percent
CO2 or O2 (in terms of the mean difference
between the reference method and CEM values during the RATA) is given
for obtaining a semiannual RATA frequency, but no corresponding
alternative criterion is given for obtaining an annual frequency.
EPA notes that in order to make the annual RATA frequency criteria
for NOX-diluent and SO2-diluent monitoring
systems more equitable, a third decimal place is required. However,
Secs. 75.54 and 75.55 currently require NOX and
SO2 emission rates in lb/mmBtu to be reported only to 2
decimal places. Therefore, revisions are being proposed, see
Secs. 75.57(d)(6) and 75.58(a)(1)(iv), to require that, beginning on
January 1, 2000, all NOX emission rates in lb/mmBtu must be
reported to three decimal places. Prior to January 1, 2000, the owner
or operator would have the option of reporting NOX emission
rates to either two or three decimal places. Note that no corresponding
change is being proposed for the reporting of SO2 emission
rates in lb/mmBtu, since such emission rates will only be reported to
EPA by units that have installed Phase I Qualifying Technologies for a
three-year period (1997-1999), and are not required to be reported
thereafter. EPA solicits comments on the appropriateness of requiring
all NOX lb/mmBtu emission rates to be reported to three
decimal places. The Agency favors this approach, particularly for
quality assurance purposes, due to increased precision in the
calculation of RATA results. The Agency notes that this proposed change
would not affect the way in which compliance with the NOX
emission limits under part 76 is determined. Compliance with part 76
NOX limits, in lb/mmBtu, would still be based on two decimal
places.
All of the proposed revisions to the part 75 relative accuracy
specifications in today's rulemaking are summarized in proposed Figure
2 of Appendix B.
11. Bias Adjustment Factors for Low Emitters
As discussed in the preceding section, sources that qualify as low
emitters of SO2 and/or NOX have two ways to
evaluate the relative accuracy of SO2 and NOX
monitoring systems: (a) by the normal relative accuracy specification
(i.e., 10.0 percent RA), and (b) by the alternative RA specification
(i.e., the difference between the mean CEMS and reference method values
is within 15.0 ppm for SO2 low emitters, or
within 0.02 lb/mmBtu for NOX low emitters).
The normal RA is determined by a statistical analysis of the
reference method and CEMS data from the RATA. Mathematically, the
normal RA is the sum of the absolute values of the mean difference
(dmean) and the confidence coefficient (cc), expressed as a
percentage of the mean reference method value (RM)avg. The
mean difference indicates how closely the CEMS measurements agree with
the
[[Page 28072]]
reference method and is generally the principal contributor to the
percentage relative accuracy in the RA equation. The confidence
coefficient (cc) is a statistical term related to the standard
deviation and is an indicator of the amount of scatter in the data.
Section 7.6 of Appendix A requires a bias test of each
SO2 and NOX monitoring system whenever a RATA of
the CEMS is performed. If the mean difference is greater than the
absolute value of the confidence coefficient, the CEMS measurements are
systematically lower than the corresponding references method
measurements, i.e., the monitoring system has a low bias. In such
cases, sources are given two options. The first, preferred by EPA, is
to locate and eliminate the source of the measurement bias in the
instrument. The second option is to apply a bias adjustment factor
(BAF). This alternative was developed in response to an industry
request to provide an alternative for sources that choose not to expend
the effort to locate and eliminate the technical problem causing the
systematic measurement error. The BAF is equal to 1.000 +
|dmean| /(CEM)avg, where (CEM)avg is
the mean value of the CEMS measurements from the RATA.
At least one utility has questioned whether it is appropriate for
low emitters to calculate a BAF in the usual way when a CEMS fails a
RATA by the normal RA specification, but passes by the alternative
specification, because in such cases the BAF can become inordinately
high, particularly at very low emission levels (see Docket A-97-35,
Items II-D-62 and II-E-23). Since both the percent relative accuracy
and the BAF are based upon the same statistical terms (dmean
and cc), the utility questions whether the standard calculation
procedure for the BAF is adequate to determine a meaningful BAF for low
emitters. Just as the value obtained from the standard relative
accuracy equation tends to become large for low emitters, so, too, the
BAF is seen as becoming inordinately large for low emitters which use
the current BAF equation.
As this comment suggests, it is not uncommon for an SO2
or NOX CEMS installed on a low-emitting unit to fail a RATA
by the normal specification of 10.0 percent RA and to pass the same
RATA by the alternative RA specification. For instance, suppose that
the mean RM and CEMS values during an SO2 RATA of a low
emitter are 51.0 ppm and 40.0 ppm, respectively, and that
dmean is 11.0 ppm and the confidence coefficient is 0.50.
Suppose further that the bias test is failed. Then, the percent RA by
the normal specification (i.e., |dmean| + |cc | /
(RM)avg) would exceed 20.0 percent, indicating a failed
RATA, but the alternative RA specification would indicate a pass (i.e.,
(CEMS)avg is within 15.0 ppm of
(RM)avg). In this same illustration, the BAF would be 1 + 11
/ 40 = 1.275.
In fact, if it is assumed that the difference between the CEMS and
the reference method measurements does not decrease as emissions
decline, then the lower the SO2 or NOX emissions,
the more likely it is for the CEMS to fail the normal relative accuracy
specification because the mean difference becomes a larger percentage
of the average reference method value. It was precisely in response to
such concerns that the alternative relative accuracy specifications
were originally included in part 75.
Today's rule proposes to provide an option in the way the BAF is
determined for low emitters of SO2 and NOX. Low
emitters of SO2 and NOX would be given the choice
of using either: (a) the normal BAF calculation procedure described
above and found in Equation A-12, section 7.6.5 of Appendix A, or (b)
an alternative default bias adjustment factor of 1.111.
The justification is as follows: for units that meet the normal
relative accuracy standard of RA 10.0 percent, the
theoretically maximum possible Bias Adjustment Factor is 1.111 (see
Docket A-97-35, Item II-B-2). Therefore, low-emitting units meeting the
alternative relative accuracy standards (|dmean|
15.0 ppm for SO2 low emitters and |dmean|
0.02 lb/mmBtu for NOX low emitters) should not
have to apply a bias adjustment any higher than the maximum BAF value
applicable to units meeting the normal relative accuracy standard. EPA
solicits comment on allowing the alternative BAF of 1.111 for low-
emitting units.
12. Clarification of Diluent Monitor Certification Requirements
Today's proposed rule would clarify the certification requirements
for diluent gas (CO2 and O2) monitors, in
response to comments received on the pre-proposal draft of the rule
(see Docket A-97-35, Item II-D-52). Section 75.20(c)(1)(iii) of the
current rule requires a RATA of each NOX continuous
monitoring system to be done for initial certification. Even though the
NOX system consists of two component monitors
(NOX concentration and diluent gas), the required RATA is
done on a system basis in units of lb/mmBtu. Separate RATAs of the
individual component monitors are not required, except when the diluent
component monitor is also used as a CO2 pollutant
concentration monitor or to account for unit heat input, in which case
Sec. 75.20(c)(5)(iii) in the current rule requires a RATA of the
diluent monitor. To be sure that this is clear, today's proposed rule
would add a statement to Sec. 75.20(c)(1)(iii), indicating that the
RATA for the NOX-diluent system shall be done on a system
basis (i.e., individual component RATAs are unnecessary for
certification of a NOX-diluent system). Therefore, units
that have installed NOX monitoring systems, but that use
Appendix D for SO2 emission accounting and Appendix G for
CO2 accounting, would not be required to submit separate
RATA results for the diluent monitor.
A second point of clarification would be added in proposed
Sec. 75.20(c)(3), which was previously designated as Sec. 75.20(c)(4).
The new section would make it clear that when a diluent monitor
(O2 or CO2) is used both as a CO2
pollutant concentration monitor and for heat input determinations, only
one set of diluent monitor certification test results would have to be
submitted under the component and system ID codes of the CO2
monitoring system. This is appropriate because there is no such thing
as a ``heat input monitoring system'' or an ``oxygen monitoring
system'' under part 75.
13. Daily Calibration Requirements for Redundant Backup Monitors
Section 75.20(d)(1) of the current rule requires redundant backup
(``hot-standby'') monitoring systems to be operated during all periods
of unit operation and to meet all of the quality assurance requirements
of Appendix B, including daily calibrations and interference checks,
quarterly linearity checks and leak checks, and semiannual or annual
RATAs. One commenter on a pre-proposal draft of today's proposed rule
requested that EPA consider changing the daily calibration requirement
for redundant backup monitors (see Docket A-97-35, Item II-D-35). The
commenter recommended that the daily calibrations be made mandatory
only for days on which the redundant backup monitoring system is
actually used to report emission data to EPA. Daily calibrations would
be optional on all other days. Fewer calibrations of redundant backup
systems would considerably reduce calibration gas consumption. The
commenter estimated that this change could result in an annual savings
of more than $100,000 for his company. EPA agrees that the request is
reasonable, provided that the redundant
[[Page 28073]]
backup systems are kept on hot-standby and are calibrated prior to each
use for reporting. The Agency therefore proposes to amend
Sec. 75.20(d)(1) accordingly.
14. Daily Performance Specification and Control Limits for Low-Span DP
Flow Monitors
Section 3.1 of Appendix A of the current rule gives the calibration
error performance specification for flow monitors. Section 2.1.4 of
Appendix B gives the calibration error limits for daily operation of
flow monitors. For initial certification, a flow monitor is required to
meet a calibration error specification of 3.0 percent of
the span value. For daily operation of the flow monitor, the
calibration error must not exceed 6.0 percent of span. These
specifications are both reasonable and achievable for the vast majority
of flow monitors. However, when a differential pressure (DP) type flow
monitor is used to measure stack gas flow rate in a stack that has low
exit velocities, it can be very difficult for the monitor to pass its
daily calibration error tests. This is because the daily calibration
span value for a DP flow monitor is expressed in units of inches of
water. For stack exit velocities less than 2000 feet per minute, the
calibration span value will be a very small number (0.20 inches of
water or less). When performing a daily calibration error test of a
flow monitor with a span value of 0.20 inches of water, the test would
be failed (i.e., the calibration error would exceed 6.0 percent of
span) if the response of the monitor deviated from either the zero or
high reference signal by 0.02 inches of water. For span values of 0.15
inches of water or less, the calibration error test would be failed if
the monitor's response deviated from the reference signals by 0.01
inches of water. One utility with a DP type flow monitor with a span
value less than 0.15 inches of water has indicated to EPA that it
cannot pass daily calibrations unless the monitor responses exactly
equal the reference signal values (see Docket A-97-35, Item II-E-30).
Clearly, these daily calibration specifications are too stringent for
low span DP-type flow monitors. In view of this, EPA is proposing
alternative calibration error specifications for DP type flow monitors
with low span values, with ``low'' span value meaning a span value of
0.20 inches of water or less. The alternative performance specification
for initial certification, given in proposed section 3.1 of Appendix A,
would be 0.01 inches of water, rather than
3.0 percent of span. The alternative specification for daily operation
of the monitor, given in proposed section 2.1.4 of Appendix B, would be
0.02 inches of water, rather than 6.0 percent
of span. Since the results of a calibration error test of a DP type
flow monitor are reported to 2 decimal places, the performance
specification of 0.01 inches of water, is the tightest
specification that could be imposed, short of requiring the monitor to
read exactly the reference value with zero tolerance (which is what the
current specification of 3.0 percent of span essentially
imposes on a DP flow monitor with very low span). The Agency solicits
comment on this proposed approach and on the value of the alternate
specification.
O. CEM Data Validation
Background
The current requirements of part 75 regarding CEM data validation
are as follows. Section 75.10 specifies that a valid hourly average
from a CEMS must be based on a minimum of four evenly spaced data
points (i.e., one point in each 15-minute quadrant of the clock hour),
except that two evenly spaced data points separated by at least 15
minutes are sufficient to validate an hourly average when daily
calibration error tests and/or other required quality assurance
activities are conducted during the hour. Data from a CEMS are
considered to be quality assured, provided that the monitoring system
has passed all of the initial certification tests required under
Sec. 75.20(c) and provided that the CEMS is not ``out-of-control,'' as
a result of having failed any of the daily, quarterly, semiannual, and/
or annual quality assurance tests required in sections 2.1 through 2.3
of Appendix B. Out-of-control periods extend from the hour of failure
of a QA test until the hour of completion of a subsequent successful QA
test of the same type. For instance, if a linearity check of a gas
monitor is failed, the monitor is considered out-of-control from the
hour of completion of the failed test until the hour of completion of a
subsequent successful linearity test.
Finally, Sec. 75.20(b)(3) specifies that when a change is made to a
CEMS such that recertification of a monitor becomes necessary, data
from the CEMS are invalid from the hour in which the change is made to
the system until the hour of completion of all required recertification
tests.
In the first three years of implementing part 75, EPA has received
numerous requests from the utilities for guidance concerning CEM data
validation. This has prompted the Agency to re-examine these provisions
of the rule. From this re-examination, the Agency believes that the
current data validation provisions of part 75 are neither sufficiently
detailed nor flexible to address the complex realities of daily
operation of utility boilers and continuous emission monitoring
systems. Therefore, today's proposed rule would set forth more
comprehensive data validation criteria.
Discussion of Proposed Changes
Today's proposed rule would set forth proposed guidelines for the
validation of CEM data, attempting to take into account the realities
associated with the operation and maintenance of electric utility steam
generating units and continuous emission monitoring systems. The
proposed guidelines would govern CEM data validation as it pertains to
six principal areas: (1) calibration error tests and adjustment of gas
and flow monitors; (2) linearity tests of gas monitors; (3) relative
accuracy test audits of gas and flow monitoring systems; (4)
recertifications of gas or flow monitors; (5) data from non-redundant
backup monitoring systems; and (6) missed QA test deadlines. These
proposed guidelines for data validation are discussed in detail below.
1. Recalibration and Adjustment of CEMS
Today's proposed rule would revise section 2.1.3 of Appendix B, the
``recalibration'' section. The May 17, 1995 rule recommends (but does
not require) the calibration of a monitor to be adjusted whenever the
daily calibration error exceeds the performance specification in
Appendix A. For example, if the calibration error of a gas monitor
exceeds 2.5 percent of span, but does not exceed the daily control
limit of 5.0 percent of span, the monitor is considered to be out-of-
adjustment but not out-of-control, and EPA recommends that calibration
of the monitor be adjusted.
Today's proposal would re-title section 2.1.3 as ``Additional
Calibration Error Tests and Calibration Adjustments.'' The
recommendation to adjust the monitor when the calibration error exceeds
the Appendix A performance specification would be retained, but
definitions of ``routine calibration adjustments'' and ``non-routine
calibration adjustments'' would be added. Routine calibration
adjustments would be defined as adjustments made to a CEMS following a
successful calibration error test. The purpose of these adjustments
would be to bring the monitor readings as close as practicable to the
tag values of the reference calibration gases or to the
[[Page 28074]]
known values of the flow monitor reference signals. Non-routine
calibration adjustments would be adjustments in either direction
(toward or away from the reference value), but within the performance
specifications of the monitor (i.e., within 2.5 percent of
span for an SO2 or NOX monitor, 0.5
percent CO2 or O2 for a diluent monitor, or
3.0 percent of span for a flow monitor). Non-routine
calibration adjustments would be permitted, provided that an acceptable
technical justification is included in the QA/QC program required under
section 1 of Appendix B. An additional calibration error test would be
required following non-routine adjustments, to demonstrate that the
instrument is still operating within its performance specifications.
In addition to the daily calibration error requirements in section
2.1.1 of Appendix B, today's proposed rule would require a calibration
error test in four specific instances: (1) whenever a daily calibration
error test is failed; (2) when a CEMS is returned to service following
routine or corrective maintenance that may affect the ability of the
CEMS to accurately measure and record emissions data; (3) following
routine calibration adjustments in which the monitor's calibration is
physically adjusted, e.g., by means of a potentiometer (however, an
additional calibration error test would not be required if a
mathematical algorithm in the DAHS is used to make the routine
adjustments); and (4) following non-routine calibration adjustments.
Data from the CEMS would be considered invalid until the required
additional calibration error test had been successfully completed.
EPA is proposing to allow non-routine calibration adjustments
within the performance specifications of an instrument for two
principal reasons. First, commenters have expressed concern that
restricting allowable adjustments to routine calibration adjustments
would limit their ability to make adjustments within the acceptable
plus or minus control limits of a monitor, particularly prior to
linearity tests and RATAs. They have indicated that this flexibility is
necessary because the tag values of reference gases are not 100.0
percent accurate and adjustments of the analyzer may be needed to
account for these inaccuracies (see Docket A-97-35, Item II-I-15). EPA
agrees that this is a legitimate concern. Because there is a tolerance
of 2.0 percent on the different reference gases used for
daily calibration error tests, linearity tests, and RATAs, it may be
necessary to adjust toward or away from the tag value in order to make
sure that the test specifications are met. The Agency believes,
however, that it is appropriate to limit the calibration adjustments to
within the instrument's performance specifications (i.e.,
2.5 percent of span (for SO2 and NOX),
3.0 percent of span (for flow rate), and 0.5
percent CO2 or O2) in order to provide an on-
going demonstration that the CEMS can simultaneously comply with the
applicable daily, quarterly, semiannual, or annual performance
specifications in Appendix A. One utility has expressed concern about
its vendor's practice of making large calibration adjustments to the
CO2 monitor prior to RATA testing (see Docket A-97-35, Item
II-D-63).
The second reason for proposing to allow non-routine calibration
adjustments is the sensitivity of dilution-extractive monitors to
changes in barometric pressure, temperature, and molecular weight. EPA
believes that the best way to deal with this deficiency in the
dilution-extractive monitoring technology is to develop a mathematical
algorithm (site-specific, if necessary) that continuously applies a
correction to the measurement in order to compensate for pressure,
temperature, and molecular weight, as necessary, and to program the
algorithm into the DAHS. However, in commenting on a pre-proposal draft
of today's proposed rule, a number of utilities indicated that they
prefer to account for dilution probe pressure effects by manually
adjusting the monitor's calibration in anticipation of barometric
pressure changes (e.g., approaching weather fronts) (see Docket A-97-
35, Items II-D-41, II-D-55). After much deliberation, the Agency is
proposing to allow such adjustments, provided that: (1) the calibration
of the monitor is not adjusted outside of its performance
specifications; (2) an additional calibration error test is done to
verify that the adjustments have been properly made; and (3) the
procedures used for the adjustments are included in the QA/QC program
for the CEMS. Despite this, EPA still prefers that automatic pressure,
temperature, and molecular weight compensation be used, where
necessary, and would strongly encourage all facilities with dilution-
extractive monitors to develop and apply the necessary mathematical
algorithm(s).
2. Linearity Tests
Today's proposal would provide rules for data validation during
linearity tests, in proposed section 2.2.3 of Appendix B. A routine
quality assurance linearity test could not be commenced if the CEMS
were operating ``out-of-control'' with respect to any of its other
daily, semiannual, or annual quality assurance tests. Linearity tests
would be done ``hands-off,'' as follows. 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
test period, however, no adjustment of the monitor would be permitted
except for routine daily calibration adjustments following successful
daily calibration error tests (the Agency notes that it is unlikely for
calibration error tests to be done during a linearity test period
except when two or more operating days are required to complete the
test, e.g., for a peaking unit).
Proposed section 2.2.3 of Appendix B would specify that when a
linearity check is 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 hands-
off linearity test. This proposed requirement is not substantially
different from the out-of-control provision in the current rule. It
would merely extend the definition of out-of-control to include
linearity tests that are aborted prior to completion due to a problem
with the monitor. The underlying assumption is that the aborted
linearity test would not have been passed if all nine gas injections
had been completed. However, a linearity test that is aborted for a
reason unrelated to a monitor malfunction (e.g., an unplanned or forced
unit outage) would not trigger an out-of-control period.
Finally, a new section, 2.2.4, would be added to Appendix B,
providing a linearity test grace period of 168 unit operating hours.
The purpose of the grace period would be to give the owner or operator
a window of opportunity in which to perform a linearity test, when
either: (1) the required linearity test cannot be completed within the
QA operating quarter in which it is due, or (2) four consecutive
calendar quarters have elapsed since the end of the calendar quarter in
which a linearity test of a monitor (or range) was last done. Data
validation during a grace period would be done according to the
applicable provisions of proposed section 2.2.3 of Appendix B. Proposed
section 2.2.4 of Appendix B would specify that if the required
linearity test has not been completed within the grace period, data
from the monitor would become invalid, beginning with the first hour
following the expiration of the grace period and would remain invalid
until the hour of completion of a
[[Page 28075]]
subsequent successful, hands-off linearity test. Proposed section 2.2.4
would further specify that a linearity test done during a grace period
could only be used to meet the linearity test requirement of a previous
QA operating quarter, not the requirement of the quarter in which the
grace period is used. Note that proposed sections 2.2.3 and 2.2.4 of
Appendix B would also extend the 168 unit operating hour grace period
to apply to the quarterly leak checks of differential pressure-type
flow monitors.
3. RATAs
Today's proposal would provide rules for data validation during gas
and flow monitor RATA tests, in section 2.3.2 of Appendix B. Proposed
section 2.3.2 would specify that a routine quality assurance RATA could
not be commenced if the monitoring system is out-of-control with
respect to any of its daily quality assurance assessments, including
the additional calibration error test requirements of proposed section
2.1.3 of Appendix B. All RATAs would be done ``hands-off,'' as follows.
Prior to the RATA , both routine and non-routine calibration
adjustments would be permitted, in accordance with proposed section
2.1.3 of Appendix B. During the RATA test period, however, only routine
calibration adjustments (as defined in proposed section 2.1.3 of
Appendix B) would be permitted. For 2-level and 3-level flow RATAs, no
linearization of the monitor would be permitted between load levels.
Note that EPA is proposing to allow pre-RATA adjustments and
linearization of a CEMS, principally to encourage facilities to
optimize the performance of their CEMS by achieving the best possible
relative accuracy results in a cost-effective manner with little or no
data loss. The Agency believes that there is no significant risk in
allowing pre-RATA adjustments, provided that the monitor's continued
accuracy between successive RATAs can be reasonably established. For
gas monitors, EPA believes that the daily calibration error tests and
quarterly linearity tests, which challenge the analyzers with protocol
gases of known concentration, provide that assurance. For flow
monitors, however, the daily calibration error tests, which check the
internal electronics of the flow monitor but do not evaluate the actual
flow measurement capability of the instrument, do not provide the
necessary assurance. Therefore, in today's rulemaking, EPA is proposing
a new flow monitor quality assurance requirement, the ``flow-to-load
test,'' to provide a reasonable indicator of continued flow monitor
accuracy between successive RATAs. The flow-to-load test has been
discussed in detail under section III.M. of this preamble.
If a RATA is failed or aborted due to a problem with the CEMS,
proposed section 2.3.2 of Appendix B would specify that the monitoring
system is out-of-control as of the hour in which the test is failed or
aborted. Data from the monitoring system would remain invalid until the
hour of completion of a subsequent successful hands-off RATA. This
proposed requirement is essentially the same as the out-of-control
provision in the current rule, except that it would extend the
definition of out-of-control to include RATAs that are aborted prior to
completion due to a problem with the CEMS. Note, however, that a RATA
which is terminated for a reason unrelated to monitor malfunction
(e.g., process operating problems or unit outage) would not trigger an
out-of-control period.
For multiple-load flow RATAs, each load level would be treated as a
separate RATA. Therefore, if a flow RATA is failed at a particular load
level, previously-passed RATAs at the other loads would not have to be
repeated unless the flow monitor has to be re-linearized. In that case,
a subsequent 3-load RATA would be required.
If a daily calibration error test is failed during a RATA test
period, proposed section 2.3.2 of Appendix B would require invalidation
of the RATA, and an out-of-control period would begin with the hour of
the failed calibration error test. The RATA could not to be re-started
until a subsequent calibration error test had been passed, following
corrective actions.
Proposed section 2.3.2 of Appendix B further specifies that when
the RATA of a CO2 pollutant concentration monitor (or an
O2 monitor used to measure CO2 emissions) is
failed and that same CO2 (or O2) monitor also
serves as the diluent component in a NOX-diluent (or
SO2-diluent) monitoring system, then both the CO2
(or O2) monitor and the associated NOX-diluent (or
SO2-diluent) system would be considered to be out-of-control
until the hour of completion of subsequent hands-off RATAs which
demonstrate that both systems are in-control and have met the
applicable relative accuracy specifications in sections 3.3.2 and 3.3.3
of Appendix A. The beginning of the out-of-control period for each
monitoring system would be the hour of completion of the failed or
aborted RATA of the CO2 (or O2) monitor. The
lengths of the out-of-control periods would, therefore, be determined
from the same reference point for both the CO2 (or O2)
monitoring system and the NOX-diluent (or SO2-
diluent) monitoring system.
Today's proposal would clarify the way in which RATA results are to
be reported to EPA in the electronic quarterly report required under
Sec. 75.64. Proposed section 2.3.2 of Appendix B specifies that only
the results of completed and partial RATAs that affect data validation
would have to be reported. That is, all completed passed RATAs, all
completed failed RATAs, and all RATAs aborted due to a problem with the
CEMS would have to be included in the quarterly report. Therefore,
aborted RATA 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. RATAs which are aborted or invalidated due to problems with
the 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 is performed, and (2) no
adjustments other than the calibration adjustments allowed under
proposed section 2.1.3 of Appendix B are made. However, such RATA runs
would still have to be documented and kept on-site as part of the
official test log.
Whenever a required RATA has not been completed by its deadline,
section 2.3.3 of Appendix B of today's proposed rulemaking would
provide a grace period of 720 unit operating hours in which to complete
the test. Data validation during a grace period would be done according
to the applicable provisions of proposed section 2.3.2 of Appendix B.
Proposed section 2.3.3 would specify that if the RATA is not completed
by the end of the grace period, data from the CEMS would become invalid
upon expiration of the grace period and remain invalid until the hour
of completion of a subsequent successful hands-off RATA.
EPA has proposed a 720 unit operating hour RATA grace period
because the Agency believes this will allow the facility sufficient
time to schedule the RATA, to provide all required test notifications,
and to complete the testing. The proposed grace period would be based
on unit
[[Page 28076]]
operating hours rather than clock hours, because this is believed to be
more equitable for peaking and cycling units. Data validation during
the grace period would be prospective, i.e., data from the monitoring
system would be considered valid during the grace period until the time
of the RATA. If the RATA is failed or aborted due to a problem with the
CEMS, data would be invalidated from the hour in which the test is
failed or aborted, forward. Data would not be invalidated
retrospectively back to the beginning of the grace period. Several
utilities have expressed a preference for a grace period with
prospective data invalidation, because it is simple to implement and is
consistent with other part 75 provisions for which data invalidation is
prospective when a test is failed (see Docket A-97-35, Item II-E-23).
4. Recertification of Gas and Flow Monitors
Today's proposed rule would revise Sec. 75.20(b)(3) concerning data
validation during recertification test periods. In the January 11, 1993
rule, as amended on May 17, 1995, Sec. 75.20(b)(3) specifies that for
any replacement, change, or modification to a monitoring system
requiring recertification of the CEMS, all data from the CEMS are
considered invalid from the hour of that replacement, change, or
modification until the hour of completion of all required
recertification tests. Today's rulemaking proposes 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 allow
these new data validation procedures to also be applied to the initial
certification of monitoring systems. The proposed revisions are based,
in part, on policy guidance issued by EPA to address the initial
certification of CEMS when a wet scrubber is installed on an affected
unit (see Docket A-97-35, Item II-I-9, Policy Manual, Question 16.10).
The intent of that policy guidance and of today's proposal 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 are provided for data
validation during the recertification test period. The recertification
test period would begin with the first successful calibration error
test after making the change to the CEMS and completing all necessary
post-change adjustments, re-programming, linearization, etc. of the
CEMS. The post-change activities could also include preliminary tests
such as trial RATA runs or a challenge of the monitor with calibration
gases. The first successful calibration error test following all of
these activities would be known as a probationary calibration error
test. 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.
Today's proposal would place a specific time limit on the length of
the recertification test period, depending upon the type(s) of test(s)
required. If a linearity test or cycle time test is required, the test
would have to be completed within 168 unit operating hours of the hour
in which the probationary calibration error test was passed, marking
the beginning of the recertification test period. If a RATA is
required, it would have to be completed within 720 unit operating
hours. If a 7-day calibration error test were required, it would have
to be completed within 21 unit operating days. Routine daily
calibration error tests would continue to be done as required by part
75 throughout the recertification test period. If a particular
recertification test is not completed within the specified number of
hours, data validation would be done as follows. For a late linearity
test, RATA, or cycle time test that is passed on the first attempt, or
for a late 7-day calibration error test (whether or not it is passed on
the first attempt), data from the monitoring system would be
invalidated from the hour of expiration of the recertification test
period until the hour of completion of the late test. However, for a
late linearity test, RATA, or cycle time test that is failed on the
first attempt or aborted on the first attempt due to a problem with the
monitor, all conditionally valid data from the monitoring system would
be invalidated from the hour of the probationary calibration error test
that initiated the original recertification test period to the hour of
completion of the late recertification test. Data would remain invalid
until successful completion of the failed/aborted test and any
additional recertification or diagnostic tests that are required as a
result of changes made to the monitoring system to correct the
problem(s) that caused failure of the late recertification test.
A conditionally valid status would be assigned to emission data
generated by a CEMS during a recertification test period. The
conditionally valid data status would begin with the first hour of the
recertification test period (i.e., the hour in which the probationary
calibration error test is passed, following completion of all necessary
monitor adjustments, preliminary tests, etc.). The conditionally valid
status of the CEMS data would continue throughout the recertification
test period, provided that the required recertification tests are done
``hands-off'' (i.e., with no adjustments, reprogramming, etc. 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 continue to be passed.
If all of the required recertification tests and calibration error
tests are 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. Note, however, that
if a required recertification test has not been completed by the end of
a calendar quarter, the owner or operator would indicate this by using
a suitable conditional data flag in the electronic quarterly report for
that quarter. The owner or operator would be required to resubmit the
report for that quarter if the required recertification test is
subsequently failed. In the resubmitted report, the owner or operator
would use the appropriate missing data routine in Sec. 75.31 or
Sec. 75.33 to replace each hour of conditionally valid data that was
invalidated by the failed recertification test with substitute data. In
addition, if conditionally valid data is submitted to the Agency in any
quarterly report, the owner or operator would have to indicate in the
end of the year compliance report required under Sec. 72.90 whether the
final status of the conditionally valid data has been determined. Note
that in certain instances where a recertification test period spans two
calendar quarters, it may be possible to avoid use of the conditional
data flag and quarterly report resubmittal. If a required
recertification test(s) is completed no later than 30 days after the
end of a calendar quarter (i.e., prior to the quarterly report
submittal deadline), the test data and results may be submitted
[[Page 28077]]
with the quarterly report, even though the test dates are from the next
calendar quarter. If the recertification test(s) is passed, this would
allow the ``conditionally valid'' data to be reported as quality
assured, in lieu of using a conditional data flag. If the test(s) is
failed, conditionally valid data could be replaced with substitute
data, as appropriate, and resubmittal of the quarterly report would not
be necessary.
If a recertification test is failed or aborted due to a problem
with the CEMS or if a routine daily calibration error test is failed
during a recertification test period, proposed Sec. 75.20(b)(3)
specifies that data validation would be done as follows:
(1) If any required recertification test is failed, the test would
have to be repeated. If any recertification test, other than a 7-day
calibration error test, is failed or aborted due to a problem with the
CEMS, the original recertification test period would end and any
necessary maintenance activities, adjustments, linearizations, and
reprogramming of the CEMS would need to be completed before a new
recertification test period could begin. The new recertification test
period would begin with a probationary calibration error test. The
tests that would be required in this new recertification test period
would include any tests that were required for the initial
recertification event which were not successfully completed and any
recertification or diagnostic tests required as a result of changes
that were made to the monitoring system to correct the problems that
caused failure of the recertification test;
(2) If a linearity test, RATA, or cycle time test is failed or
aborted due to a problem with the CEMS, all conditionally valid
emission data recorded by the CEMS would be invalidated from the hour
of commencement of the original recertification test period to the hour
in which the test is failed or aborted. Data from the CEMS would remain
invalid until the hour in which a new probationary calibration error
test is passed following all of the necessary maintenance procedures,
diagnostic tests, etc., at which time the conditionally valid status of
emission data from the CEMS would begin;
(3) If a 7-day calibration error test is failed within the
recertification test period, the test would have to be re-started.
Previously-recorded conditionally valid emission data from the CEMS
would not be invalidated by a failed 7-day calibration error test
unless the calibration error on the day of the failed 7-day calibration
error test exceeded twice the performance specification in section 3 of
Appendix A (causing the monitor to be considered out-of-control); and
(4) If a calibration error test is failed during a recertification
test period, the CEMS would be considered out-of-control as of the hour
in which the calibration error test is failed. Emission data from the
CEMS would be invalidated prospectively from the hour of the failed
calibration error test until the hour of completion of a subsequent
successful calibration error test following corrective action, at which
time the conditionally valid data status would resume. Failure to
perform a required daily calibration error test during a
recertification test period would also cause data from the CEMS to be
invalidated prospectively from the hour in which the calibration error
test was due until the hour of completion of a subsequent successful
calibration error test. Following a failed or missed calibration error
test, no recertification tests could be performed until the required
subsequent calibration error test had been passed.
5. Recertification and QA
In today's proposed rule, a new section, 2.4, entitled
``Recertification, Quality Assurance, and RATA Deadlines'' would be
added to Appendix B. The purpose of this section would be to clarify
the inter-relationship between normal quality assurance testing of CEMS
and recertification events and to further clarify how RATA deadlines
are determined. Appendix B to part 75 currently requires periodic
(daily, quarterly, and semiannual or annual) quality assurance tests of
all CEMS. The required daily QA tests include calibration error tests
of all monitors and interference checks of flow monitors. Quarterly QA
tests include linearity checks of gas monitors and leak checks of
differential pressure-type flow monitors. The required semiannual or
annual QA tests for all types of CEMS are RATAs.
Under the current rule, when a significant change is made to a CEMS
which affects the ability of the monitoring system to accurately read
and record emissions data, Sec. 75.20(b) specifies that the CEMS must
be recertified. To recertify a monitoring system, one or more of the
following tests that were performed for initial certification of the
CEMS must be repeated. That is, depending upon the nature of the change
made to a CEMS, one or more of the following tests may be required for
recertification: (1) calibration error test, (2) cycle time test, (3)
linearity check, (4) RATA, or (5) DAHS verification. Notice that
recertification tests (1), (3), and (4) are the same types of tests
that are done for routine daily, quarterly, and semiannual or annual
QA. There is, therefore, a connection between routine QA tests and
recertification tests. Proposed Sec. 75.20(b) would further clarify
that any change to a CEMS that does not require a RATA would not be
considered a recertification event, and, therefore, would not require a
recertification application. In such cases, the required tests would be
considered diagnostic tests.
Routine QA tests are generally planned and scheduled in advance,
while recertification tests are performed on an as-required basis.
Despite this, it is sometimes possible to coordinate component
replacements or other changes to a CEMS with the QA test schedule for
the CEMS. For instance, suppose that in a particular quarter, a CEMS
component is replaced, and a RATA is required to recertify the
monitoring system. Suppose, further, that in the quarter of the
component replacement, the annual RATA is due, but has not yet been
conducted. In this case, the recertification RATA could serve a dual
purpose, i.e., to recertify the CEMS and to meet the annual RATA
requirement. For this reason, EPA proposes to recommend in today's rule
that, to the extent practicable, component replacements, system
upgrades, and other events that require recertification be coordinated
with the periodic (daily, quarterly, and semiannual or annual) QA
testing required under Appendix B. Proposed section 2.4 of Appendix B
clarifies that when a particular test is done for the dual purpose of
recertification and routine QA, the data validation rules in
Sec. 75.20(b)(3) pertaining to recertification would take precedence
and would be followed. In a similar manner, a required diagnostic test
(e.g., linearity check) could also be used to satisfy a quarterly
linearity test requirement.
Proposed section 2.4 of Appendix B emphasizes that, in general,
whenever a RATA is performed, whether for QA purposes, recertification
purposes, or both, the projected deadline for the next RATA (i.e.,
whether the next test is due in 2 or 4 QA operating quarters) would be
established based upon the percentage relative accuracy obtained. For
2-load and 3-load flow RATAs, the projected deadline for the next RATA
would be established according to the highest relative accuracy at any
of the loads tested. There would, however, be two important exceptions
to this for single-load flow RATAs. Irrespective of
[[Page 28078]]
the relative accuracy percentage obtained, the results of a single-load
flow RATA could only be used to establish an annual RATA frequency if:
(1) the single-load flow RATA is specifically required under section
2.3.1.3(b) of Appendix B for flow monitors installed on peaking units
and bypass stacks, or (2) the single-load RATA is allowed under
proposed section 2.3.1.3(c) of Appendix B for 85.0 percent
historical unit operation at a single-load level. No other single-load
flow RATA could be used to establish an annual frequency; however, a 2-
load flow RATA could be performed in place of any required single-load
RATA, in order to achieve an annual frequency.
6. Data From Non-Redundant Backup Monitors
Today's rule proposes to revise the quality assurance and data
validation requirements in Sec. 75.20(d) for non-redundant backup
monitoring systems. Under the May 17, 1995 rule, a ``non-redundant
backup monitoring system'' is defined as a ``cold'' backup monitoring
system which is brought into service on an as-needed basis, rather than
being operated continuously. Non-redundant backup monitors must be
initially certified at each location at which they are to be used, but
unlike ``redundant backup'' monitors which are operated continuously
and kept on ``hot-standby,'' non-redundant backup systems are not
required to meet the daily and quarterly quality assurance requirements
of Appendix B, except when they are actually used for data reporting. A
linearity test of each non-redundant backup gas monitor is required
before it is placed in service, and each non-redundant backup flow
monitor must pass a calibration error test before being used to report
data. The use of non-redundant backup monitors is restricted to 720
hours a year at a particular unit or stack, unless a 7-day calibration
error test is passed. A periodic recertification RATA of each non-
redundant backup monitor is required at least once every two years, at
each location where it is to be used.
Section 75.20(d) of today's proposal would clarify and expand the
definition of a non-redundant backup monitoring system. Under the
proposal, two distinct types of non-redundant backup systems would be
defined: (1) type-1 is a system that has its own separate probe, sample
interface, and analyzer (e.g., a portable gas monitoring system), and
(2) type-2 is a system consisting of one or more like-kind replacement
analyzers that use the same sample probe and interface as the primary
monitoring system. This would include non-redundant backup analyzers
that are used to meet the dual span and range requirements for
SO2 or NOX under proposed sections 2.1.1.4 and
2.1.2.4 of Appendix A.
The ``type-1'' system is the familiar non-redundant backup system
described in the current version of part 75. However, the ``type-2''
system is a new kind of non-redundant backup monitoring system. EPA
believes that allowing limited use of type-2 monitoring systems will
encourage facilities that do not have redundant backup monitors to
perform better maintenance on their primary analyzers. The Agency is
concerned that primary analyzers with excessive, recurring daily
calibration drift (i.e., monitors that fail calibration error tests
more often than expected) are sometimes kept in service to avoid using
substitute data, when the analyzers should be in the shop for
maintenance. If the monitor readings tend to drift low from day to day,
this can result in under-reporting of emissions, because data
validation for daily calibrations under part 75 is prospective. That
is, data are invalidated from the hour of a failed calibration error
test forward, while data recorded from the hour of the previous
successful calibration to the hour of the failed calibration are
considered valid. EPA believes that allowing limited use of type-2 non-
redundant backup monitoring systems would provide a simple way (i.e.,
like-kind analyzer replacement) for primary analyzers to be properly
maintained and repaired with minimal data loss.
Today's proposal would retain the requirement for type-1 non-
redundant backup monitoring systems to be initially certified (except
for a 7-day calibration error test) at each location at which they are
to be used. However, type-2 systems would require no initial
certification. Both types of systems would have to pass a linearity
test (for gas monitors) or a calibration error test (for flow monitors)
each time that they were used to report emission data. For a type-2
``mix-and-match'' NOX monitoring system consisting of one
primary analyzer and one like-kind replacement analyzer, only the like-
kind replacement analyzer would have to pass a linearity test, provided
that the primary analyzer is operating and not out-of-control with
respect to any of its quality assurance requirements. When a non-
redundant backup monitoring system is brought into service, emission
data from the non-redundant backup system could be deemed conditionally
valid during the linearity test period, as follows. After making the
like-kind replacement and prior to conducting the linearity test, a
probationary calibration error test could be done to begin the period
of conditionally valid data. If the linearity test is then passed
within 168 unit operating hours of the probationary calibration error
test, the conditionally valid data would be validated. However, if the
linearity test is either failed, aborted due to a problem with the
CEMS, or not completed as required, then all of the conditionally valid
data would be invalidated beginning with the hour of the probationary
calibration error test, and data from the non-redundant backup CEMS
would remain invalid until the hour of completion of a successful
linearity test.
Under today's proposal, when a non-redundant backup system is used
for part 75 reporting, the bias adjustment factor (BAF) from the most
recent RATA of the system would be applied to the data generated by the
system. If no RATA results were available for a type-2 system, the
primary monitoring system BAF would be applied to the data generated by
the type-2 system.
Today's proposal would retain the restrictions of the current rule,
which limit the annual usage of a non-redundant backup monitoring
system to 720 hours at a particular location (unit or stack). To use a
non-redundant backup system for more than 720 hours per year at a
particular location would require a RATA of the system at that
location. For type-1 systems, a recertification RATA would be required
at least once every eight calendar quarters at each location at which
the system is to be used. All non-redundant backup monitoring systems
(type-1 and type-2) would have to be assigned unique system and
component identification numbers and would have to be included in the
monitoring plan for the unit or stack.
7. Missed QA Test Deadlines
As discussed above under the subsections on ``Linearity Tests'' and
``Relative Accuracy Test Audits,'' proposed sections 2.2.4 and 2.3.3 of
Appendix B to today's rulemaking would allow a grace period in which to
perform required linearity tests and RATAs whenever a test cannot be
completed by the end of the quarter in which it is due. EPA believes it
is appropriate to allow a grace period because circumstances beyond the
control of the owner or operator (e.g., unplanned unit outages)
sometimes arise which prevent the deadline for a quality assurance test
from being met.
The proposed linearity grace period is 168 unit operating hours,
and the proposed RATA grace period is 720 unit operating hours. A
linearity grace period
[[Page 28079]]
could only be used to satisfy the linearity requirement from a previous
quarter. For any RATA (or RATAs, if more than one attempt is made)
conducted during a grace period, the deadline for the next RATA would
be calculated from the quarter in which the RATA was originally due,
not from the quarter in which the RATA is actually completed.
Data validation during a grace period would be done according to
the applicable provisions in proposed section 2.2.3 of Appendix B (for
linearities) or section 2.3.2 of Appendix B (for RATAs). Data from a
CEMS would become invalid upon expiration of a grace period if the
required linearity test or RATA had not been completed. Data from the
CEMS would remain invalid after the expiration of the grace period
until the required test is successfully completed.
P. Appendix D
1. Pipeline Natural Gas Definitions
Background
Appendix D provides an optional protocol by which oil-fired and
gas-fired units may account for their SO2 mass emissions.
Under the definitions of ``oil-fired'' and ``gas-fired'' in Sec. 72.2,
Appendix D may be used to measure SO2 emissions from gaseous
fuels only if the gaseous fuel's sulfur content is less than or equal
to that of natural gas.
In developing Appendix D, EPA assumed that virtually all of the
gaseous fuel combusted by affected units in the Acid Rain Program would
be pipeline natural gas. Section 2.3 of Appendix D of the January 11,
1993 rule allowed for accounting for SO2 emissions from
gaseous fuel using EPA's ``National Allowance Database (NADB) emission
rate.'' The NADB was used to establish a baseline of historical
SO2 emissions in order to allocate allowances. For the vast
majority of units combusting pipeline natural gas, NADB used the
historical heat input from gas and an emission rate of 0.0006 pounds of
SO2 per measured million British thermal units (lb/mmBtu)
(see Docket A-92-06; Docket A-94-16, Item II-F-2). This default factor
is derived from EPA Publication AP-42 and is based on a sulfur content
of 0.2 grains per 100 standard cubic feet of gaseous fuel (gr/100 scf)
(see Docket A-97-35, Item II-I-1). Use of this default SO2
emission rate factor for pipeline natural gas was clarified by EPA in
its Acid Rain Policy Manual (see Docket A-97-35, Item II-I-9, Policy
Manual, Question 2.4).
Section 2.3.2 of Appendix D, as revised by the May 17, 1995 direct
final rule, explicitly allows owners or operators to use a default
emission factor of 0.0006 (lb/mmBtu) to estimate SO2
emissions during hours in which pipeline natural gas is combusted.
Alternatively, section 2.3.1 of Appendix D, also as revised by the May
17, 1995 direct final rule, allows for determining SO2
emissions from any gaseous fuel with a sulfur content no greater than
natural gas by performing daily fuel sampling, analyzing the sulfur
content of the gaseous fuel, and multiplying that sulfur content in
grains per 100 standard cubic feet (gr/100scf) times the volume of
gaseous fuel combusted. Units combusting gaseous fuels with a total
sulfur content greater than natural gas (i.e., > 20 gr/100scf) are not
allowed to use the procedures of Appendix D and must instead use an
SO2 CEMS and a flow monitor to determine SO2 mass
emissions. This limitation is explicitly stated in Sec. 75.11(e)(4), as
revised on November 20, 1996.
The definition of ``natural gas'' in Sec. 72.2, as revised by the
May 17, 1995 direct final rule, indicates that the sulfur content of
natural gas is ``1 grain or less hydrogen sulfide per 100 standard
cubic feet, and 20 grains or less total sulfur per 100 standard cubic
feet.'' This definition was taken from Requirements of the Federal
Energy Regulatory Commission (FERC) for regulation of the transmission
of natural gas. ``Pipeline natural gas'' is also defined in Sec. 72.2.
However, the definition is simply ``natural gas that is provided by a
supplier through a pipeline,'' and provides no specifications for
sulfur content or hydrogen sulfide content.
Section 2.3.2.2 of Appendix D requires documentation of the
contractual sulfur content of pipeline natural gas from the supplier.
This documentation was intended to demonstrate that the natural gas is
supplied through a pipeline, as well as that it meets the sulfur
content definition for natural gas.
Questions over the applicability of Appendix D and the apparent
inconsistencies between the definitions ``natural gas'' and ``pipeline
natural gas'' in Sec. 72.2 and the provisions of section 2.3 of
Appendix D have caused confusion during program implementation since
the May 17, 1995 direct final rule. Some utilities have interpreted
section 2.3.2.2 of Appendix D to allow pipeline natural gas to have a
sulfur content as high as 20 gr/100 scf, which is one hundred times
higher than the sulfur content upon which the 0.0006 lb/mmBtu emission
factor is based. During the process of applying for certification of
monitoring equipment for six gas-fired units, one utility indicated to
the Agency that it intended to use a default emission rate of 0.0006
lb/mmBtu and heat input to account for SO2 mass emissions
from propane liquefied petroleum gas (see Docket A-97-35, Item II-D-6).
Based upon the information provided by the utility in its monitoring
plan for the units, the sulfur content of propane was several times
higher than that of pipeline natural gas, with a range of sulfur
content between 0.08 and 2.72 gr/100 scf, compared to a typical sulfur
content of 0.2 gr/100 scf for pipeline natural gas, upon which the
default SO2 emission rate of 0.0006 lb/mmBtu is based. Later
information submitted by the utility indicated that during the previous
three years, the sulfur content of propane combusted at that plant had
an average value of 0.83 gr/100 scf and a maximum value of 2.20 gr/100
scf (see Docket A-97-35, Item II-D-60). EPA rejected the utility's
monitoring approach using the default emission rate for pipeline
natural gas because it would have resulted in an underestimation of
SO2 emissions, as well as not following the procedures of
Appendix D (see Docket A-97-35, Item II-C-2).
Other utilities have tried to use the default SO2
emission rate of 0.0006 lb/mmBtu for higher sulfur gaseous fuels, such
as digester gas (see Docket A-94-16, Item II-D-71). EPA issued policy
guidance to ensure that other utilities were aware that the default
SO2 emission rate of 0.0006 lb/mmBtu should only be used for
pipeline natural gas with a low sulfur content of 0.2 gr/100 scf (see
Docket A-97-35, Item II-I-9, Policy Manual, Question 2.15, as
originally published in March 1996). However, several utilities were
concerned that this excluded some pipeline natural gas (see Docket A-
97-35, Items II-B-3, II-E-16). As stated in the technical support
document for the May 17, 1995 direct final rule, EPA had intended that
all pipeline natural gas would qualify for use of the default
SO2 emission rate of 0.0006 lb/mmBtu. Therefore, the Agency
revised its guidance to clarify that a facility needed only to document
that it was using pipeline natural gas, without documenting a sulfur
content of 0.2 gr/100 scf (see Docket A-97-35, Item II-I-9, Policy
Manual, Question 2.15, as revised in June 1996). During this process,
the Agency became concerned that the definition of pipeline natural gas
in Sec. 72.2 was not clear enough and that the sulfur content
documentation required for pipeline natural gas in section 2.3.2.2 of
Appendix D was confusing and possibly inappropriate.
[[Page 28080]]
Discussion of Proposed Changes
For the definition of pipeline natural gas in Sec. 72.2, today's
proposal includes a revised definition that would indicate pipeline
natural gas is low in the sulfur-bearing compound hydrogen sulfide
(H2S). The proposed revised definition would specifically
include the maximum hydrogen sulfide content for pipeline natural gas
permitted by fuel purchase or transportation contracts. The hydrogen
sulfide content of pipeline natural gas is proposed to be up to 0.3 gr/
100 scf.
In addition, section 2.3 of Appendix D would be revised. As under
the current rule provisions, sources would be allowed to use a default
SO2 emission rate of 0.0006 lb SO2/mmBtu in
conjunction with unit heat input to calculate the SO2 mass
emission rate during the combustion of pipeline natural gas. In order
to demonstrate that the pipeline natural gas qualifies to use the
default SO2 emission rate of 0.0006 lb/mmBtu, it would be
necessary for the designated representative to provide information in
the monitoring plan on the gas's maximum hydrogen sulfide content from
the facility's purchase contract with the pipeline gas supplier or from
the pipeline natural gas supplier's transportation contract. In such
contracts, or in the tariff sheets associated with them, the pipeline
gas supplier typically agrees to provide natural gas with a maximum
hydrogen sulfide content of 0.25 gr/100 scf or 0.30 gr/100 scf. If a
facility has previously submitted contract information from its
pipeline gas supplier containing a limit on the sulfur content, this
information typically also verifies the limit on the hydrogen sulfide
content. For pipeline natural gas, it would not be necessary to provide
sampling information to verify that the hydrogen sulfide content
actually meets the quality specification limit on the hydrogen sulfide
content stated in the definition of pipeline natural gas.
If a facility wanted to demonstrate that another gaseous fuel had
an SO2 emission rate no greater than pipeline natural gas,
and thus, could use the default emission rate factor of 0.0006 lb/
mmBtu, the designated representative would provide sulfur content and
GCV information in the monitoring plan for the unit or could petition
under Sec. 75.66(i) after initial certification for the unit. It would
be necessary for the designated representative to demonstrate that the
gaseous fuel has an SO2 emission rate no greater than 0.0006
lb/mmBtu. The designated representative would need to provide at least
720 hours of data for the demonstration. The data could come from the
fuel supplier, if the fuel came from a gas supplier.
For all units using Appendix D, proposed section 2.3.3 would
require the designated representative to provide information to the
Agency demonstrating that the total sulfur content of the gaseous fuel
meets the requirements of Appendix D and that the unit meets the
Sec. 72.2 definition of ``gas-fired'' or ``oil-fired.'' Additionally,
the gas-fired definition would be revised to indicate that the
restriction of burning gaseous fuels containing no more sulfur than
natural gas is actually a restriction on the total sulfur in the fuel.
The gaseous fuel's total sulfur content would have to be shown to be
less than or equal to 20 grains total sulfur per 100 standard cubic
feet of gaseous fuel.
Rationale
The Agency proposes to introduce specific hydrogen sulfide content
values into the definition of pipeline natural gas in order to provide
a guideline that will separate gaseous fuels with a higher sulfur
content from low sulfur pipeline natural gas. The maximum hydrogen
sulfide content of 0.3 gr/100 scf is being proposed for two reasons.
First, hydrogen sulfide contents of 0.25 or 0.3 gr/100 scf are
typically required under pipeline gas transmission contracts, and
should be relatively easy to document (see Docket A-97-35, Item II-E-
19). In addition, 0.2 gr/100 scf is the sulfur content equivalent to
the default emission rate factor of 0.0006 lb/mmBtu from the Agency's
AP-42 emission factors that may be used by units combusting pipeline
natural gas under section 2.3.2 of Appendix D (see Docket A-97-35, Item
II-A-6). A maximum hydrogen sulfide content of 0.3 gr/100 scf
corresponds to this default emission rate far more closely than a total
sulfur content of 20.0 gr/100 scf or a hydrogen sulfide content of 1.0
gr/100 scf and, yet, would allow for some variability in the hydrogen
sulfide content above a 0.2 gr/100 scf average. EPA believes that all
or virtually all pipeline natural gas that is supplied through a
pipeline for commercial use can meet these qualifications.
Pipeline natural gas is composed predominantly of methane
(CH4). Hydrogen sulfide is the predominant molecule
containing sulfur in pipeline natural gas. Therefore, restricting the
hydrogen sulfide content of pipeline natural gas to 0.3 gr/100 scf
serves as a proxy for a limit on the total sulfur content, while being
relatively easy to document. This revised definition of pipeline
natural gas would also serve to restrict the default emission rate
factor from being inappropriately applied to higher sulfur gaseous
fuels, such as liquefied petroleum gas (see Docket A-97-35, Item II-D-
6) or digester gas (see Docket A-94-16, Item II-D-71).
Appendix D of today's proposed rule would be revised to clarify the
documentation requirements for sulfur content and hydrogen sulfide
content of gaseous fuel, including pipeline natural gas. The original
wording of section 2.3.2.2 implied that pipeline natural gas only need
to have a total sulfur content of 20 gr/100 scf, roughly 100 times the
sulfur content associated with the default emission rate of 0.0006 lb/
mmBtu. Some utilities found this confusing (see Docket A-97-35, Items
II-D-6, II-E-10). Therefore, EPA issued guidance to clarify that the
default emission rate factor was only intended to apply to lower sulfur
pipeline natural gas (see Docket A-97-35, Item II-I-9, Policy Manual,
Question 2.15).
However, some utilities using pipeline natural gas were concerned
that because their fuel suppliers were not willing to certify or agree
to a sulfur content of 0.3 gr/100 scf by contract, they might be
required to perform daily gas sampling (see Docket A-97-35, Items II-B-
3, II-E-15, II-E-16). This was not the Agency's intent. The Agency
merely wishes to ensure that facilities provide adequate documentation
to demonstrate that the unit will not be underestimating SO2
emissions for a high sulfur gaseous fuel by using an inappropriate
default emission rate factor that applies to extremely low sulfur gas.
Similar to EPA's Policy Manual Question 2.15 referred to above, a
facility would need only to provide the fuel quality specification for
total sulfur content and hydrogen sulfide from the pipeline supplier,
or from the tariff sheet for the pipeline, in order to qualify to use
the default emission rate.
If a facility intends to use the default emission rate factor for a
gaseous fuel other than pipeline natural gas, sulfur content and GCV
data would have to be provided and analyzed to demonstrate that the
fuel has an SO2 emission rate no greater than 0.0006 lb/
mmBtu. A minimum of 720 hours of data would be required for the
demonstration. Each hourly value of the total sulfur content (in gr/100
scf) would be divided by the GCV value (in Btu/100 scf) and then
multiplied by a conversion factor of 106 Btu/mmBtu. This
would provide a ratio of the number of grains of sulfur in the fuel to
the heat content of the fuel. For pipeline natural gas with an assumed
SO2 emission rate of 0.0006 lb/mmBtu, a sulfur content of
0.2 gr/100 scf and a
[[Page 28081]]
GCV value of 100,000 Btu per hundred scf, the value of the ``sulfur-to-
heat content'' ratio is 2.0 gr/mmBtu. Therefore, a candidate gaseous
fuel would qualify to use the default SO2 emission rate of
0.0006 lb/mmBtu for part 75 reporting purposes if the 720 hours of
historical data demonstrate that the mean value of the sulfur-to-heat
content ratio is 2.0 gr/mmBtu or less.
To demonstrate that a unit qualifies to use Appendix D when
combusting a gaseous fuel, the designated representative for the
facility would be required to show that the gaseous fuel has a total
sulfur content of 20 grains/100 scf or less. This demonstration would
apply to all gaseous fuels. For gaseous fuels other than pipeline
natural gas, the sulfur content information could come either from
contractual information on the sulfur content based on routine vendor
sampling and analysis or from historic fuel sampling data to show the
gaseous fuel's sulfur content (see Docket A-97-35, Item II-I-9, Policy
Manual, Question 2.15). For gaseous fuels that are produced in batches
or lots with a relatively uniform sulfur content, such as liquefied
petroleum gases, it would be sufficient to provide historical
information on each batch over the past year. This approach was
accepted by the Agency for six units combusting liquefied petroleum gas
(see Docket A-97-35, Items II-C-14 and II-D-22).
In addition to documenting the total sulfur content of the fuel,
the owner or operator would be required to submit certain other fuel-
specific information. As previously noted, for units combusting
pipeline natural gas, a designated representative would be required to
provide contractual information to demonstrate that the natural gas is
supplied under specification and has a hydrogen sulfide content less
than or equal to 0.3 gr/100 scf. And historical data would have to be
provided, as described above, to obtain permission to use the default
SO2 emission rate of 0.0006 lb/mmBtu for a fuel other than
pipeline natural gas. For other gaseous fuels that are not produced in
batches with relatively uniform sulfur content, such as gaseous fuel
generated through an industrial process (e.g., digester gas from a
paper mill), since the sulfur content of the gaseous fuel could be
highly variable, section 2.3.3.4 of today's proposed revisions to
Appendix D would require a minimum of 720 hours of historical data
documenting the sulfur content of the fuel under representative
operating conditions. This information would allow the Agency to
determine how variable the sulfur content is and if the daily sampling
procedure under section 2.3.1 of Appendix D is sufficient to capture
this variability without allowing the underestimation of sulfur
content. If the sulfur variability were too great, continuous sampling
using a gas chromatograph and hourly reporting of sulfur content would
be required under today's proposed rule.
2. Fuel Sampling
(a) Fuel Oil.
Background
Diesel fuel is distillate fuel oil of grades No. 1 or 2. Diesel
fuel is heavily refined and has a much lower sulfur content and greater
consistency than other grades of fuel oil. Section 2.2 of Appendix D to
the May 17, 1995 direct final rule provides three options for sampling
of diesel fuel and two options for sampling of other fuel oils. First,
for all fuel oils, including diesel fuel, daily manual sampling is
allowed. Second, diesel fuel and other fuel oils may also be sampled
continuously using an automated sampler according to ASTM D4177-82
(Reapproved 1990), either using continuous drip sampling or flow
proportional sampling. The samples would then be mixed to form a daily
composite sample. Third, diesel fuel may be sampled ``as-delivered,''
upon receipt of a shipment. These sampling approaches were selected to
ensure that sulfur content values would be as accurate as possible,
would not underestimate SO2 mass emissions, and would
account for any variability in the sulfur content of fuel.
Many utilities have expressed concern about the cost of daily oil
sampling (see Docket A-97-35, Items II-D-18, II-D-20, II-E-13, II-E-
14). Some utilities indicated that for a unit that burns oil every day,
the cost of daily oil sampling is greater than the cost of
SO2 CEMS and flow monitors. Furthermore, industry
representatives provided information indicating that within a given
shipment of fuel oil from a supplier, the variability in sulfur content
is low (see Docket A-97-35, Items II-D-18 and II-D-59). Many companies
already have state or Federal requirements for sampling of fuel from
each truck delivery or in a storage tank on site at the plant whenever
fuel is added to the storage tank (see Docket A-97-35, Item II-D-93).
The storage tank is a tank at a plant that holds oil that is actually
combusted by the unit on that day. In other words, no fuel will be
blended between the time when a fuel lot is transferred to the storage
tank and when the fuel is combusted in the unit. In other cases, such
as EPA's NSPS regulations for industrial boilers under 40 CFR part 60,
subpart Db, companies keep copies of fuel receipts from the supplier to
indicate the sulfur content is below the required sulfur content. Based
upon this information, EPA is proposing to reduce the required sampling
frequency for fuel oil. This would be a significant reduction in burden
and cost of using Appendix D, without causing underestimation of
SO2 emissions.
Discussion of Proposed Changes
Several utilities suggested that the Agency propose to allow
sampling of each delivery of oil (see Docket A-97-35, Items II-D-18,
II-D-20, II-E-13, II-E-22). Under this approach, either a facility or
its supplier would sample each truck or barge containing oil before the
fuel is transferred into a tank at the plant. If a delivery shipped in
a group of trucks were purchased under the same order and were
specified to have the same gross calorific value, density, and sulfur
content, then only one sample would be necessary for the group of
trucks. Samples taken by the supplier would not need to be split and
kept on hand at the site. This approach is currently allowed only for
diesel fuel under section 2.2.1.2 of Appendix D, but would be extended
to apply to all fuel oils under today's proposed rule. This approach
would be particularly useful to a facility that receives large,
infrequent deliveries of fuel or to a facility that already has other
State or Federal regulations requiring sampling of each truck or barge
delivered to the plant.
A similar approach suggested by another industry representative,
allowing facilities to use a sample of oil taken from a tank belonging
to the supplier before the oil is delivered, is also proposed in
today's rulemaking. The supplier could take the sample and the facility
would be able to use that value as long as it keeps records of the fuel
analysis results from the supplier. This approach would be particularly
useful to a facility that receives a delivery of oil from a single
supplier's tank that is shipped in many different trucks. This approach
also would be useful for a small facility that would prefer to rely on
samples taken by the supplier rather than taking its own samples and
paying for their analysis.
Finally, the Agency proposes a third sampling approach, allowing a
facility to sample oil manually from its storage tank at the plant
whenever oil is added to the tank. This approach would yield samples
that are more representative of the oil combusted because it would
include any fuel remaining in the tank as well as all fuel added.
Sampling from the storage tank at the plant would be
[[Page 28082]]
useful to a facility that burns oil infrequently and adds oil to its
storage tank infrequently. It also would be helpful where a facility
already has other State or Federal regulations requiring sampling after
adding fuel to the storage tank.
Both the ``before delivery'' and ``as delivered'' sampling
approaches would require a sample for each ``lot'' of oil;
consequently, a suitable definition of a ``lot'' is needed. For
purposes of determining when an oil sample should be taken for the NSPS
applicable to utility boilers, section 5.2.2.2 of Method 19 in Appendix
A to 40 CFR part 60 relies on a definition of fuel ``lot'' developed by
the American Society for Testing and Materials (ASTM). This definition
states that ``the lot size of a product oil is the weight of product
oil from one pretreatment facility and intended as one shipment (ship
load, barge load, etc.).'' In essence, a lot is a single batch of oil
that has uniform properties and is purchased from a single supplier and
delivered to a buyer. Among those uniform fuel properties are gross
calorific value, density, sulfur content, and viscosity. In today's
rulemaking, EPA proposes to adopt this definition of a lot of oil for
use in the Acid Rain Program.
The Agency also considered whether it is appropriate to keep the
current approach of daily manual oil sampling as an option. Although it
seems unlikely that facilities would choose daily sampling option if
they have the three options of sampling by lot, sampling upon addition
of fuel to a storage tank, or continuous sampling, a utility group has
requested that EPA retain daily manual sampling as an option. The
agency is, therefore, proposing to retain daily manual oil sampling as
an option in Appendix D to allow facilities this additional
flexibility. An industry representative suggested that EPA could define
the oil combusted during a 24-hour period as a lot. For the reasons
discussed below and in the section addressing sulfur content, density,
and gross calorific values used in calculations, EPA is not
incorporating this suggestion in today's proposed rule.
EPA also reconsidered whether it is necessary to require daily
composite samples when samples are taken continuously with an automatic
sampler. In today's proposal, the Agency is proposing that continuous
samples may be composited on a weekly basis rather than daily. The
Agency also considered allowing an even longer compositing period, such
as a month, but is not proposing this option for the reasons discussed
below. A weekly composite sample of oil that is sampled continuously
would be an attractive option for a facility that wants the most
representative and accurate sulfur content data possible. This also
would be a useful option for those few facilities that receive oil via
a pipeline, rather than in discrete lots.
Rationale
Facilities wish to be able to perform less frequent fuel sampling
in order to save money. From the information EPA has examined over the
previous year, the Agency believes that less frequent oil sampling can
be technically justified. Based upon information provided by utilities,
the sulfur content of a lot of oil varies from sample to sample, with a
standard deviation of 0.036 percent S to 0.063 percent S, or 5.62 to
6.85 percent of the average sulfur content for all daily samples
between deliveries (see e.g., Docket A-97-35, Item II-D-18). Density
and gross calorific value of oil in a lot should vary even less than
sulfur content, because sulfur is an impurity in the composition of the
fuel and not an essential physical property of the oil, as is density.
Furthermore, the difference between the sulfur content, density, gross
calorific value, and carbon content of a fuel during the first daily
sample after a new delivery is received and the average sulfur content,
density, gross calorific value, and carbon content for all daily
samples from between two deliveries is extremely small (see Docket A-
97-35, Items II-B-18 and II-D-18 for supporting information).
Therefore, the Agency expects that the variability of fuel
characteristics within a lot is low enough that only a single
representative sample is necessary for the lot. Data have indicated
that there could be a significant difference in sulfur content between
shipments, however (see Docket A-97-35, Items II-B-12, II-B-18 and II-
D-18). The Agency believes that differences between lots, which could
potentially result in the underestimation of SO2 emissions,
can be dealt with by selecting a conservative sulfur content, density,
or gross calorific value that would not be exceeded in any sample,
rather than retaining more frequent sampling requirements. Therefore,
today's proposal incorporates this approach.
Prior to drafting today's proposed rule revisions, EPA requested
comments on removing the option to perform daily manual oil sampling
for Appendix D units. At least one utility group expressed interest in
retaining the option to allow flexibility. The prime benefit to a
facility from continuing to use daily manual sampling would appear to
be that the facility could continue to use the same daily operating
procedures and that reprogramming of a DAHS would not be necessary.
Note that when using the approach of daily manual oil samples, a
facility calculates SO2 mass emissions using the highest
sulfur content in the previous 30 daily oil samples. Therefore, this
approach requires more frequent analysis than either the proposed
weekly composite sample for continuous samples or the proposed sampling
by lot, and provides less accurate and more conservative results. The
Agency believes it would be simpler and less confusing for both the
Agency and for the regulated community to deal with a smaller number of
approaches to sampling and calculating SO2 emissions.
However, the Agency is retaining this option since at least some
affected utilities want the flexibility to continue to use this option.
EPA also considered the suggestion to define a 24-hour period as a
lot in order to allow facilities to continue to perform daily manual
sampling. EPA is not proposing this approach because of the added
complexity, compared to keeping the current language in section 2.2.4
of Appendix D concerning manual daily sampling of oil. If a lot were
defined as an arbitrary 24-hour period, the other requirements in the
current rule (e.g., conservative sulfur, gross calorific value, and
density values used to calculate SO2 mass emission rate and
heat input rate) would need to be retained to ensure that
SO2 emissions were not underestimated. Furthermore, using
the terminology of a ``lot'' for both a delivery and a period of time,
while requiring different treatment of sample data from the two
different types of ``lots,'' could potentially be confusing. It seems
preferable to keep the current language for daily manual samples.
Because the Agency now believes it is appropriate to sample each
fuel lot instead of sampling daily, the Agency reconsidered whether
daily composite samples are necessary when a facility performs
automated continuous sampling. Because continuous samplers take fuel
samples multiple times each hour, they are highly representative of the
oil being burned. Flow proportional samplers take samples automatically
when a certain volume or mass of fuel has passed by, rather than during
a particular time period. Generally, automatic samplers take multiple
samples each hour; however, only one sample per hour is required under
section 2.2.3 of Appendix D of the current rule. Even if the
compositing time period is extended, the composite sample will be
representative of the sulfur content, density, and gross calorific
value of the oil between samples. Therefore, the Agency believes
[[Page 28083]]
that the compositing period could be extended from a day to as long a
period as a month. However, EPA believes that it is unlikely that any
container for taking samples from an automatic sampler would be large
enough to accommodate all automatic samples taken during a month. In
addition, at least one industry representative suggested that weekly
composite samples were appropriate (see Docket A-97-35, Item II-D-30).
Therefore, in section 2.2.3 of today's proposed rule, EPA would extend
the allowable length of the compositing period for automatic samples to
one week. The Agency believes this will make automatic sampling less
costly, while taking into account the physical limitations of sampling
equipment.
(b) Gaseous Fuels.
Background
Section 2.3 of Appendix D, as revised in the May 17, 1995 direct
final rule, provides only one approach for sampling gaseous fuel: under
section 2.3.1, gaseous fuel sampling must be performed daily.
Relatively few utilities perform daily sampling upon gaseous fuels,
choosing instead to use a default SO2 emission rate for
pipeline natural gas. In part, this is because the vast majority of
gaseous fuel used by power plants is pipeline natural gas. Under
section 2.3.2 of Appendix D, facilities may calculate SO2
mass emissions from pipeline natural gas using a default emission rate
instead of performing fuel sampling. Because of the difficulty and
potential danger of sampling gaseous fuel, gas sampling is generally
conducted by the supplier, rather than by the facility.
Those few utilities combusting gaseous fuels other than pipeline
natural gas have expressed concern about the difficulty and expense of
daily sampling, particularly in comparison to the value of
SO2 allowances for low SO2 emissions from
relatively clean fuel (see, e.g., Docket A-97-35, Items II-E-11, II-E-
20). For gaseous fuels that are delivered in discrete batches or
``lots,'' one would expect the gaseous fuel to behave like an ideal
gas; sulfur should be evenly distributed throughout the batch. On this
principle, the Ohio Environmental Protection Agency allowed a plant to
take propane samples from each discrete delivery, rather than on a
daily basis (see Docket A-97-35, Items II-C-14 and II-D-22).
Discussion of Proposed Changes
Today's proposal incorporates three different sampling approaches
for gaseous fuels: sampling by lot, daily sampling, and continuous
sampling with a gas chromatograph. For gaseous fuel that is delivered
in discrete lots, such as liquefied petroleum gas, the gaseous fuel
could be sampled either daily or for each lot delivered. Any gaseous
fuels other than pipeline natural gas that are not delivered in
discrete lots, such as digester gas or sour natural gas pumped directly
from a field, would, at a minimum, need to be sampled daily. The
samples could be taken either by the supplier or by the facility.
However, if the average sulfur content and sulfur variability of such a
fuel were too high (i.e., mean sulfur content > 7 gr/100 scf and
standard deviation from the mean > 5 gr/100 scf, based on 720 hours of
representative historical data), continuous sampling with a gas
chromatograph and hourly reporting of sulfur content would be required.
Rationale
The approach of sampling upon a lot or discrete delivery of gaseous
fuel is being incorporated into today's proposed rule for the following
reasons. The Agency believes that discrete deliveries are sufficiently
different from pipeline transmission of fuel that a different sampling
approach is appropriate. According to the ideal gas law, all gas within
an enclosed volume is mixed with a consistent composition; therefore, a
single sample should be representative of all gas in the volume.
Although gaseous fuels delivered by lot, such as liquefied petroleum
gas, are higher in sulfur content and have a wider range of sulfur
contents than pipeline natural gas, they still have relatively low
sulfur contents compared to liquid and solid fuels. Thus, less frequent
gas sampling appears appropriate, based on the small difference in the
accuracy of calculated SO2 mass emissions. For this same
reason, the Agency allowed as-delivered sampling for diesel fuel in the
May 17, 1995 direct final rule (see Docket A-94-16, Item II-F-2).
Finally, because of the difficulty of sampling gaseous fuels, EPA
believes that it is less burdensome and less dangerous if gas sampling
is conducted by the gas supplier. It is the Agency's understanding that
the sampling for a gas in a discrete delivery or lot is typically
conducted once for the lot, rather than on a daily basis. Through a
petitioning process, EPA has already allowed one utility to perform
sampling upon a lot or discrete delivery of gaseous fuel (see Docket A-
97-35, Items II-C-14 and II-D-22).
EPA is proposing to require daily or continuous sampling of gaseous
fuels other than pipeline natural gas or the equivalent that are not
shipped in discrete lots, such as sour natural gas pumped directly from
a field, landfill gas, or digester gas. Such gaseous fuels cannot be
guaranteed to be stable in sulfur content. Therefore, proposed section
2.3.3.4 in Appendix D would require a minimum of 720 hours of
representative historical data to characterize the sulfur variability
of such fuels. For the 720 hours of demonstration data, the mean value
and standard deviation of the fuel sulfur content would be calculated.
If the mean value does not exceed 7 gr/100 scf (equivalent to about 10
ppm of SO2 emissions to the atmosphere), daily sampling
would suffice. If the mean value is greater than 7 gr/100 scf, however,
the variability of the sulfur content would be assessed in terms of the
standard deviation. If the standard deviation exceeds 5 gr/100 scf, the
sulfur variability would be considered too high and continuous sampling
of the fuel with a gas chromatograph would be required. If continuous
sampling were required, the owner or operator would have to implement a
quality assurance program for the gas chromatograph. A copy of the QA
plan would be kept on-site, suitable for inspection. For fuel with a
low average sulfur content or a low sulfur variability, daily sampling
would be sufficient. However, for gaseous fuel with a higher sulfur
content, if the sulfur variability were too great, continuous sampling
of the fuel with a gas chromatograph and hourly reporting of sulfur
content would be required.
3. Sulfur, Density and Gross Calorific Value Used in Calculations
(a) Fuel Oil.
Background
The hourly SO2 mass emissions rate due to combustion of
oil is calculated using the mass flow rate of oil combusted and a
sulfur content value from a sample. If a unit's oil flow rate is
measured with a volumetric fuel flowmeter rather than a mass fuel
flowmeter, then it will be necessary to determine the mass flow rate of
oil from the volume of fuel and a density value from an oil sample. The
heat input rate is calculated using the flow rate of oil multiplied by
the gross calorific value (GCV) of a sample.
The sulfur content, density, and GCV used to calculate emissions
and heat input depend upon the oil sampling method used. Some sampling
methods are more accurate than others. For example, for flow
proportional or continuous drip sampling, the actual sulfur content
from a sample is used to calculate SO2 mass emissions.
However,
[[Page 28084]]
when daily manual samples are taken under section 2.2.4 of Appendix D,
a facility must use the highest fuel sulfur content recorded at that
unit from the most recent 30 daily samples, which is not necessarily
the sulfur content of the fuel being burned at any particular time. For
units where diesel fuel is sampled upon delivery, section 2.2.1.2
instructs a facility to calculate SO2 emissions using the
highest sulfur content of any oil supply combusted in the previous 30
days that the unit combusted oil. In daily manual sampling and as-
delivered sampling, conservative sulfur values are used to avoid the
possibility of underestimating SO2 mass emissions due to
variations in sulfur content. Gross calorific values are taken from the
most recent sample, rather than using the highest value in the previous
30 days, because, for natural gas, GCV is more consistent than sulfur
content.
Today's proposed rule includes changes to the sampling frequency
for oil. Therefore, it is also necessary to make corresponding changes
to the sulfur content, density, and GCVs to be used in calculations.
For example, where oil samples would no longer be taken daily, it would
be inappropriate to calculate SO2 mass emissions based upon
a certain number of daily samples. In developing today's proposal, EPA
considered what fuel analysis data values for sulfur content, density,
and GCV would be appropriate and consistent with the approaches for
taking manual samples. The appropriate sulfur content, density, and GCV
values were considered for manual samples taken from a storage tank at
the facility whenever fuel is added to the tank, for samples taken from
each lot before the delivery is transferred from tank trucks or barges,
and for samples taken from the fuel supplier's storage tank.
Discussion of Proposed Changes
EPA has re-evaluated the sulfur content, density, and GCVs to be
used to calculate SO2 mass emissions and heat input based
upon the new oil sampling approaches. For daily manual oil sampling, a
facility would continue to use the highest sulfur content from previous
30 daily samples, and the actual density and GCV. For continuous oil
sampling with an automatic sampler, a facility would continue to use
the actual sulfur content, density, and GCV. For the two new methods of
manual sampling, EPA considered whether conservative or actual values
should be used to calculate emissions and heat input. EPA also
considered whether the same type of calculational value should be used
for sulfur content, density, and GCV. For example, if conservative
sulfur content and density values are used to calculate the
SO2 mass emission rate, should a conservative or an actual
measured GCV be used to calculate the heat input rate?
For manual samples taken from a storage tank at a plant whenever
fuel is added to the tank, EPA considered the following options: (1)
using the highest sulfur content and density from the previous three
samples, and the actual GCV, (2) using the highest sulfur content from
the previous three samples, and the actual density and GCV, (3) using
the actual sulfur content, density, and GCV, (4) using the highest
sulfur content, density, and GCV from the previous calendar year, and
(5) using the maximum sulfur content, density, and GCV allowed by fuel
purchase contract with the fuel supplier. The third, fourth, and fifth
options are incorporated into today's proposal in section 2.2.4.2.
Under this approach, a facility would take a sample from the storage
tank whenever fuel is added to the tank. No blending of fuel would be
allowed from the time the oil is sampled until the fuel is combusted by
the unit. The sample would be analyzed for sulfur content, density, and
GCV. Based on the selected option (3, 4, or 5), the appropriate values
would then be used to calculate the SO2 mass emission rate
and the heat input rate from the date and hour in which the transfer of
oil is complete until the date and hour when oil is again added to the
tank.
EPA considered several different options for the case where a
facility or its supplier would sample each oil delivery (or the
supplier's storage tank) before the fuel is transferred into a tank at
the plant. EPA considered whether or not these values needed to be
conservative and concluded that there was a real possibility of
underestimating SO2 emissions by using the fuel analysis
values from a delivery. The options that EPA considered to avoid the
underestimation were: (1) using the highest sulfur content and density
from all samples taken from oil combusted during the previous 30 days,
and the actual GCV, (2) using the maximum sulfur content, density, and
GCV in the fuel purchase contract specifications, (3) using the highest
sulfur content, density, and GCV from a sample taken in the previous
calendar year, and (4) using the highest sulfur content, density, and
GCV ever recorded for the unit. The second and third options are
incorporated into today's proposed rule in section 2.2.4.3 of Appendix
D.
Under the selected options, a facility or its supplier would need
to sample a delivery of fuel before it is transferred into a storage
tank. The facility would then need to keep records of the fuel
analytical results for three years. The facility would use the
conservative value it selected under option (2) or (3), above, in order
to calculate the SO2 mass emission rate and the heat input
rate. If an as-delivered sample were ever analyzed and found to have a
sulfur content, density, or GCV that exceeded the value being used in
calculations (i.e., the contract specification, or the maximum value
measured in the previous calendar year), then the new sampled value
would be used to calculate the SO2 mass emission rate or the
heat input rate, as follows. For a unit using a default value of the
maximum value measured during the previous calendar year, that new
sample value would become the new default value and would be reported
for the remainder of the current year and the next year, unless
superseded by a higher sampled value. For a unit using a default value
of a contract specification, the new sample value would continue to be
used as the new default value instead of the contract specification
value, unless superseded by a higher sampled value or by a new
contract.
Rationale
EPA considers continuous sampling and the measurement of fuel from
a storage tank at a plant after each addition of fuel to the tank to be
highly accurate methods that will be representative of the fuel
combusted in a unit. However, if samples are taken from the truck or
barge used to ship the fuel, or if samples are taken ``as-delivered,''
the sample values will not necessarily accurately reflect the oil being
combusted by the unit at any particular time (see Docket A-97-35, Item
II-E-22). For example, a storage tank could contain oil with an average
sulfur content of 0.6 percent. Then a new delivery with a sulfur
content of 0.4 percent is received and transferred to the tank. The
``as-delivered'' sample value from the delivery truck would
underestimate the emissions at that time, since the fuel actually
combusted will combine a mixture of the old fuel supply in the storage
tank and the new fuel that is added. Thus, a more conservative sulfur
value should be used to calculate SO2 emissions if samples
are taken from the delivery containers or from a container used by the
oil supplier.
For density and GCV, today's proposal, at the suggestion of some
industry representatives, uses conservative values determined by the
same method for both parameters (see Docket A-97-35, Item II-E-24).
This
[[Page 28085]]
has the advantage of being easy to remember and to program. However, if
greater accuracy is desired, a facility would always have the option of
using actual sulfur content, density, and GCVs if it took samples from
its storage tank after each addition of fuel to the tank, or if it took
continuous, automatic samples.
EPA considered which conservative values would be appropriate for
sulfur, density, and GCV. EPA at first considered using the maximum
value from all oil supplies combusted in the previous 30 days. This is
similar to the current wording of section 2.2.1.2 of Appendix D for
calculation of SO2 emissions from diesel fuel as-delivered
sampling. However, in the process of implementing this provision of
part 75, EPA found this wording was somewhat confusing and issued
policy guidance to clarify section 2.2.1.2 of Appendix D (see Docket A-
97-35, Item II-I-9, Policy Manual, Question 2.9). This policy
essentially directs facilities to keep track of the amount of fuel used
as well as its sulfur content. Because of the more complicated nature
of this accounting, some industry representatives suggested that it
would be simpler to use a conservative default value that would not
require tracking fuel usage (see Docket A-97-35, Item II-E-24). Of the
default values considered, EPA felt that the most appropriate default
values would be the maximum values established by agreement with the
fuel supplier through a contract or the maximum measured value from all
samples in the previous calendar year. Contractual limits should be
higher than or equal to the actual sulfur content, density, or GCV.
Because not all units would necessarily have a fuel contract limiting
oil sulfur content, density, or GCV, EPA is also proposing to provide
the option of using the maximum oil sulfur content, density, or GCV in
the previous calendar year.
The Agency also considered whether the current provisions of 2.2.4
of Appendix D should be retained for calculation of SO2
emissions using the highest sulfur from the previous 30 daily samples
when performing daily manual sampling. As discussed above in Section
III.P.2(a) of this preamble on oil sampling frequency, the Agency is
proposing to retain the option as requested by at least one utility
representative.
(b) Gaseous Fuels.
Background
The vast majority of Acid Rain units which burn gaseous fuels
combust pipeline natural gas. Section 2.3.2 of Appendix D contains a
provision for calculation of SO2 mass emissions from
pipeline natural gas using a default SO2 emission rate in
lb/mmBtu and the heat input rate of pipeline natural gas. However, if a
facility or its supplier is sampling gaseous fuel for sulfur content,
either because it is not pipeline natural gas or because the facility
chooses to use a sampled value, then Appendix D requires the facility
to calculate the SO2 mass emission rate using the sulfur
content of the sample and the volume of gas combusted, and to calculate
the heat input using the GCV of the sample and the volume of gas
combusted (see Equations D-5 and F-20). Because of the nature of
gaseous fuels, they are always measured with a volumetric fuel
flowmeter. The formulas for calculating the SO2 mass
emission rate and the heat input rate use volume directly and do not
require information on gas density. The current provisions of Appendix
D allow a facility to calculate the SO2 mass emission rate
and the heat input rate using the actual value from a daily sample of
gaseous fuel.
When the provisions of section 2.3 of Appendix D were added to part
75 in the May 17, 1995 direct final rule, EPA presumed that virtually
every utility combusting gaseous fuel was combusting pipeline natural
gas. However, the Agency found that utilities were combusting other
types of gaseous fuels. One utility submitted a monitoring plan and a
certification application for fuel flowmeter monitoring systems that
indicated the utility was also using propane liquefied petroleum gas
(LPG) (see Docket A-97-35, Item II-D-6). The utility indicated that it
wished to use the default emission rate factor reserved for pipeline
natural gas in its monitoring plan and later petitioned the Agency
specifically for permission to use the default emission rate factor of
0.0006 lb/mmBtu. In conversations with utility staff, EPA found that
the utility wanted to avoid the expense of additional daily samples and
the trouble of entering daily sulfur values manually into its data
acquisition and handling system (see Docket A-97-35, Items II-E-11, II-
E-20). The Agency eventually approved a revised petition for the
utility that allowed the utility to take propane samples from each
discrete delivery, rather than on a daily basis, where the utility
calculates sulfur dioxide emissions from propane by using the highest
sulfur content recorded during the previous 365 days and reports these
data in its quarterly electronic data report (see Docket A-97-35, Items
II-C-14 and II-D-22).
The Agency found that there were also some utilities burning
gaseous fuels that were by-products of an industrial process (see
Docket A-94-16, Item II-D-71). EPA had concerns that such ``digester
gas'' might have a more variable sulfur content than pipeline natural
gas, since the gaseous fuel would begin with a higher sulfur content
than pipeline natural gas and would not necessarily go through a
process that would reduce and stabilize the sulfur content.
Discussion of Proposed Changes
In today's proposed rule, the provisions for sampling gaseous fuels
are found in section 2.3.1 of Appendix D. For gaseous fuels that are
delivered in discrete lots, a facility would use conservative values
for sulfur content and GCV to calculate the SO2 mass
emission rate and the heat input rate. For the sulfur content value,
the highest sampled sulfur content from the previous calendar year or
the maximum value allowed by contract would be used to calculate the
SO2 mass emission rate. For GCV, the highest of all sampled
values in the previous calendar year or the maximum value allowed by
contract would be used to calculate the heat input rate. If, for any
gas sample, the assumed sulfur content or GCV were exceeded, the
sampled value would become the new assumed value. For units using the
contract value, the sampled value would continue to be used unless a
new (higher) contract specification were put in place or unless an even
higher sampled value is obtained. For units using the maximum value
from the previous year, the sampled value would continue to be used for
the remainder of the current year and for the next calendar year unless
it was superseded by an even higher sampled value.
For any gaseous fuel where daily fuel sampling is required, a
facility would use the highest sulfur in the previous 30 daily samples.
For gaseous fuels other than pipeline natural gas, where daily sampling
of sulfur content is required, the highest GCV from the previous 30
daily samples would be used. For pipeline natural gas, where monthly
sampling of GCV only is required, the actual measured GCV, the highest
of all sampled values in the previous calendar year, or the maximum
value allowed by contract would be used.
For a gaseous fuel that is not produced in batches and that has a
relatively high sulfur content and a high sulfur variability,
continuous sampling with a gas chromatograph would be required. Sulfur
content would be reported as actual measured hourly average values. The
GCV would also be determined on an hourly basis, or,
[[Page 28086]]
alternatively, the highest value in the previous 30 unit operating days
could be reported.
Rationale
For gaseous fuel supplied in discrete deliveries, EPA is proposing
to take the same approach as for fuel oil that is being delivered to a
plant by barge or truck. EPA has already approved this approach with
one utility that combusts liquefied petroleum gas (see Docket A-97-35,
Items II-C-14 and II-D-22). Because a discrete delivery of gaseous fuel
would be maintained in an enclosed chamber with a relatively constant
temperature and pressure, one would expect the gaseous fuel to behave
like an ideal gas. Thus, sulfur and other constituents of the fuel
should be evenly distributed throughout the delivery of fuel. Using
conservative values to calculate the SO2 mass emission rate
and the heat input rate should account for any variability between
deliveries. Furthermore, this reduces the number of changes that would
be made to a data acquisition and handling system to add fuel supply
data.
For gaseous fuel other than pipeline natural gas, where daily fuel
sampling is required, EPA considered leaving unchanged the current
provisions of section 2.3.1 of Appendix D that would allow a utility to
use the actual value from a day's sample to calculate the
SO2 mass emission rate and the heat input rate. However, the
Agency believes that it is appropriate to change the sulfur content
value to be a somewhat conservative historical value. This is because
the Agency has concerns that there may be some gaseous fuels other than
natural gas, such as digester gas, that may have significant
variability in their sulfur content over the course of a day or a
longer period of time. This might result in the underestimation of the
SO2 mass emission rate.
In the case of fuel oil, some industry representatives suggested it
was simplest to determine the appropriate conservative values for
sulfur content, density, and GCV by the same method (see Docket A-97-
35, Item II-E-24). With one exception (for fuels with relatively high
sulfur content and high sulfur variability), today's proposal follows
this suggestion for gaseous fuels. The proposal uses the highest sulfur
content and the highest GCV from the previous 30 daily samples. This is
currently the procedure used to determine the sulfur value used in
calculations from daily manual oil samples. Since this algorithm for
daily manual oil sample calculations is already being used by many
software programmers, it is a good conservative value to use for daily
samples in this case. The Agency notes that currently, the heat input
is calculated using the actual sampled GCV and that this change would
require software reprogramming for units where gaseous fuel is sampled
daily. However, for pipeline natural gas that is sampled monthly for
GCV, facilities could continue to use the actual GCV measured in a
monthly sample. The other two options are more conservative and would
require software changes. The Agency requests comment on the proposal
to use the more conservative GCV value to determine the heat input rate
for gas combustion when gaseous fuel is sampled daily (which differs
from the current procedure in section 2.3.1.3 of Appendix D and section
5.5.2 of Appendix F).
For gaseous fuel that has a relatively high sulfur content and high
sulfur variability, daily sampling is not considered adequate to ensure
that SO2 emissions will not be underestimated. Therefore,
for such fuels, continuous sampling with a gas chromatograph and hourly
reporting of sulfur content would be required. For GCV, which is
expected to be less variable than sulfur content, either the actual
hourly measured value or the highest GCV value obtained in the last 30
unit operating days could be reported.
4. Missing Data Procedures for Sulfur, Density, and Gross Calorific
Value
Background
(a) Fuel Oil. The May 17, 1995 direct final rule included missing
data procedures for missing analytical information on sulfur content,
density, and GCV in section 2.4 of Appendix D. These procedures are
based on a daily sampling frequency. For example, missing sulfur
content, density, or GCV data are to be calculated using the highest
measured sulfur content, oil density, or GCV during the previous thirty
days when the unit burned oil. This was intended to mean that the
substitute data values are to be based on the previous thirty daily oil
samples for which data are available.
In order to ensure that a DAHS is capable of implementing the
missing data procedures required by the rule, Sec. 75.20(c)(7) and
Sec. 75.20(g)(1)(ii) require testing of each DAHS. EPA issued policy
guidance discussing how facilities should report the results of these
tests for units measured with fuel flowmeters. This policy guidance
provided a form checklist that facilities could use to show the results
of their own tests of the missing data substitution procedures (see
Docket A-97-35, Item II-I-9, Policy Manual, Question 15.9). Some
utilities objected to testing the DAHS missing data procedures on the
grounds that they should never miss sample data. In part, this would be
because the facility is required, under section 2.2.5 of Appendix D, to
split its sample and keep a portion. One utility offered to substitute
the maximum potential sulfur content, which would require less
complicated DAHS programming than using the maximum sulfur content of
the previous 30 daily samples.
(b) Gaseous Fuels. Section 2.4.1 of Appendix D, as revised by the
May 17, 1995 direct final rule, provides missing data substitution
procedures for missing sulfur data from daily samples of gaseous fuel.
The DAHS is required to substitute the highest measured sulfur content
recorded during the previous 30 days when the unit combusted gaseous
fuel. As for oil, this was intended to be the highest sulfur value from
the previous 30 daily samples with available sulfur values. Section
2.4.2 of Appendix D requires the substitution of the highest measured
GCV recorded during the previous three months that the unit burned
gaseous fuel when data are missing from a monthly gaseous fuel sample.
As for fuel oil, the missing data procedures for gaseous fuels are
linked to the frequency of fuel sampling.
A utility indicated to EPA that because it receives gas sampling
information from its supplier, it should never have missing data for
GCV. The utility suggested that it should not have to go to the expense
of programming its DAHS for missing data procedures that should never
need to be used. This argument was similar to that used by another
utility when referring to missing data procedures for manual samples of
fuel oil taken upon each delivery.
Discussion of Proposed Changes
EPA proposes to revise the missing data substitution procedures for
both fuel oil and gaseous fuel, in order to simplify them. For any
instance in which the sulfur content, GCV, or density value is missing,
the maximum potential value would be reported until the results of a
subsequent valid sulfur content analysis, GCV determination, or density
measurement are obtained. The proposed appropriate maximum potential
values are specified in the table below. The default values for sulfur
content, GCV, and density of residual oil and diesel fuel were taken
from handbook values (see Docket A-97-35, Item II-A-7). The default
maximum sulfur content values for gaseous fuel are consistent with the
maximum sulfur content allowed under
[[Page 28087]]
the definition of natural gas and the de facto maximum sulfur content
of pipeline natural gas, based on the proposed definition. Thus, any
gas with a sulfur content that did not allow it to qualify as pipeline
natural gas (i.e., greater than 0.30 gr/100 scf) but still allowed it
to be measured following Appendix D procedures (i.e., total sulfur
content not exceeding 20.0 gr/100 scf) would have a default maximum
potential sulfur content of 20.0 gr/100 scf. The default values for GCV
of gaseous fuels were taken from handbook values (see Docket A-97-35,
Item II-I-1). For pipeline natural gas, it is assumed that the gas is
primarily methane (GCV of 1050 Btu/scf) with a small amount of other
hydrocarbons with a higher GCV (see Docket A-97-35, Item II-E-19). For
other gaseous fuels, it is assumed that they are primarily butane (GCV
of 2100 Btu/scf), the hydrocarbon gas with the highest GCV of gases
commercially used for fuel.
Maximum Potential Default Values for Sulfur Content, Density, and GCV Data
----------------------------------------------------------------------------------------------------------------
Parameter Fuel Maximum potential default value
----------------------------------------------------------------------------------------------------------------
Sulfur content.......................... residual oil............... 3.5 percent by weight.
diesel fuel................ 1.0 percent by weight.
pipeline natural gas....... 0.30 gr/100 scf.
gaseous fuels with sulfur 20.0 gr/100 scf.
content greater than
pipeline natural gas.
GCV/heat content........................ residual oil............... 19,500 Btu/lb.
diesel fuel................ 20,000 Btu/lb.
pipeline natural gas....... 1100 Btu/scf.
gaseous fuels with sulfur 2100 Btu/scf.
content greater than
pipeline natural gas.
Oil Density............................. residual oil............... 8.5 lb/gal,
diesel fuel................ 7.4 lb/gal.
----------------------------------------------------------------------------------------------------------------
Rationale
(a) Fuel Oil. It seems possible that a facility might occasionally
miss a sample taken with an automatic sampler, and thus, would have
missing data. Therefore, today's proposal includes a provision for
substitution of missing sulfur content, density, and GCV data from
continuous, automatic sampling.
Based upon comments from some utilities, it seems relatively
unlikely that both a facility and its supplier would miss performing a
sample during a delivery. Both a facility and its fuel supplier will
want to verify that the fuel delivered is actually supplying the heat
content that it is supposed to, either under a contract or a fuel
specification; thus, both a facility and its fuel supplier will have an
incentive to ensure sampling takes place for a delivery. Furthermore,
if samples taken by a facility are split, then there should generally
be the ability to provide analytical data for that fuel, even if test
results were somehow lost. Because the event of missing fuel samples is
unlikely for as-delivered samples, EPA believes that it would be
appropriate to establish a simple, conservative value that could easily
be substituted in a data acquisition and handling system. This would be
easier to program than using historical values that require tracking
fuel usage over an extended period of time.
EPA is specifically proposing the most conservative (maximum
potential) values for missing data purposes. This would ensure that
substituted missing data values would be less advantageous to a
facility than taking samples and using sulfur content, density, and GCV
data from samples. In addition, several utilities suggested to EPA that
this was a reasonable approach (see Docket A-97-35, Item II-E-24).
(b) Gaseous Fuels. As mentioned previously, gas sampling is
generally performed by fuel suppliers because of the difficulty and
potential danger of opening up a pressurized pipe containing a highly
flammable gas. It seems extremely unlikely that a fuel supplier would
not have information available on the sulfur content or GCV of gaseous
fuel, since industrial customers will purchase fuel or agree to a
contract based upon these characteristics. The exception to this might
be gaseous fuel manufactured through an industrial process that is not
produced specifically for sale as a fuel, such as digester gas. In
today's proposed rule, EPA is using the same reasoning as above for
missing manual fuel oil sample data and is using the same basic
substitution approach for missing sulfur content and GCV data for
gaseous fuel.
EPA considered keeping the existing missing data substitution
procedures from sections 2.4.1 and 2.4.2 of Appendix D for missing data
from gaseous fuel. This would have the advantage of requiring no
reprogramming of software for facilities already following the existing
procedures. EPA also considered using the maximum sulfur content or GCV
from the previous calendar year, the same procedure proposed in today's
rule for calculation of SO2 mass emission rate or heat
input, for discrete deliveries of gas or for manual samples of oil
taken from a delivery truck or barge. However, using the proposed
maximum value would require little reprogramming and would greatly
simplify the missing data procedures. In policy guidance, the Agency
has indicated it would accept a simplified DAHS for units using the
procedures of Appendices D and E. In particular, these policies endorse
manual entry of fuel analytical data, simplified missing data
procedures for fuel flowmeters, and a DAHS that uses commercial
spreadsheet software instead of a specialized custom software for
purposes of part 75 (see Docket A-97-35, Item II-I-9, Policy Manual,
Questions 14.72 and 14.73). In keeping with the policy of allowing
Appendices D and E units to use commercial spreadsheet software, EPA
has proposed what it believes to be the simplest possible missing data
substitution procedure for missing sulfur content and GCV data. In
addition, using the proposed maximum potential sulfur content or GCV
would ensure that substituted missing data values are more conservative
than the values normally used to calculate the SO2 mass
emission rate and the heat input rate.
[[Page 28088]]
5. Installation of Fuel Flowmeters for Recirculation
Background
The current provisions of section 2.1.1 of Appendix D require the
use of an additional ``return'' fuel flowmeter when some fuel is
recirculated, i.e., initially sent toward a unit and then diverted away
from the unit without being burned. This additional fuel flowmeter is
required, regardless of the amount of fuel being diverted.
At least one utility has requested to use only the fuel flowmeter
measuring fuel leaving the oil tank without a second fuel flowmeter to
measure any fuel diverted away by the recirculation fuel line. The
utility argued that using a single fuel flowmeter would result only in
the overestimation of SO2 emissions, since the utility would
measure a larger amount of fuel usage. This would allow the facility to
avoid the expense of installation, certification, and quality assurance
testing on a fuel flowmeter on the recirculation fuel line. Since the
proportion of fuel being recirculated was minimal, the utility was
willing to use a more conservative SO2 emissions calculation
in exchange for devoting fewer resources for the testing and
maintenance of the recirculation line fuel flowmeter.
Discussion of Proposed Changes
In today's proposal, EPA proposes to allow facilities to use only a
fuel flowmeter on the main fuel line from the oil tank if the amount of
oil recirculated is demonstrated to be less than 5.0 percent of total
fuel usage for each hour during the year.
Rationale
EPA believes that it is reasonable not to require installation,
certification and quality assurance of secondary fuel flowmeters in
cases where the amount of fuel to be combusted is a small proportion of
the total fuel used, and where knowing the exact volume of the
recirculated fuel makes little difference in the calculation of
emissions and heat input. EPA has allowed one utility to use an
estimate of the maximum oil usage at start-up, rather than requiring
the utility to install a return line oil flowmeter to measure the
startup fuel flow rate.
At first, EPA considered making the installation of a fuel
flowmeter on a recirculation fuel line optional. Presumably, if the
cost in lost SO2 allowances were greater than the cost of
installing and maintaining a fuel flowmeter, then a facility would
choose to use a fuel flowmeter on the recirculation fuel line. However,
many fuel flowmeters used under Appendix D for determining the
SO2 mass emission rate and the heat input rate are also used
to estimate the NOX emission rate in lb/mmBtu under Appendix
E to part 75. The Appendix E procedures estimate hourly NOX
emission rates using a correlation between measured NOX
emission rates and heat input rates. The correlation is established
during a testing period. Therefore, subsequent to the test period, if
the hourly heat input values should become less accurate, it could
result in the estimated NOX emission rates becoming less
accurate. Such loss in accuracy could occur if the heat input rates
during the initial testing period were based upon subtraction of
measured volumes or masses of recirculated fuel from the total fuel
flow rates, and then the facility later began estimating, rather than
measuring, the recirculated fuel volumes or masses. The potential
inaccuracy would increase if the proportion of recirculated oil to the
total flow rate of oil varies over time. The NOX emission
rate can sometimes increase with increases in the heat input rate and
can sometimes decrease with increases in the heat input rate, depending
on the particular type of boiler; in addition, when certain types of
control equipment are installed, the NOX emission rate may
not have any relationship with the heat input. Thus, an overestimation
of the heat input rate would sometimes result in the overestimation and
sometimes result in the underestimation of the NOX emission
rate under Appendix E. For these reasons, EPA believes that there needs
to be some limits on the cases where a facility can choose not to use a
return fuel flowmeter.
In today's proposed rule, EPA is proposing that a facility may
choose to use only a fuel flowmeter on the main fuel line from the oil
tank and not install a return meter in those cases where the previously
measured proportion of oil from the recirculation line is less than or
equal to 5.0 percent of the unit's total oil usage during each hour of
the year. EPA believes that an error of 5.0 percent in the heat input
rate should be small enough that it will not significantly affect
accounting for the NOX emission rate under Appendix E. An
analysis of emissions data from a gas-fired Appendix E unit with a
higher than average NOX emission rate for gas (0.157 lb/
mmBtu) showed that a 5.0 percent increase in heat input would change
the quarterly average NOX emission rate by only 3.17 percent
(0.152 vs. 0.157 lb/mmBtu) (see Docket A-97-35, Item II-B-19). At the
same time, EPA believes that an average proportion of 5.0 percent of
total fuel usage should provide relief for the most extreme situations
where it might cost more to perform quality assurance testing on a
return fuel flowmeter than the value of the allowances saved by
monitoring with the return flowmeter.
The Agency also considered whether it would be more appropriate to
determine the proportion of recirculated fuel on an hourly average
basis or on an annual average basis to determine if the returned fuel
was less than 5.0 percent of total fuel usage. The Agency concluded
that the proportion of fuel could be determined only if a return fuel
flowmeter were already installed on the recirculation fuel line. Thus,
there would appear to be little advantage to basing the proportion of
fuel on an annual basis. Hourly average fuel flow rate would also be
more directly related to the heat input rate used to calculate hourly
NOX emission rate under Appendix E. EPA notes this is not
fully consistent with the objective of revising this provision, i.e.,
to exempt facilities from installation and operation of additional fuel
flowmeters. Therefore, the Agency believes it is better to base the
reduced fuel flow rate monitoring requirement either on actual
historical fuel flowmeter data or on some other method, as yet unknown,
that would yield a reasonable estimate of the average proportion of
fuel recirculated to the total amount of fuel used. At this time, the
Agency is unaware of what other methods could provide a reasonable
estimate of the average proportion of fuel recirculated to the total
amount of fuel used, either on an hourly or an annual basis.
Accordingly, the Agency would allow facilities to suggest methods
through the petitioning process of Sec. 75.66.
6. Fuel Flowmeter Testing
(a) Fuel Flowmeter Accuracy Tests.
Background
Sections 2.1.5 and 2.1.6 of Appendix D, as revised by the May 17,
1995 direct final rule, refer to calibration and recalibration of fuel
flowmeters. Section 2.1.5.2 gives procedures for a test of the
flowmeter accuracy by comparing a candidate flowmeter against another
flowmeter that has already been calibrated according to specified
procedures. If a flowmeter does not meet the specified accuracy, then
it would need to be recalibrated by adjusting it, then retested to
ensure it is reading accurately.
Some utilities have found confusing the terminology of
``calibration'' for a test that compares measurements from two
different flowmeters. Generally, the
[[Page 28089]]
term ``calibration'' is used to refer to adjustments made to a
flowmeter to ensure it is reading accurately. However, the type of test
described in section 2.1.5.2 is more like a relative accuracy test
audit than a calibration, in that it checks the flowmeter accuracy by
comparing the fuel flowmeter readings against readings from an outside
standard.
Discussion of Proposed Changes
To alleviate the confusion surrounding flowmeter testing, today's
proposal introduces the term ``flowmeter accuracy test.'' This
terminology is used in sections 2.1.5 and 2.1.6 of Appendix D.
Rationale
EPA believes that the term ``flowmeter accuracy test'' more clearly
reflects the nature of the test that is performed. Introducing this new
term also will clarify that the word ``calibration'' refers to
flowmeter adjustments, rather than to a comparative test between a
candidate flowmeter and a reference meter.
(b) Methods for Fuel Flowmeter Accuracy Testing.
Background
Section 2.1.5.1 of Appendix D, as revised by the May 17, 1995
direct final rule, includes a list of standards and procedures that may
be used to determine if a flowmeter is sufficiently accurate for use
under the Acid Rain Program. However, because of the large number of
different brands and kinds of fuel flowmeters, there are also many
manufacturers' procedures that are not explicitly permitted under part
75. Consequently, many Acid Rain certification applications for units
with fuel flowmeters have contained petitions under Secs. 75.23 and
75.66 for approval of other fuel flowmeter testing procedures. Among
those methods was AGA Report No. 7 for turbine flowmeters. This method
was incorporated by reference into part 75 in the November 20, 1996
final rule. In addition, another standard method that EPA approved
through petitions is American Petroleum Institute (API) Section 2,
``Conventional Pipe Provers,'' from Chapter 4 of the Manual of
Petroleum Measurement Standards, October 1988 edition (see reproduction
of this document in Docket A-97-35, Item II-D-10 (Attachment B)).
In the process of implementing part 75, many utilities have
commented on the problems of testing and calibrating fuel flowmeters.
Unlike CEMS or stack flow monitors, it is not always possible to
perform an accuracy test with the fuel flowmeter remaining in the pipe
where it is installed. Utilities have stated that certain fuel
flowmeters are extremely difficult to remove, send out for testing,
recalibrate, and then reinstall (see Docket A-97-35, Item II-E-22). In
addition, removing a fuel flowmeter from in-line may require stopping
flow of the fuel and possibly shutting down the unit, with negative
economic consequences (see Docket A-97-35, Item II-E-8). In addition,
if a facility needs to operate a unit while the flowmeter is being
tested at a laboratory, then no flow data will be available for the
fuel measured by the flowmeter unless the facility has a backup fuel
flowmeter. Utilities have petitioned for alternative quality assurance
procedures for fuel flowmeters in order to avoid the inconvenience and
expense of removing the fuel flowmeter and testing it (see Docket A-97-
35, Item II-D-9). Because of this, the Agency has been evaluating
various ways of testing a fuel flowmeter in-line (that is, still
installed in the pipe in its regular position).
Some utilities have suggested that an alternative way to check fuel
flowmeter accuracy would be to compare over time the ratio of the fuel
flowrate to unit output (``load''), measured either in electrical
generation in MWe or in steam flow in 1000 lb/hr (see Docket A-97-35,
Item II-E-21). A fuel flow-to-load comparison could be used to
determine if fuel flowmeter readings are still similar to the readings
obtained the last time the fuel flowmeter was tested against an outside
method. A significant change in the amount of fuel used at a load level
would call into question the validity of fuel flow readings from a
flowmeter. A fuel flow-to-load comparison could provide this check
without removal of the fuel flowmeter from its installed location,
which would be of considerable benefit to facilities.
Discussion of Proposed Changes
EPA is proposing to incorporate by reference the standard: American
Petroleum Institute (API) Section 2, ``Conventional Pipe Provers,''
from Chapter 4 of the Manual of Petroleum Measurement Standards. The
Agency also specifically requests comment on any other voluntary
consensus standards from standard setting organizations, such as API,
AGA, ASME, or ISO, that would be appropriate for incorporation by
reference into part 75. Any suggested methods should also be submitted
to the Agency as part of the comments to assist in the Agency's
evaluation.
Section 2.1.7 of Appendix D to today's proposed rule includes
provisions for an optional, supplemental quality assurance test for
fuel flowmeters using a ratio of the fuel flow rate and the unit load.
The fuel flow rate-to-load ratio comparison test would provide an
additional way to meet the requirement to periodically test fuel
flowmeter accuracy. This test would serve as a supplement to more
rigorous fuel flowmeter tests. These more rigorous tests include the
standards incorporated by reference under section 2.1.5.1 of Appendix D
that require the fuel flowmeter to be taken out of line and shipped to
a laboratory, and the ``master meter'' comparison procedures under
section 2.1.5.2 of Appendix D. For orifice-, nozzle-, and venturi-type
flowmeters, the more rigorous tests would include an inspection of the
primary element and an accuracy test on the transmitters or
transducers. If a facility performed and passed regular quarterly fuel
flow-to-load ratio testing, then it would need to perform the more
rigorous checks on monitor performance only once every 20 calendar
quarters (five years).
The fuel flow-to-load ratio test would require a facility to
establish a baseline period from a period of time when the fuel
flowmeter is known to be operating properly. After establishing this
baseline of accurate fuel flow data (or heat input rate data), a
facility would calculate the fuel flow-to-load ratio (or ``gross heat
rate'' (GHR)) during the baseline period. In each ``flowmeter operating
quarter'' that the fuel flowmeter operates after the baseline period is
completed, the facility would calculate the fuel flow-to-load ratio (or
GHR) for each hour the fuel flowmeter is used to report data. The
facility would compare the hourly fuel flow-to-load ratio (or GHR) to
the fuel flow-to-load ratio (or GHR) during the baseline period in
order to calculate the absolute value of the percentage difference for
each hour. Next, the facility would calculate the average percentage
difference for the quarter. If the percentage difference exceeded the
specified limits for the test, the fuel flowmeter would fail the test.
The key elements of the fuel flow rate-to-load evaluation are discussed
in the following paragraphs.
(1) Use of Gross Heat Rate-to-Load Ratio. Today's proposed rule
would allow a facility the option of calculating either the ratio of
the fuel flow rate to the gross generation in MWe or the steam flow
rate in thousands of pounds of steam per hour (``fuel flow-to-load
ratio'') or the ratio of the heat input rate to the gross generation in
MWe or the steam flow rate in thousands of pounds of steam per hour
(``GHR''). In order to allow a meaningful comparison, a facility would
use one of these two ratios consistently, both in calculating
[[Page 28090]]
an initial baseline ratio and in calculating hourly ratios during a
particular quarter. Equations D-1c and D-1e describe the calculation of
the fuel flow-to-load ratio for the baseline period and for hourly
values during a calendar quarter, respectively. For the GHR, the
respective equations are Equations D-1d and D-1f. These equations are
found in proposed sections 2.1.7.1 and 2.1.7.2 of Appendix D.
(2) Baseline Period for Fuel Flow-to-Load Ratio. The provisions for
calculating the baseline fuel flow-to-load ratio or gross heat rate are
found in section 2.1.7.1 of today's proposed rule. EPA is proposing
that the owner or operator of a facility would establish a baseline of
fuel flow rate (or heat input rate) data following a flowmeter accuracy
test under either section 2.1.5.1 or 2.1.5.2 of Appendix D, or
following both a transmitter or transducer accuracy test under section
2.1.6.1 of Appendix D and an inspection of a primary element for an
orifice-, nozzle-, or venturi-type fuel flowmeter under section
2.1.6.6. Throughout section 2.1.7 of today's proposed rule, these are
referred to as ``the most recent quality assurance procedure(s).'' The
baseline period of fuel flow rate (or heat input rate) data for a fuel
flowmeter to be tested under section 2.1.7 would use the first 168
hours of quality assured data measured by that flowmeter following the
most recent quality assurance procedure(s) for which: (1) only the fuel
measured by that fuel flowmeter is combusted (i.e., no co-firing of
fuels occurs); (2) the load is relatively stable and not ``ramping''
rapidly up or down; and (3) the load is sufficiently above the minimum
safe, stable operating load (unless low-load operation is normal for
the unit).
Today's proposal includes a limit to the length of time over which
the baseline period could extend. The baseline period of 168 hours
could not extend for longer than the end of the second calendar quarter
following the calendar quarter in which the most recent quality
assurance procedure(s) was performed. For orifice-, nozzle-, and
venturi-type fuel flowmeters, two quality assurance procedures would be
required: both a transmitter or transducer accuracy test under section
2.1.6.1 of Appendix D and an inspection of a primary element, such as
an orifice plate. For practical purposes, this means that the
transmitter or transducer accuracy test and the primary element
inspection would have to be completed either in the same calendar
quarter or in consecutive calendar quarters. If there were not 168
hours of quality-assured fuel flowmeter data from hours when a single
fuel is combusted, then the fuel flowmeter would not be allowed to be
tested using the fuel flow-to-load ratio as a supplement to other
quality assurance tests.
The 168 hours of quality-assured fuel flowmeter data next would be
averaged and divided by the average load, in megawatts or 1000 lb
steam/hr, during the same 168 hours to determine the baseline fuel
flow-to-load ratio (see Equation D-1c). Alternatively, the facility
could instead calculate the gross heat rate by averaging hourly heat
input rate during the 168 hours of the baseline period and by dividing
the average heat input rate by the average load during the same 168
hours (see Equation D-1d).
In cases where the fuel flowmeter is located on a common pipe
header, one fuel flow rate measurement could be associated with the
load from several units that receive fuel from the common pipe header.
In order to analyze the fuel flow-to-load ratio for a flowmeter on a
common pipe header, the load from all units receiving fuel from the
common pipe header would have to be combined for each hour, averaged
over the baseline period of 168 hours, and compared to the average fuel
flow rate during the baseline period. If a single unit receives fuel
from multiple pipes, each pipe with its own fuel flowmeter, then the
flow rates from all fuel flowmeters would have to be added together to
obtain the average fuel flowrate for the unit to be divided by the unit
load.
(3) Data Preparation and Analysis. In each flowmeter operating
quarter following the final quarter of the baseline period, all hourly
fuel flowmeter data would be compared to the load. A flowmeter
operating quarter would be a calendar quarter in which the unit
combusts the fuel measured by the fuel flowmeter for at least 168
hours. For each hour in which the fuel is combusted, the owner or
operator would calculate the fuel flow-to-load ratio (or GHR) (see
Equation D-1e for the fuel flow-to-load ratio and Equation D-1f for the
GHR). Hourly fuel flow rates on common pipe headers would be compared
to the sum of the loads from all units receiving fuel from the common
pipe header. For units with multiple pipes and multiple fuel
flowmeters, the total hourly fuel flow rate for the fuel would be
compared to the unit load.
Next, the facility would compare the hourly fuel flow-to-load
ratios (or GHRs) to the baseline fuel flow-to-load ratio (or GHR). The
absolute value of the percentage difference would be calculated for
each hour using Equation D-1g. Then the facility would calculate the
average value of the percentage difference for the quarter, using each
hourly percentage difference in Equation D-1h.
The quarterly average of the hourly percentage difference values
next would be compared to the limitation. For either the fuel flow-to-
load ratio or the GHR, Ef, the quarterly average of the hourly
percentage difference values would need to be no greater than 10.0
percent, unless the average of the hourly loads used for the analysis
was 50 MWe (or 500 klb/hr of steam), in which
case the limit on Ef would be 15.0 percent. If a fuel flowmeter were to
fail to meet this limit when using all data in the flowmeter operating
quarter, then the facility would have the option of excluding certain
hours. Otherwise, a failure to meet the 10.0 percent (or 15.0 percent,
if applicable) limit would be considered a failure of the fuel flow-to-
load ratio test.
(4) Optional Data Exclusions. As mentioned above, if a fuel
flowmeter's data would not meet the 10.0 percent (or 15.0 percent, if
applicable) limit on the quarterly average of the percentage difference
values, then a facility could opt to exclude certain hours of
unrepresentative fuel flow rate (or heat input rate) data and then
reanalyze the smaller set of data. The types of data that EPA proposes
as non-representative would be the same as the hours excluded during
the baseline period, including: (1) hours when the unit combusts
multiple fuels measured by multiple fuel flowmeters, such as co-firing
of gas and residual oil or co-firing of residual oil and diesel fuel;
(2) hours when the unit load is rapidly rising or falling, sometimes
referred to as ``ramping,'' to such a degree that the load in a given
hour differs by more than 15.0 percent from the load
during either the previous hour or the hour afterwards; or (3) hours in
which the unit load is in the lower 10.0 percent of the unit's
operating range, unless operation at those low levels is considered
normal for the unit. The facility would proceed to analyze the
remaining quarterly fuel flow rate or heat input rate values, provided
that there are at least 168 hours remaining for the quarter after
excluding non-representative hours. If less than 168 representative
hours remained after excluding the allowable hours, then a flow-to-load
or GHR test would not be required for that flowmeter for that flowmeter
operating quarter. If the fuel flowmeter data still failed to meet the
10.0 percent (or 15.0 percent, if applicable) limit on the quarterly
average of the percentage difference values after excluding the
allowable
[[Page 28091]]
hours, the flowmeter would fail the fuel flow-to-load ratio test.
(5) Consequences of Failing Fuel Flow-to-Load Ratio or GHR Tests.
There would be two primary consequences of failing a fuel flow-to-load
ratio or a GHR test. First, the data from the fuel flowmeter would no
longer be considered quality-assured. Thus, the facility would need to
invalidate data from the fuel flowmeter following the test. Proposed
section 2.1.7.4 of Appendix D specifies that the missing data
procedures of section 2.4.2 of Appendix D would be used to substitute
for the invalid data (unless a different fuel flowmeter is available
that has been tested for accuracy and has been demonstrated to meet the
accuracy specification), beginning with the first hour the fuel
measured by the fuel flowmeter is used during the quarter following the
flowmeter operating quarter in which the meter fails the fuel flow-to-
load ratio test. Second, in order to establish that the fuel flowmeter
is again operating properly and providing quality-assured data, the
facility would perform a fuel flowmeter accuracy test according to
sections 2.1.5.1 or 2.1.5.2 of Appendix D or, for orifice-, nozzle-,
and venturi-type flowmeters, a transmitter or transducer accuracy test
according to section 2.1.6.1 of Appendix D. In addition to the
transmitter or transducer test, orifice-, nozzle-, and venturi-type
fuel flowmeters would need to be further tested following a failed
flow-to-load or GHR test in order to ensure that the problem causing
the failure of the fuel flow-to-load ratio was a problem with the
transmitters or transducers.
Once the orifice-, nozzle-, or venturi-type flowmeter has been
recalibrated and passes a transmitter or transducer accuracy test
according to section 2.1.6.1 of Appendix D, the facility would perform
a shortened version of the fuel flow-to-load ratio test. The shortened
version of the test would use six to twelve hours of data following the
passed transmitter or transducer accuracy test. If the fuel flowmeter
passed the abbreviated fuel flow-to-load ratio test, then its data
would be considered valid, beginning with the time and date of the
passed transmitter or transducer accuracy test. However, if the fuel
flowmeter were to fail the abbreviated fuel flow-to-load ratio test,
then it would be necessary for the facility to inspect the primary
element for corrosion or damage. Furthermore, data would be considered
invalid until the orifice-, nozzle-, or venturi-type fuel flowmeter
passes an inspection of the primary element. Although data from the
flowmeter would be considered quality-assured after successful
completion of all required accuracy testing, visual inspections and
diagnostic tests, the baseline would have to be re-established no later
than the end of the second flowmeter operating quarter following the
quarter in which the quality assurance tests are completed.
Rationale:
EPA is proposing to incorporate by reference the standard: American
Petroleum Institute (API) Section 2, ``Conventional Pipe Provers,''
from Chapter 4 of the Manual of Petroleum Measurement Standards,
October 1988 edition. The Agency has already approved this method of
fuel flowmeter testing in response to a petition (see Docket A-97-35,
Item II-C-6). This is also a standard agreed to by API that is
traceable to NIST standards. The Agency has a general policy of
approving standards from technically knowledgeable groups such as the
Organization for International Standards (ISO), the American Society
for Testing and Materials (ASTM), the American Society of Mechanical
Engineers (ASME), the American Gas Association (AGA), the Gas
Processors Association (GPA), and API. EPA would also be willing to
incorporate additional standards by reference if commenters supply a
copy for consideration.
The Agency recognizes that it is difficult and sometimes costly to
take a fuel flowmeter out from its installation location to be tested
(see Docket A-97-35, Item II-E-22). Today's proposed rule would provide
the flexibility of an additional approach for testing fuel flowmeters
where they are installed. Today's proposal for a fuel flow rate-to-load
comparison test would allow facilities to assure the quality of their
fuel flow rate data without taking a fuel flowmeter out of line.
Several industry representatives suggested that a fuel flow rate-to-
load comparison was a useful approach to quality assuring data (see
Docket A-97-35, Items II-E-22, II-E-23). Some industry representatives
felt that a fuel flow rate-to-load ratio was straightforward and even
more representative than a stack flow rate-to-load ratio (see Docket A-
97-35, Item II-E-23).
In general, utilities have indicated that the idea of a fuel flow-
to-load ratio is an appropriate quality assurance test for fuel
flowmeters (see Docket A-97-35, Items II-D-30, II-D-41, II-E-33). Use
of the fuel flow-to-load ratio was first suggested to the Agency as an
alternative to annual orifice inspections (see Docket A-97-35, Item II-
E-22). One utility mentioned that the fuel flow-to-load ratio test
would be most useful if it allowed them to stretch the time between
transmitter or transducer accuracy tests on orifice-, nozzle-, and
venturi-type fuel flowmeters, as well as primary element inspections
and fuel flowmeter accuracy tests performed in-line against a ``master
meter'' or performed in a laboratory (see Docket A-97-35, Item II-D-
49).
Utilities have also indicated that they would prefer the provisions
of the fuel flow-to-load ratio test to be as similar as possible to the
stack flow-to-load ratio test in today's proposed rule (see Docket A-
97-35, Item II-E-33). This would be easier for facilities to comply
with because they would need to learn fewer new procedures, they could
use the same equations and algorithms in computer software or hand
calculations, and they could report information in a similar format. To
the extent possible, the Agency has incorporated this suggestion in
today's proposed rule. However, because monitoring with fuel flowmeters
is not identical to monitoring with stack volumetric flow monitors,
there are some differences in the procedures and in the data to be
recorded and reported.
Today's proposed rule would allow the quarterly fuel flow-to-load
ratio test as an optional supplement to flowmeter accuracy tests under
section 2.1.5.1 or 2.1.5.2 of Appendix D, transmitter or transducer
accuracy tests under section 2.1.6.1 of Appendix D for orifice-,
nozzle-, and venturi-type fuel flowmeters, and visual inspections of
the primary element required under section 2.1.6.6 of Appendix D for
orifice-, nozzle-and venturi-type fuel flowmeters. These more rigorous
fuel flowmeter quality assurance procedures would still be required at
least once every 20 calendar quarters (five years), even if the
procedures of section 2.1.7 of Appendix D were followed. The Agency has
proposed a quarterly fuel flow-to-load ratio test for several reasons:
(1) this is consistent with the provisions of the proposed volumetric
stack flow-to-load ratio test in today's proposed rule; (2) the test
involves examining data more closely when preparing quarterly reports;
and (3) a quarterly test allows facilities to find problems in fuel
flowmeter data before an entire year has passed. The Agency also
considered requiring the fuel flow-to-load ratio to be used more
frequently than quarterly, perhaps daily; however, this would require
facilities to spend far more time and effort in evaluating data at
different times during the quarter than they may do currently,
particularly for small, infrequently operated units. In addition, many
utilities claim that fuel
[[Page 28092]]
flowmeters tend to be stable, and therefore little change would be
expected over short time periods such as a day (see Docket A-97-35,
Item II-E-33).
EPA is proposing that the optional fuel flow-to-load ratio test
could serve as a supplement to other quality assurance procedures for
fuel flowmeters for up to 20 calendar quarters (five years). EPA is
proposing a time period of 20 calendar quarters for the following
reasons. First, it is similar to the current provision in section
2.1.5.2 of Appendix D, which allows a reference fuel flowmeter to be
accuracy tested as seldom as once in five calendar years if comparison
with an in-line ``master'' flowmeter shows less than a 1.0 percent
difference in their flow rates. Second, a five-year test cycle offers
certain administrative advantages. For instance, fuel flowmeters used
to provide heat input data for the heat input-versus-load correlation
of Appendix E could be accuracy-tested before each Appendix E test
(i.e., once every five years). In addition, a five-year period would
ensure that fuel flowmeters are tested by the time the unit's operating
permit is renewed. The 20 calendar quarter (five-year) period is
consistent with the provisions for reduced three-level flow RATAs for
stack flow monitors. The 20 calendar quarter (five-year) period between
tests is also consistent with the proposed time between quality
assurance tests for fuel flowmeters that are used very infrequently.
Repeating the periodic quality assurance procedures for fuel flowmeters
at least every five years would catch slow, long-term changes in heat
rates mentioned by a facility and would allow a facility to update its
baseline data periodically (see Docket A-97-35, Item II-D-49). Finally,
allowing the option of a 20 calendar quarter (five-year) period between
more rigorous quality assurance procedures would be safer and less
costly than annual testing, while, in coordination with quarterly fuel
flow-to-load ratio testing, still providing assurance of the quality of
the data.
(1) Use of Gross Heat Rate or Flow-to-Load Ratio. Today's proposed
rule would allow a facility the option of calculating either the ratio
of the fuel flow rate to the gross generation in MWe or the steam flow
rate in thousands of pounds of steam per hour (``fuel flow-to-load
ratio'') or the ratio of the heat input rate to the gross generation in
MWe or the steam flow rate in thousands of pounds of steam per hour
(``gross heat rate'' or ``GHR''). One utility suggested that, because
the load is created based upon a number of factors in addition to the
fuel flow rate, such as the gas heat rate (i.e., gross calorific
value), a ratio of the heat input to the unit load would be a better
test than the ratio of the fuel flow rate to the unit load (see Docket
A-97-35, Item II-D-50). In addition, some utilities pointed out that
the Agency allows facilities to use either a stack flow-to-load ratio
or a heat input-to-load ratio (gross heat rate) as a diagnostic test on
stack volumetric flow monitors, through Policy Manual Question 13.15
(see Docket A-97-35, Item II-I-9). The Agency agrees that the heat
input-to-load ratio (GHR) is also a technically appropriate check on
the performance of fuel flowmeters. Therefore, today's proposal
includes options for both the fuel flow-to-load ratio and the GHR.
(2) Baseline Period for Fuel Flow-to-Load Ratio or GHR. When using
this type of comparison test, it is important to establish a baseline
of reliable data to which hourly data can later be compared. For the
stack volumetric flow-to-load ratio, the baseline of reliable data
consists of data from the reference method for flow, Method 2 of
Appendix A to 40 CFR part 60. However, there is no universally
applicable test for flowmeters that is performed in-line with a
reference method while the unit is operating, parallel to the flow
RATA. EPA asked several utilities what could be a source of baseline
data to which the fuel flowmeter could later be compared. One utility
suggested using fuel flowmeter readings during a time when the unit is
operating at a steady load, such as when the unit undergoes Appendix E
testing for a NOX-versus-heat input correlation or when a
NOX CEMS undergoes a normal level RATA (see Docket A-97-35,
Item II-D-41). A second utility recommended that the baseline be
established just after performing a transmitter calibration, i.e.,
after performing a quality assurance test on the fuel flowmeter (see
Docket A-97-35, Item II-D-49). The Agency believes that using fuel
flowmeter data taken immediately following a flowmeter quality
assurance test would be most likely to be accurate and representative
of proper operation of the fuel flowmeter. Flowmeter quality assurance
tests might include any of the methods incorporated by reference in
section 2.1.5.1 of Appendix D; meter testing against a certifiable
``master'' meter under section 2.1.5.2 of Appendix D; or transmitter or
transducer accuracy testing under section 2.1.6.1 of Appendix D, and
inspection of a primary element for an orifice-, nozzle-, or venturi-
type fuel flowmeter under section 2.1.6.6 of Appendix D. This approach
is proposed in today's rule.
The utilities supporting the idea of using fuel flowmeter data
taken immediately after a flowmeter quality assurance test have
suggested that it would be important to have a fairly large number of
hours in the baseline, on the order of 100 or more, to ensure that the
baseline period is representative of typical operation (see Docket A-
97-35, Item II-E-33). In today's rule, EPA is proposing to use the
first 168 hours of quality assured data measured by that flowmeter for
which: (1) only the fuel measured by that fuel flowmeter is combusted;
(2) the unit load is not significantly ``ramping'' up or down; and (3)
the unit load is safely above the minimum safe, stable load. The Agency
believes that a baseline period containing 168 hours of data is
sufficiently long to be representative of different unit operating
conditions that may occur later. This specific time period is
consistent with the minimum number of hours that a unit combusts a fuel
before the quarter counts toward the deadline for the next quality
assurance test, and with the minimum number of hours that a unit
combusts a fuel before a quarter needs to be evaluated using the fuel
flow-to-load ratio. Certain hours would be excluded from the baseline
(i.e., periods of co-firing, unstable, or low load), because the fuel
flow-to-load ratio or GHR would tend to be less reliable during those
periods.
Today's proposal would also limit the baseline period so that it
may extend no more than two quarters beyond the quarter in which the
flowmeter passes its accuracy tests. The Agency has concerns that if
the baseline data were to extend longer than this, the performance of
the fuel flowmeter might degrade. In order for the baseline data to
reflect fuel flow rate data that are most likely to be accurate, the
Agency is proposing that the fuel flow rate or heat input rate data
used in the baseline period must either be obtained in the calendar
quarter in which the quality assurance procedure is performed, or
within two calendar quarters after the QA test. The Agency considered
limiting the time period to the same calendar quarter as the quality
assurance procedure or to one flowmeter operating quarter beyond the QA
test. However, because a quality assurance procedure may be conducted
at any time during a quarter, it could be difficult for a facility to
collect 168 hours of fuel flowmeter data after a quality assurance
procedure in the same calendar quarter or even (for infrequently
operated units that ramp
[[Page 28093]]
up and down often) in the next calendar quarter.
For orifice-, nozzle-, and venturi-type fuel flowmeters, two
quality assurance procedures would be required prior to collecting the
baseline data: (1) a transmitter or transducer accuracy test, and (2)
an inspection of a primary element. The Agency considered whether these
two quality assurance procedures should be separated and whether the
baseline period could simply be based upon a time period after the most
recent quality assurance procedure. The Agency believes that the
baseline period data would be more reliable if they were taken shortly
after completing both quality assurance procedures for orifice-,
nozzle-, and venturi-type fuel flowmeters. Using the same time period
for both tests simplifies administration of the fuel flow-to-load ratio
test. EPA also notes that a unit does not need to be operating in order
to perform the tests; thus, it should not be burdensome for a facility
to plan to coordinate the two quality assurance procedures.
(3) Data Preparation and Analysis. The proposed procedures for data
preparation and analysis for the fuel flow-to-load ratio are similar to
those for the volumetric stack flow-to-load ratio. Equations of the
same form as those for the stack volumetric flow-to-load ratio are used
to calculate the hourly fuel flow-to-load ratio, the hourly absolute
value of the percentage difference between the baseline fuel flow-to-
load ratio and the hourly fuel flow-to-load ratio, and the quarterly
average percentage difference. Common pipe headers would be treated in
the same way as common stacks. If there were multiple units associated
with a single fuel flowmeter or flow monitor, the total load from all
units would be summed before the flow rate data are divided by the load
data to calculate the flow-to-load ratio. Fuel flowmeters on multiple
pipes would be treated in the same way as multiple stacks associated
with a single unit. If there are multiple fuel flowmeters or flow
monitors associated with a single unit, the flow rates from all fuel
flowmeters for the same fuel or all flow monitors would be added
together before the flow rate data are divided by the load data to
calculate the flow-to-load ratio.
Certain aspects of the volumetric stack flow-to-load ratio test are
not the same for the fuel flow-to-load ratio test. For example, the
volumetric stack flow-to-load ratio test requires the facility to
screen out those hours when the unit operates further than 10.0 percent
away from the average load during the most recent normal-load flow
RATA. As was discussed previously, there is no equivalent of an in-line
flow RATA for fuel flowmeters. EPA does not believe that there is a
need to screen out hours for the fuel flow-to-load test when the unit
operates at a load somewhat less than or greater than normal. Some
facilities have indicated that the fuel flow-to-load ratio or GHR based
on fuel flow readings is less variable over different loads than the
volumetric stack flow-to-load ratio (see Docket A-97-35, Items II-E-33
and II-D-98). However, preliminary evidence has also indicated that the
fuel flow-to-load ratio or GHR can be significantly different at very
low operating loads than at other load levels (see Docket A-97-35, Item
II-A-5). For this reason, EPA is proposing to allow hours in which the
unit load is within the lower 10.0 percent of the range of operation to
be excluded from both the baseline data and the quarterly flow-to-load
or GHR analysis, unless such low loads are considered normal for the
unit.
Another feature of the volumetric stack flow-to-load ratio test
that differs from the fuel flow-to-load ratio test is the treatment of
bias-adjusted data. Fuel flow rate data are never adjusted for bias.
There is no bias test for fuel flowmeters. Bias-adjustment of data is
an issue for the volumetric stack flow-to-load ratio test because bias-
adjusted data has already been adjusted to make it more consistent with
the value of the reference method data. Thus, bias-adjusted volumetric
stack flow data must meet a stricter quarterly average percentage
difference of 10.0 percent from the reference flow-to-load ratio,
whereas the allowable difference is 15.0 percent when unadjusted
volumetric stack flow data are used. (See discussion of stack flow-to-
load test in Section III.M. of this preamble.) EPA notes that since the
same fuel flow meter is used to produce both the baseline data and the
quarterly data, the fuel flow-to-load ratio is more closely analogous
to the use of bias-adjusted volumetric flow data. Therefore, the limit
on the quarterly average percentage difference from baseline for fuel
flow rate data should be at least as stringent as that for bias-
adjusted volumetric flow data (10.0 percent). Information provided by
facilities on the gross heat rate derived from fuel flow rate data have
shown less variability than the corresponding stack heat rate (see
Docket A-97-35, Item II-D-98). Based upon this information, EPA is
proposing a limit of 10.0 percent on Ef, the quarterly
average percentage difference from the baseline for the quarterly flow
rate-to-load or GHR evaluation. EPA considered whether it would be
appropriate to set a different limit for smaller units, as was done for
the stack flow-to-load test. Analysis of some preliminary fuel flow-to-
load data has shown that for lower loads (e.g., < 50 MWe), the flow-to-
load ratio is quite sensitive to small changes in load (see Docket A-
97-35, Item II-A-5). This indicates that it would be appropriate to set
a higher limit for smaller units. Therefore, today's rule proposes a
limit of 15.0 percent on the value of Ef when the quarterly
average load used for the data analysis is 50 megawatts or less (or
500 klb steam per hour). The Agency solicits comment on the
15.0 percent limit for loads less than or equal to 50 megawatts.
(4) Optional Data Exclusions. As for volumetric stack flow
monitors, if a fuel flowmeter's data would not meet the limit on the
percentage deviation from the baseline, then a facility could opt to
exclude certain hours of unrepresentative fuel flow rate (or heat input
rate) data and then reanalyze the smaller set of data. The hours of
data that EPA proposes to view as non-representative for fuel
flowmeters are: (1) hours when the unit combusts multiple fuels; (2)
hours when the unit load in a given hour would differ by more than
15.0 percent from the load during either the previous hour
or the subsequent hour; or (3) hours when the load is very close to the
minimum safe, stable load (unless operation in that range is normal).
The baseline period for fuel flowmeters and the data used for the
quarterly flow-to-load or GHR analyses would include only those hours
when a single fuel is combusted--the fuel measured by the fuel
flowmeter. If the quarterly fuel flow rate data included hours when
multiple fuels are co-fired, the fuel flow-to-load ratio or GHR for the
fuel flowmeter being tested would be biased low. This could result in a
failure of the flow-to-load test or GHR evaluation. Today's proposed
rule would also allow a facility to exclude from the baseline data and
the quarterly analyses those hours that are not representative because
the unit's load is changing rapidly. Specifically, hours could be
excluded when the unit load in a given hour would differ by more than
15.0 percent from the load during either the previous hour
or the hour afterwards. There will be a lag in the time between when
electricity is generated and registered as load and the time that the
fuel flowmeter measures the fuel that is combusted to generate the
load. Therefore, during an hour when the load changes rapidly, the fuel
flow rate will not necessarily be changing by the same amount or in the
[[Page 28094]]
same direction. At least one utility has suggested that the Agency
consider such an exclusion for the proposed fuel flow-to-load ratio
test (see Docket A-97-35, Item II-D-41).
In general, the fuel flow is directly proportional to load, with a
linear graphical relationship. However, this is not always the case at
extremely low loads (see Docket A-97-35, Items II-E-33, II-D-98).
Therefore, today's proposed rule would allow certain low-load hours to
be excluded from the flow-to-load baseline and quarterly data analyses.
Specifically, loads in the lower 10.0 percent of the ``range of
operation'' of the unit, (as that term is defined in proposed section
6.5.2.1 of Appendix A in today's proposal) could be excluded, unless
such loads are considered normal for the unit.
Today's proposed rule, in section 2.1.7 of Appendix D, would also
exempt a fuel flowmeter from the fuel flow-to-load ratio test in a
quarter when a more rigorous quality assurance test is performed. This
is unlike the volumetric stack flow-to-load ratio, which is required
each QA operating quarter, including quarters when the flow monitor is
tested with a RATA (provided, of course, that sufficient data for the
analysis are obtained after the RATA).
(5) Consequences of Failing the Fuel Flow-to-Load Ratio Test. The
consequences of failing the fuel flow-to-load ratio test would be
similar to the consequences of failing quality assurance tests in
general for fuel flowmeters. Data from the fuel flowmeter would no
longer be considered quality assured. Because the fuel flow-to-load
ratio test is only performed at the end of a quarter, the facility
would invalidate data from the fuel flowmeter beginning with the first
hour in the quarter after the quarter in which the meter fails the fuel
flow-to-load ratio test. In order to establish that the fuel flowmeter
is operating properly and providing quality assured data again, the
facility would perform a flowmeter accuracy test or (for orifice-,
nozzle-, and venturi-type flowmeters) a transmitter or transducer
accuracy test. The Agency believes it is appropriate to perform an
accuracy test if the fuel flow-to-load ratio test is failed, because in
such cases the facility has had the benefit of postponing the accuracy
test based upon the assumption that the fuel flowmeter has continued to
measure accurately and consistently with its operation during the
baseline period.
Note that for orifice-, nozzle-, and venturi-type fuel flowmeters,
a transmitter/transducer test alone would not suffice to demonstrate
that the flowmeter is back in control. The owner or operator would
still need to ensure that the cause of the failed fuel flow-to-load
ratio test was a problem with the transmitters or transducers rather
than a problem with the primary element. Sudden changes in flowmeter
performance are likely to be caused by a problem with transmitters (see
Docket A-97-35, Item II-D-33). However, it cannot be assumed that the
transmitters are solely responsible for degradation in monitor
performance. In order to verify that the primary element is not
contributing additional error to the fuel flow measurements because of
corrosion, a facility would conduct an abbreviated (6 to 12 hour)
version of the fuel flow-to-load ratio test, similar to the diagnostic
test for volumetric stack flow monitors in Policy Manual Question 13.15
(see Docket A-97-35, Item II-I-9). The Agency believes that this
abbreviated fuel flow-to-load ratio test would provide additional
assurance that the fuel flowmeter is indeed operating properly. In
addition, it would be more timely than waiting for another calendar
quarter to pass to repeat the fuel flow-to-load ratio. The abbreviated
test would also be less burdensome than removing the primary element
from the fuel pipe. EPA believes the abbreviated fuel flow-to-load
ratio test strikes a reasonable balance by providing some additional
quality assurance in a timely manner. If the orifice-, nozzle-, or
venturi-type fuel flowmeter failed the abbreviated fuel flow-to-load
ratio test, then it would appear that the primary element may also have
a problem. Therefore, upon failure of an abbreviated fuel flow-to-load
ratio test, the facility would be required to inspect the primary
element and to repair or replace it, as necessary.
The rules for data validation upon failure of the fuel flow-to-load
ratio are not parallel with the procedures for data validation
following failure of the volumetric stack flow-to-load ratio test in
that there is no conditional validation of data. A number of utilities
have emphasized that they wish to spend less time and effort preparing
and evaluating quarterly reports for units using Appendix D, which are
generally smaller and less frequently operated than coal-fired units or
oil-fired units that choose to use CEMS (see Docket A-97-35, Item II-E-
33). The concept of conditional data validation for fuel flowmeters is
not consistent with this objective, because it would introduce
additional complexity into the process, would require significantly
more time and resources to quality-assure the data, and might require
additional DAHS programming. Therefore, the Agency is not proposing the
use of conditional data validation for fuel flowmeters.
(c) Fuel Flowmeter Quality Assurance Testing Frequency
Background
Section 2.1.6.1 of Appendix D, as revised by the May 17, 1995
direct final rule, requires regular quality assurance
``recalibrations'' (accuracy tests) of fuel flowmeters at least
annually (once every four calendar quarters). For fuel flowmeters that
were not used on a regular basis, such as fuel flowmeters used to
measure the usage of emergency fuel or backup fuel, or flowmeters
installed on peaking units, owners or operators are allowed to do
flowmeter accuracy tests once every four quarters when the unit
actually combusts the fuel measured by the flowmeter, rather than once
every four calendar quarters. Flowmeters can be retested either by
using one of the methods incorporated by reference in section 2.1.5.1
of Appendix D to part 75 or by an in-line comparison of the fuel
flowmeter against a ``master'' fuel flowmeter using the procedure in
section 2.1.5.2 of Appendix D.
Some utilities have expressed concern about the annual fuel
flowmeter testing requirement (see Docket A-97-35, Items II-D-20, II-E-
13, II-E-14). In many cases, it is neither practical nor cost-effective
to modify the fuel pipes (e.g., to install a parallel length of pipe)
to allow installation of a master fuel flowmeter for comparison
testing. Thus, most utilities must remove a fuel flowmeter from the
pipe and return it to a laboratory or to the manufacturer to be
retested. In some cases, especially for oil flowmeters, this can be
difficult.
Some utilities have raised the issue of whether there should be a
minimum time period that a fuel flowmeter is used before a quality
assurance test is required. For instance, a utility might test its
unit's burners once each quarter for a few hours to ensure that the
unit can be operated when needed and may not operate for the rest of
the quarter. Under the current rule, the fuel flowmeter would have to
be quality assurance tested after four such operating quarters, even
though the flowmeter was only used for a few hours in those calendar
quarters.
Discussion of Proposed Changes
Today's proposed rule includes a provision that only those calendar
quarters in which the fuel measured by the fuel flowmeter is combusted
for at least 168 hours would count toward determining the next quality
assurance test deadline. The 168-hour time period
[[Page 28095]]
is roughly equivalent to one week of operation while combusting the
fuel measured by a particular fuel flowmeter. A calendar quarter in
which the fuel measured by a fuel flowmeter is combusted for 168 hours
or more would be called a ``flowmeter operating quarter.'' For example,
if a unit combusted oil for 200 hours in the first calendar quarter of
the year, 10 hours in the second calendar quarter, 250 hours in the
third calendar quarter, and 100 hours in the fourth calendar quarter,
then only the first and third calendar quarters would be considered
flowmeter operating quarters for the oil flowmeter. Only the first and
third calendar quarters would count toward determining the deadline for
the next required oil flowmeter accuracy test.
In today's proposed rule, each fuel flowmeter would need to be
accuracy tested at least once every four flowmeter operating quarters.
However, the deadline for testing infrequently-used meters could not be
extended indefinitely. No more than 20 calendar quarters (five years)
would be allowed to elapse between successive flowmeter accuracy tests,
regardless of the number of ``flowmeter operating quarters'' that have
elapsed since the last test. The interval between successive quality
assurance tests could also be extended for up to 20 calendar quarters
if the quarterly fuel flow rate-to-load procedures in proposed section
2.1.7 of Appendix D were implemented.
Rationale
In evaluating the frequency of fuel flowmeter accuracy testing, EPA
considered simply extending the less strict requirement for fuel
flowmeter quality assurance testing for peaking units, backup fuel, and
emergency fuel to apply to all units and all fuel flowmeters. Thus,
quality assurance testing would be required once every four quarters in
which the unit combusted the fuel measured by the flowmeter.
One industry representative recommended that the Agency require
fuel flowmeter calibrations once every four unit operating quarters,
where a unit operates at least 168 hours in the quarter (see Docket A-
97-35, Item II-E-13). This approach would treat all fuel flowmeters the
same, whether they were used for primary, emergency, or backup fuel.
Another utility suggested that the Agency consider creating some
sort of diagnostic test comparing the flow rate of the fuel flowmeter
to the unit load (generation) to determine whether the fuel flowmeter
readings are degrading over time, rather than specifying a particular
frequency for accuracy testing (see Docket A-97-35, Item II-E-22).
Although this suggestion was originally referring to problems with
corrosion of an orifice plate, such a test could also be used for other
types of fuel flowmeters as a check on the quality of fuel flowmeter
data.
The Agency also considered extending the typical time between
accuracy tests to the equivalent of two years. This time was suggested
by a member of the AGA subcommittee responsible for the drafting of AGA
Report No. 7 for turbine-type flowmeters (see Docket A-97-35, Item II-
E-17). The Agency also considered extending the typical time between
accuracy testing to 12 calendar quarters--the equivalent of three
years. Three years is the period of time that records must be retained
in a file at the source under Sec. 75.54 (or proposed Sec. 75.57).
The Agency also considered allowing fuel flowmeters to continue for
up to five calendar years between accuracy tests. This is similar to
the current provision in section 2.1.5.2 of Appendix D, which allows a
reference fuel flowmeter to be accuracy tested as seldom as once in
five calendar years, if the in-line comparison with a master fuel
flowmeter shows a 1.0 percent or less difference in their flow rates. A
five-year test cycle offers certain administrative advantages. For
instance, fuel flowmeters used to provide heat input data for the heat
input-versus-load correlation of Appendix E could be accuracy-tested
before each Appendix E test (i.e., once every five years). In addition,
the five calendar-year period would ensure that fuel flowmeters are
tested by the time the unit's operating permit is renewed. Facilities
might find this time cycle easier to determine than a time period based
upon a number of calendar quarters. However, test data would need to be
retained for five years, rather than for three years, the recordkeeping
period for most records under part 75. However, the Agency is not
proposing this option because five years is far too long a period of
time to allow a unit to continue with no checks at all upon the quality
of its data. Such an approach would allow the use of data from a fuel
flowmeter that potentially had been reading inaccurately for the
previous five years.
Another option that EPA evaluated was to establish different fuel
flowmeter quality-assurance testing frequencies depending on the fuel
measured by the fuel flowmeter. Under this approach, oil flowmeters
would need to be tested every four calendar quarters in which oil was
combusted. Gas flowmeters would only need to be tested once every five
years. The two fuels would be treated differently because units emit
less NOX and far less SO2 when combusting gas
than when combusting oil. In addition, gaseous fuels, particularly
pipeline natural gas, should be less corrosive; therefore, a gas
flowmeter should be less likely to degrade than an oil flowmeter.
EPA believes that today's proposed approach to reducing the fuel
flowmeter quality assurance testing frequency takes into account many
of the concerns raised by utilities. All unit types and fuel types
would have the same frequency of testing. This would avoid confusion
that could follow from an approach that set different requirements for
fuels or units that are used less frequently. A group of utilities had
indicated that they prefer a more consistent approach (see Docket A-97-
35, Item II-E-13). Under today's proposal, infrequently-used fuel
flowmeters (e.g., meters for backup fuel or emergency fuel) would only
need to be calibrated once every five years. When a facility renews its
operating permit, the permitting agency could verify that all fuel
flowmeters have been tested at least once in the previous five years.
The minimum period of 168 hours of fuel flowmeter usage which
defines a ``flowmeter operating quarter'' is consistent with the
definition of a ``QA operating quarter'' in Appendix B in today's
proposed rule for the quality assurance of CEMS. The Agency believes
that using a consistent minimum number of hours in a calendar quarter
for both CEMS and fuel flowmeters will make implementation easier for
facilities and air regulatory agencies. In addition, 168 hours should
be a sufficiently long period of time to ensure that short-term usage
of backup fuel or emergency fuel or short-term tests of a unit do not
trigger unnecessary quality assurance testing.
Today's proposed rule would also provide more flexibility in the
methods that could be used for fuel flowmeter quality assurance
testing. As discussed above in Section III.P.2 of this preamble, a new
testing procedure has been proposed that would allow a facility to test
flow rate-to-load ratio of the fuel flowmeter while leaving it
installed. Thus, the Agency believes that the overall burden of fuel
flowmeter testing has been significantly reduced. In addition to the
reduced frequency of testing discussed above, the Agency believes the
less burdensome testing procedures should address concerns of the
regulated community.
The Agency requests comment on whether facilities would prefer to
base
[[Page 28096]]
the frequency of fuel flowmeter quality assurance testing on the type
of fuel used or the amount of time the fuel flowmeter is used. Under
the first approach, gas flowmeters would receive greater regulatory
relief. Under the second approach, which is being proposed in today's
rule, infrequently-used flowmeters (typically oil flowmeters) would
receive greater regulatory relief.
(d) Orifice, Nozzle, and Venturi Visual Inspections
Background
Section 2.1.6 of Appendix D, as revised in the May 17, 1995 direct
final rule, created special provisions for the ongoing quality
assurance testing of orifice fuel flowmeters. Orifice-,
nozzle-, and venturi-type fuel flowmeters are designed and installed
within a set of physical specifications, such as the orifice diameter
(see Docket A-97-35, Item II-D-13). Maintaining these physical
specifications determines the flowmeter's ability to read accurately.
Thus, it is not necessary to take an orifice-, nozzle-, or venturi-type
flowmeter out of line and send it to a laboratory to determine its
accuracy.
After installation of an orifice-, nozzle-, or venturi-type
flowmeter is complete, the two major factors that contribute to error
in flow readings are: drift in the transmitters (or transducers) which
determines the total pressure, differential pressure and temperature,
and corrosion of the primary element (e.g., the orifice plate) itself.
Quality assurance testing of the transmitters is discussed in the next
section of the preamble. In order to identify cases where error might
result from corrosion of the orifice plate, the May 17, 1995 direct
final rule added a requirement for an annual visual inspection of the
orifice plate. If an orifice plate fails the inspection, then the
facility must perform a test on the transmitters during the next
calendar quarter. A procedure for visual inspections is given in
Appendix B of part 2 of American Gas Association (AGA) Report No. 3,
which is one of the accepted standards for installation and use of
orifice flowmeters.
Some facilities have expressed concern with the frequency of visual
inspections (see Docket A-97-35, Items II-D-20, II-E-13, II-E-14). This
process must be done either with a tool, such as a boroscope, or else
the primary element must be removed from the pipe and lifted out to be
inspected. In the case of large, heavy orifices, it is necessary to use
a crane to remove the orifice. Fuel must not be flowing through the
pipe while the orifice plate is being removed (see Docket A-97-35, Item
II-E-8).
The current provisions of Appendix D to part 75 do not explicitly
state the consequences of failing a quality assurance test. Section
2.1.5.1 of Appendix D states that if a fuel flowmeter exceeds the
flowmeter accuracy of 2.0 percent of the upper range
value, then the flowmeter may not be used under part 75. Section
2.1.5.2 states that if a fuel flowmeter's accuracy exceeds
2.0 percent of the upper range value, then the flowmeter must be
recalibrated to meet that accuracy, or it must be replaced with another
flowmeter that meets the specification. Neither section explicitly
states the impact upon the validity of data if a test is failed.
However, if fuel flowmeter systems are to be treated parallel with
continuous emission monitoring systems under Sec. 75.21(e)(2), the
consequences of failing a quality assurance test for a fuel flowmeter
or an inspection of the primary element should result in the monitor
being considered out-of-control and the data being considered invalid.
In section 2.1.6.1 of Appendix D, the specific consequence of
failing a visual inspection of the primary element is that the
transmitters must be tested in the following calendar quarter, rather
than waiting until the regular annual calibration is required. However,
no mention is made of any mandatory corrective action(s) to eliminate
the corrosion problem.
Discussion of Proposed Changes
Section 2.1.6.6 of Appendix D in today's rulemaking proposes to
require visual inspections of primary elements (i.e., orifice, nozzle
or venturi) at the frequency recommended by the manufacturer or once
every three years, whichever is more frequent. The Agency solicits
comment on the proposed frequency of visual inspections.
The proposed rule would also explicitly require repair or
replacement of the primary element and invalidation of data when a
visual inspection is failed. Once the primary element is replaced or
repaired, the new or repaired primary element would have to demonstrate
that it meets the overall flow rate accuracy of 2.0
percent of the upper range value. This could be demonstrated by showing
that the new or repaired primary element meets the design and
installation requirements of AGA Report No. 3 or ASME MFC-3M, the same
methods required for initial certification. Alternatively, the flow
rate accuracy could be demonstrated by testing the fuel flowmeter
against a reference fuel flowmeter using the provisions of section
2.1.5.2 of Appendix D. Finally, whenever a primary element is repaired,
the fuel flowmeter transmitters would also have to be tested before the
fuel flowmeter is used to provide quality assured data.
Rationale
During the process of reviewing certification applications for
units using orifice flowmeters, the Agency learned of one plant where
orifice corrosion was a serious problem. This utility had an orifice
flowmeter which had been installed in the 1960's. This utility did not
have documentation of the standard used to install the orifice as a
demonstration of the meter's accuracy. In order to qualify for
certification, the utility inspected the orifice. The utility personnel
discovered that the orifice had been completely eaten away and was
incapable of reading the flow rate (see Docket A-97-35, Item II-E-22).
The utility replaced the orifice before it was able to have its fuel
flowmeter certified. In addition, it was required to invalidate the
flow rate data from the orifice meter and substitute for the missing
data. Based upon this experience, the Agency believes that corrosion of
an orifice can be a problem, and that in severe cases of corrosion,
replacement of the orifice is necessary.
Despite this, many utilities have expressed concern over the
difficulty of removing an orifice from place for visual inspection (see
Docket A-97-35, Items II-D-20, II-E-13, II-E-14), because removal
requires halting the flow of gas through the pipeline in order to
remove the orifice, which can be expensive (see Docket A-97-35, Item
II-E-8).
Utilities have provided the Agency with several suggestions for
reducing the frequency of primary element inspections. One industry
group recommended that the Agency reduce the inspection frequency to
once every five years, to be coordinated with renewal of the plant's
operating permit under title V of the Act (see Docket A-97-35, Items
II-D-20, II-E-13, and II-E-14). One utility representative mentioned
that most orifice manufacturers recommend an inspection once every
three years; thus, he recommended that the Agency require visual
inspections the earlier of once every three years or the time period
specified by the manufacturer (see Docket A-97-35, Item II-D-41).
Another utility suggested that the Agency consider creating some sort
of diagnostic test comparing the flow rate of the fuel flowmeter to
unit load (generation) to determine whether the fuel flowmeter readings
are degrading
[[Page 28097]]
over time, rather than specifying a particular time period (see Docket
A-97-35, Item II-E-22).
EPA agrees that it would be helpful to facilities to reduce the
frequency of visual inspections from their current annual frequency.
Having considered all of the options suggested by the utilities, the
Agency is proposing that the primary element of all nozzle, venturi and
orifice fuel flowmeters be visually inspected at the frequency
recommended by the manufacturer or once every three years, whichever is
the more frequent. The Agency believes that up to three years between
visual inspections is a technically sound period of time that will
assure the quality of fuel flow rate data, while providing regulatory
relief from the current annual requirement.
The Agency also has reconsidered the consequences of failure of a
visual inspection. The May 17, 1995 direct final rule added a
requirement to test a flowmeter's transmitters in the calendar quarter
following a failed inspection, but the rule does not explicitly require
that the primary element be repaired or replaced, nor does it
explicitly require data from the fuel flowmeter to be invalidated.
Today's proposed rule would require the primary element to be
removed following a failed visual inspection and would require the
problem to be corrected. The Agency believes that it is appropriate to
provide two options for correcting the problem: either replace the
element with a new one or repair it. This would provide flexibility to
facilities, while still assuring that the fuel flowmeter will be
repaired to give quality assured data.
Today's proposed rule would also change the timing of the
requirement for fuel flowmeter transmitter or transducer testing if a
primary element fails its visual inspection. The Agency believes that
it would be appropriate also to test the fuel flowmeter transmitters
before the fuel flowmeter is placed into service again. This would be a
more thorough quality assurance check of the entire fuel flowmeter than
simply addressing the problem with the primary element. Thus, when the
fuel flowmeter is placed into service again, its accuracy would be
tested as fully as possible. In addition, EPA proposes to remove the
requirement for a test on the flowmeter transmitters in the calendar
quarter following a failed visual inspection. This requirement might be
appropriate if it seemed that transmitter drift was likely to be a
problem or if the Agency had no other means of assuring the quality of
the data from the flowmeter after a problem with the primary element
was known to have occurred. However, the Agency believes that problems
with the primary element are separate from problems with drift in the
transmitters. Because today's proposal would require a check on the
fuel flowmeter transmitters after repair or replacement of the primary
element, requiring an additional test of the transmitters in the
following calendar quarter appears to be unnecessary.
The proposed rule gives procedures for data validation when a
primary element fails a visual inspection. The element would have to be
replaced or repaired, and the transmitters would have to be tested
before data would again be valid from the fuel flowmeter. During the
period in which the flowmeter data are considered invalid, the
appropriate missing data substitution procedures would be used. The
Agency has clarified that these data validation procedures would also
apply to failures of other fuel flowmeter quality assurance tests. EPA
believes that this will make facilities' obligations clearer. In
addition, the Agency believes that fuel flowmeter systems should be
treated as consistently as possible with CEMS. Consistent treatment
simplifies the part 75 requirements and is more equitable for sources
using different monitoring approaches.
(e) Orifice, Venturi, and Nozzle Flowmeter Transmitter Testing
Background
As discussed previously, once an orifice-, nozzle-, or venturi-type
flowmeter has been installed, one of the major causes of error in the
measured flow rates is drift in the transmitters or transducers that
determines the total pressure, differential pressure, and temperature.
The flow measurement error for these types of flowmeters is a
combination of the errors in these individual transmitters or
transducers and a constant error value associated with the physical
dimensions of the primary element. The May 17, 1995 direct final rule
added a requirement that flowmeter transmitters be tested at least
annually. The transmitters are also required to be retested in the next
calendar quarter if the overall flow rate error is greater than 1.0
percent of the upper range value of the flowmeter. For practical
purposes, this requires a facility to know the error from the physical
dimensions of the primary element in order to determine if the
flowmeter meets the overall accuracy requirement.
Some utilities asked the Agency how to determine the overall
flowmeter accuracy from individual transmitter values (see Docket A-97-
35, Item II-E-31). EPA addressed this issue in Policy Guidance (see
Docket A-97-35, Item II-I-9, Policy Manual, Question 10.17). This
guidance included a formula for calculating total flowmeter accuracy
from error in transmitter readings for differential pressure, static
pressure and temperature, and error from all other sources (i.e.
physical dimensions of the primary element). Some utilities indicated
that they do not always have information available on the constant
error from other portions of the primary element (see Docket A-97-35,
Item II-E-13). The policy guidance also indicated that a facility could
report test results electronically using the highest amount of error
from any of the three transmitters. Provided that the highest error
from an individual transmitter is 1.0 percent of the upper range value
of the transmitter or less, the overall flowmeter accuracy will be less
than 2.0 percent of the upper range value (see Docket A-97-35, Item II-
I-10).
EPA has also observed that transmitter test data reported for
orifice-, nozzle-, and venturi-type flowmeters have not been
consistent. Some facilities test each transmitter once at three
different levels, including a low, middle, and high value (see Docket
A-97-35, Item II-D-16). Others test each transmitter at five different
levels, including zero, full scale, and three intermediate levels (see
Docket A-97-35, Item II-D-17). The Agency had previously issued some
guidance on reporting test results, both for orifice flowmeters and
other flowmeters (see Docket A-97-35, Items II-I-4, p. 3-58, and II-I-
9, Policy Manual, Questions 10.17 and 12.27). However, this guidance
appears to have been insufficient, as utilities have continued to
request guidance in how to perform and report test results (see Docket
A-97-35, Item II-D-21). Questions have included the number of levels at
which transmitters should be tested, whether all of these levels must
be non-zero, the number of times the transmitter should be tested at a
particular level, if results may be reported in hardcopy or should be
reported electronically, and how data should be reported
electronically.
Discussion of Proposed Changes
Today's proposed rule would make the requirement to assess the
total accuracy of orifice-, nozzle-, and venturi-type fuel flowmeters
from the transmitter/transducer test results an option. As an
alternative, proposed section 2.1.6.5 in Appendix D would allow each of
the three transmitters (static pressure, differential pressure, and
temperature) individually to meet
[[Page 28098]]
an accuracy specification of 1.0 percent of the upper range value of
the transmitter.
Today's rulemaking also proposes a procedure in section 2.1.6.1 of
Appendix D for testing the accuracy of orifice-, nozzle-, and venturi-
type fuel flowmeters. Each transmitter would be calibrated against
NIST-traceable reference values at least once at the zero level and at
a minimum of two other levels across the range of values that the
transmitter reads during normal unit operation. Note that in many
instances this would be a portion of the full-scale range of the
transmitter, rather than the entire range. In addition, revised section
2.1.6.2 of today's proposed rule includes the new Equation D-1a to
clarify how to calculate the error from an individual transmitter.
Finally, today's proposal would clearly specify the consequences of
failure of an accuracy test on transmitters in section 2.1.6.5 of
Appendix D. Just as CEM data are considered invalid from the time that
a quality assurance test is failed until the test is subsequently
passed, data from a fuel flowmeter would be considered invalid from the
date and time of a failed transmitter accuracy test until the date and
time of a passed transmitter accuracy test.
Rationale
The Agency considered two main options for determining the accuracy
of a transmitter or transducer of an orifice-, nozzle-, or venturi-type
fuel flowmeter. In the first approach (which is consistent with current
policy guidance), these types of fuel flowmeters would be required to
meet an accuracy of 2.0 percent of the upper range value of the total
flow rate of the fuel flowmeter. The accuracy would be determined using
the square root of the sum of the squares of all sources of error in
the fuel flowmeter, according to the following equation:
[GRAPHIC] [TIFF OMITTED] TP21MY98.000
Where: dqv/qv = Error in the volumetric flow rate
due to transmitter drift at a given level;
K = Original error resulting from installation of orifice (including
all other variables);
dPf = Average difference between static pressure transmitter
reading(s) and reference static pressure reading(s) at a given level;
Pf = Average reference static pressure reading at a given
level;
dP = Average difference between differential pressure
transmitter reading(s) and reference differential pressure reading(s)
at a given level;
P = Average reference differential pressure reading at a given
level;
dTf = Average difference between temperature transmitter
reading(s) and reference temperature reading(s) at a given level; and
Tf = Average reference temperature reading at a given level.
If the error calculations for error from the primary element of the
fuel flowmeter were not available, then the facility could use a
default value of 1.0 percent of the upper range value error from all
parts of the fuel flowmeter except for the differential pressure,
static pressure, and temperature transmitters. (In other words, the
factor ``K'' in the equation above would be equal to 1.0 percent of the
upper range value.) However, this would almost certainly trigger the
requirement for recalibration or retesting of the accuracy of the
transmitters in the next calendar quarter because the fuel flowmeter
accuracy would exceed 1.0 percent of the upper range value. Based upon
statements from the American Gas Association, it is the Agency's
understanding that for an orifice-, nozzle-, or venturi-type fuel
flowmeter meeting AGA Report No. 3 or ASME MFC-3M, the maximum error
from portions of the meter other than the transmitters should be 1.0
percent of the upper range value (see Docket A-94-16, Item II-F-2, and
this Docket, A-97-35, Item II-E-18).
In the second approach to determining error for orifice-, nozzle-,
and venturi-type fuel flowmeters, each transmitter or transducer would
be tested separately for accuracy, and each transmitter or transducer
would be required to meet an accuracy specification of 1.0 percent of
the full scale range of the transmitter. Under this approach, it would
no longer be necessary to determine the total error in the flowrate
from the fuel flowmeter. Because this proposal would eliminate the
calculation of the total error in flowrate, there would no longer need
to be a requirement to retest the accuracy of the transmitters in the
next calendar quarter when the total fuel flowmeter accuracy exceeds
1.0 percent of the upper range value.
In today's rule, EPA proposes to allow both of the approaches
described above for calculating the total flowmeter accuracy. The
second approach (i.e., calculating individual transmitter accuracy) is
simpler than calculating the total error in the flow rate, although it
is less directly related to the accuracy of SO2 mass
emission rate and heat input measurements than the fuel flowrate. An
individual transmitter accuracy specification of 1.0 percent of the
full scale of each transmitter would be slightly stricter than a total
fuel flowmeter accuracy specification of 2.0 percent of the upper range
value of the fuel flowmeter, because one transmitter could potentially
have an error greater than 1.0 percent of its full scale range while
the entire error in the fuel flowrate would still be less than 2.0 of
the upper range value of the fuel flowmeter. Thus, the option of
calculating the total error in the fuel flowrate has been retained in
today's proposal. At least one industry representative suggested
allowing both approaches of calculating accuracy when testing
transmitters of an
orifice-, nozzle-, or venturi-type fuel flowmeter (see Docket A-97-35,
Item II-E-24).
The Agency considered two main methodologies for transmitter
testing on orifice-, nozzle-, and venturi-type flowmeters. The first
method would be to require a five-point test that checks the linearity
of the transmitter. The transmitter would be tested against an NIST
traceable method (e.g., testing a pressure transmitter against an NIST
traceable deadweight transmitter) at the following percentages of the
full scale range of the transmitter: 0.0 percent, 20.0 to 30.0 percent,
40.0 to 60.0 percent, 70.0 to 80.0 percent, and 100.0 percent. This is
the general approach that was taken by many utilities that provided
transmitter calibration results to EPA (see Docket A-97-35, Items II-D-
26 through 28).
The second method would be to require a comparison to an NIST
traceable transmitter at the zero level and at least two other levels
across the range of readings on the transmitter or transducer. This
would be different from the first method in that the transmitter would
only need to be tested across the range where the transmitter is
[[Page 28099]]
actually used. For example, if a fuel flowmeter transmitter's readings
never rise higher than 60.0 percent of the full scale range of the
transmitter, then the transmitter could be tested at 0.0 percent, 30.0
percent, and 60.0 percent of full scale. These procedures are reflected
in the proposed revised section 2.1.6.1 of Appendix D.
The Agency is proposing the second method in today's rule, i.e.,
that each individual transmitter must be tested at three or more points
across its normal range of readings. EPA realizes that it is standard
industry procedure to test a fuel flowmeter at five levels across its
entire range (see Docket A-97-35, Item II-E-24). However, the Agency is
aware of at least one case where a fuel flowmeter failed to meet an
accuracy specification of 2.0 percent of the upper range value when it
was tested at 100.0 percent of the upper range value. However, the fuel
flowmeter was never used to measure a rate greater than roughly 55.0
percent of the upper range value (see Docket A-97-35, Item II-D-15). If
this flowmeter had only been required to test across the range where
the fuel flowmeter actually measured fuel flow rates, it would have met
the accuracy specification. Section 2.1.5 requires fuel flowmeters that
are tested against a master fuel flowmeter to be tested across the
range of measured fuel flowrate only. Requiring testing of each
transmitter at three or more points across the range of all readings
would still ensure that the transmitter reads accurately across all
readings, while reducing the possibility that the transmitter might
fail an accuracy test because of a high error reading at the high end
of the transmitter's range where the transmitter is never used. At
least one utility has mentioned that this would be helpful (see Docket
A-97-35, Item II-E-24). The Agency solicits comment on the proposed
approach.
Today's proposed rule also includes Equation D-1a for calculating
error from an individual flowmeter transmitter. The Agency feels that
this would clarify the calculation. It also would prevent the possible
confusion that would occur if a facility attempted to use the existing
Equation D-1, which is designed for a fuel flowmeter that is compared
to another fuel flowmeter.
Finally, under today's proposal, when a transducer or transmitter
test is failed, a fuel flowmeter would be considered out-of-control,
and its data would be considered invalid until the date and time the
transmitter is retested and meets an accuracy of 1.0 percent of its
full scale.
(f) Reporting of Fuel Flowmeter Testing Data
Background
As mentioned above in Section III.P.5 of the preamble, utilities
have had questions about how to report the results of their fuel
flowmeter testing data. In certification applications and quality
assurance testing results, utilities have reported test data in a
variety of ways. In some cases, the Agency was unable to determine the
flowmeter accuracy from the testing information provided because data
were not labeled as reference flow rate data, flowmeter data, or
accuracy data. For example, for turbine flowmeters, data on the
reproducibility of the ``K-factor'' was often presented. However, these
are not flow rate data, nor is it clear what the accuracy of the flow
rate is (see Docket A-97-35, Item II-D-9). Sometimes data were
presented in tables. Other data were presented in graphs (see Docket A-
97-35, Item II-D-9). In many cases, Agency or state environmental
agency staff needed to request additional information from utilities to
determine if they had met the accuracy requirement for fuel flowmeters
(see Docket A-97-35, Items II-C-3, II-C-5).
To clarify the requirements for certification applications for fuel
flowmeters, the Agency issued policy guidance about the type of
information to provide (see Docket A-97-35, Item II-I-9, Policy Manual,
Question 12.27). This guidance included a sample table with an example
of how to submit information for a fuel flowmeter that is tested
against a master meter or flow prover reference value.
Discussion of Proposed Changes
EPA proposes to add a sample table to Appendix D (Table D-1) for
summarizing the results of accuracy tests of fuel flowmeters that are
calibrated by comparison against other fuel flowmeters or a prover. In
addition, EPA proposes to add a separate table for summarizing the
results of calibrations of the transmitters or transducers of an
orifice-, nozzle-, or venturi-type fuel flowmeter.
Rationale
In today's proposed rule, EPA would provide clarification in the
form of a table for summarizing the quality assurance test results of
fuel flowmeters that are compared against other fuel flowmeters or a
prover. A second table is provided for summarizing the results of
calibrations of transmitters or transducers of an orifice-, nozzle-, or
venturi-type fuel flowmeter. This second table accounts for differences
in the testing procedure for transmitters or transducers. In both
cases, EPA has tried to make clear what critical information would have
to be reported in order to demonstrate that the fuel flowmeter (or the
transmitter of an orifice-, nozzle-, or venturi-type fuel flowmeter)
meets the accuracy specification. In addition, EPA will design revised
electronic record types with this type of information so that test
results may be more easily reported electronically. The Agency is aware
that this has been difficult or confusing for some utilities (see
Docket A-97-35, Items II-D-23, and II-I-9, Policy Manual, Question
12.27). The Agency also considered adding a sample graph for reporting
accuracy data. However, EPA feels that it would be easier to compare
the data in tabular format and to enter it into the electronic data
format than to enter values from a graph. Most of the graphs provided
to EPA have been relatively easy to read, and there appears to be less
of a need for an example to be included in Appendix D (see Docket A-97-
35, Item II-D-9).
7. Use of Uncertified Commercial Gas Flowmeter
Background
Currently, a facility using Appendix D may either install its own
gas flowmeter or use a commercial gas flowmeter owned by a pipeline
natural gas supplier, provided that the meter meets the reporting and
accuracy requirements of Appendix D, including initial certification
and continuing quality assurance requirements. Some utilities have
suggested to EPA that they would like to be able to use data from the
commercial billing of pipeline natural gas without having to
demonstrate that the gas flowmeter meets initial certification and
continuing quality assurance requirements (see Docket A-97-35, Items
II-D-45, II-D-49). Those utilities assert that because the amount of
gas measured is already subject to market forces, the monitoring should
be sufficiently accurate for the Acid Rain Program. Utilities have
mentioned that gas companies often are already conducting meter
calibrations as quality assurance, but utility customers generally do
not have access to this information (see Docket A-97-35, Items II-D-49,
II-E-33). Facilities would find it advantageous to rely upon their
commercial billing charges for accounting for pipeline natural gas
usage because they would need to devote less time, effort, and money to
the maintenance of gas fuel flowmeters. This is particularly desirable
to facilities since the SO2 emissions from pipeline
[[Page 28100]]
natural gas are extremely low compared to the SO2 emissions
from other fuels.
Discussion of Proposed Rule Changes
Proposed section 2.1.4.2 of Appendix D would allow facilities to
record and report the gas flow rate, the heat input rate, and emission
values based on gas flowmeter readings from a flowmeter used for
commercial billing of pipeline natural gas without meeting the
certification requirements of section 2.1.5 of Appendix D or the
quality assurance requirements of section 2.1.6 of Appendix D under
specified conditions. Relief from the certification and quality
assurance requirements for gas flowmeters used for commercial billing
would be limited to flowmeters where the gas flowmeter is used for
commercial billing under a contract with another company having no
common owner with the unit(s) served by the flowmeter, which would
exclude any gas flowmeters used for transfers of gas between different
divisions, subsidiaries, or affiliates of the same company.
If the commercial billing gas flowmeter would be used without
undergoing certification or quality assurance under part 75
requirements, then the designated representative would need to report
hourly records of the gas flow rate, the heat input rate, and emissions
due to combustion of pipeline natural gas, as well as heat input rate
for each unit if the commercial billing gas flowmeter is on a common
pipe header. This would be similar to the reporting currently done for
a certified gas flowmeter, but no quality assurance records would be
required. The quarterly report would contain record types 303 for fuel
flow rate and heat input rate, record type 314 for the SO2
mass emission rate, either record type 320 or 323 for the
NOX emission rate in lb/mmBtu, and either record type 330 or
331 for CO2 mass emissions. It also would be necessary for
the designated representative to identify the commercial billing gas
flowmeter in Table B (electronic record type 510) of the monitoring
plan for the unit.
So long as the records from the commercial billing gas flowmeter
are the values used for commercial billing, the designated
representative would report those values from the commercial billing
gas flowmeter without adjustment. If the records from the commercial
billing gas flowmeter are not consistent with the values used for
commercial billing because of some problem that needs to be reconciled
between the gas vendor and the facility customer, then the designated
representative would consider the readings from the commercial billing
gas flowmeter to be invalid for that billing period and would report
hourly records using the missing data procedures for fuel flowmeter
data found in section 2.4 of Appendix D for all hours of gas combustion
during that billing period. A facility would not be able to use the
commercial billing value in the quarterly report if the commercial
billing value was different from the value on the commercial billing
gas flowmeter.
Rationale
Utilities have suggested that the purchase of pipeline natural gas
from a vendor is subject to market forces that ensure accurate
monitoring (see Docket A-97-35, Item II-D-49). Utilities have stated
that gas vendors already have procedures for certification and meter
calibration and that the gas vendors have an even greater incentive
than utilities to maintain a high monitor ``uptime'' (i.e.,
availability) for gas fuel flowmeters. Typically, utilities will work
together with their gas vendors if they believe there is any sort of
discrepancy in their monthly billing for pipeline natural gas (see
Docket A-97-35, Items II-D-33, II-E-33).
The Agency believes that this argument is reasonable. However, EPA
also understands that some utilities require their gas vendor to
correct their billing values based upon the evidence of the utility's
own gas flowmeters. In addition, it is likely that utilities will be
combusting more pipeline natural gas in the future as they respond to
current and potential future environmental requirements for reducing
NOX and CO2. Therefore, the Agency believes that
there must be conditions placed upon reporting emissions and heat input
for the Acid Rain Program from gas flowmeters used for commercial
billing if the gas flowmeters will not be required to meet the
certification and quality assurance requirements of part 75.
The Agency is proposing to limit the waiver from certification and
quality assurance requirements to commercial billing gas flowmeters
that are used in billing transactions between companies with entirely
different ownership (e.g., a pipeline natural gas vendor and a separate
electric utility company with no owners in common). Some utilities
requested the relief from quality assurance requirements based upon the
reasoning that a gas vendor would do its own quality assurance and
maintenance, and perhaps with better accuracy than a utility would be
able to maintain, but the utility would not necessarily have access to
the test results and would not have control over what quality assurance
might occur (see Docket A-97-35, Items II-D-49, II-E-33). This
reasoning is sound if the utility and the gas vendor have no common
owners, but it would not necessarily be sound if a gas supplier were
part of the same company as the electric utility. Also, utilities
suggested that a gas vendor may have an incentive to overstate the
amount of gas in order to bill more, rather than having an incentive to
underestimate or under-report (see Docket A-97-35, Item II-D-49). Once
again, this argument is reasonable if the gas vendor is a separate
entity, but may not be reasonable if the gas supplier has common owners
with the electric utility. Therefore, today's proposed rule includes a
limitation on the waiver from certification and quality assurance
requirements for commercial billing gas flowmeters to those gas
flowmeters used for commercial billing between companies with separate
ownership.
EPA solicits comment on the proposed approach of allowing the use
of uncertified fuel flowmeters for purposes of determining emissions
and heat input in the limited circumstances described above.
EPA has proposed in today's rule that a facility may only report
data from a commercial billing gas flowmeter if the data are used in a
commercial transaction. A group of utilities suggested that the Agency
allow facilities to report quarterly SO2 emissions based on
gas supplier data, including any reconciliation that has taken place
(see Docket A-97-35, Item II-D-45). Such a reconciliation between a gas
vendor and its customer may occur if the customer believes there is a
discrepancy in their monthly billing for pipeline natural gas (see
Docket A-97-35, Items II-D-33, II-E-33). If a facility and its gas
vendor determined that gas supply information from a fuel flowmeter
were not sufficiently accurate to purchase gas, then the Agency
presumes the gas supply information is also not sufficiently accurate
for emissions accounting.
The Agency also considered whether a facility should be able to use
the reconciled gas volumes agreed upon for billing if that value were
not from the commercial billing gas flowmeter. In general in the Acid
Rain Program, hand-typed corrections to emissions data are not
permitted (see Docket A-97-35, Item II-I-14), with the primary
exception of cases where sound engineering judgement indicates there is
an obvious error that cannot exist, such as a negative concentration
reading.
[[Page 28101]]
Allowing a facility to enter a commercial billing value by hand would
contradict this basic reporting policy of the Acid Rain Program.
Today's proposed rule also specifies the type and frequency of
information that would be required to be reported by a facility
concerning pipeline natural gas. Some utilities have requested the
ability to report only a quarterly cumulative SO2 mass
emission number for emissions from gas (see Docket A-97-35, Item II-D-
45). However, the Agency believes that there are several reasons for
maintaining hourly heat input rate and emissions data during combustion
of pipeline natural gas. First, hourly data is the most useful interval
of data for air quality modeling in order to see if progress is being
made in reducing emissions. Hourly data from combustion of pipeline
natural gas will become even more important as more units switch to
combusting pipeline natural gas in order to reduce their emissions. In
addition, hourly data are easier to check for anomalous values than
quarterly data. Further, hourly heat input rate data is necessary in
order to determine the NOX emission rate when using the
NOX-versus-heat input rate correlation of Appendix E to part
75. Also, since hourly data are already being recorded, reported, and
processed by automated computer data acquisition and handling systems,
a change to this requirement would require costly reprogramming for
industry and for EPA. For all of these reasons, EPA is proposing that
facilities continue to report hourly gas flow rates, heat input rates,
and emissions from commercial billing gas flowmeters that are not
required to meet the certification and quality assurance requirements
of part 75.
Q. Appendix G
1. Use of ASTM D5373-93 for Determining the Carbon Content of Coal
Background
Appendix G to part 75 provides procedures for determining
CO2 emissions from fuel sampling and analysis instead of
from a CO2 CEMS and a flow monitor. Section 2.1 of Appendix
G includes a mass-balance equation for determining CO2 (see
Equation G-1), the frequency for sampling fuel, and the specific
methods for analyzing fuel for carbon content. Section 2.3 of Appendix
G provides a method for determining CO2 mass emissions from
a gas-fired unit from its heat input using Equation G-4. Some
facilities use Appendix G procedures to determine CO2 mass
emissions every day for their units. Other facilities might use the
procedures of section 2.1 of Appendix G only to provide CO2
mass emissions during extended periods when CO2 data are
missing from their CO2 CEMS, under the provisions of
Sec. 75.36.
A utility and its fuel analysis laboratory contacted EPA concerning
use of an additional ASTM method for analysis of carbon content. The
industry staff felt that the new infrared analysis method, ASTM D5373-
93, was the most up-to-date method and that this method should be at
least as accurate as the methods specified in Appendix G to part 75
(see Docket A-97-35, Item II-D-25). Based upon the precision and bias
information in the method, EPA approved its use under Sec. 75.66 (see
Docket A-97-35, Item II-C-16).
Discussion of Proposed Changes
Today's proposed rule would allow the use of ASTM D5373-93,
``Standard Methods for Instrumental Determination of Carbon, Hydrogen,
and Nitrogen in Laboratory Samples of Coal and Coke,'' for Section 2.1
of Appendix G to part 75. This method is for determining the carbon
content of coal. ASTM D5373-93 would also be incorporated by reference
in Sec. 75.6. Facilities would also continue to have the option to use
ASTM D3178-89 to analyze coal for carbon content.
Rationale
EPA has previously approved the use of ASTM D5373-93 for analyzing
the carbon content of coal (see Docket A-97-35, Item II-C-16). The
Agency believes this method is of sufficient accuracy for use in the
Acid Rain Program. In addition, EPA historically has accepted
analytical methods from standard-setting organizations such as the
American Society for Testing and Materials (ASTM). The Agency solicits
comment on the use of ASTM D5373-93 for analyzing the carbon content of
coal.
2. Changes to Fuel Sampling Frequency
Background
Section 2.1 of Appendix G (as revised by the May 17, 1995 direct
file rule) specifies that fuel sampling should be done weekly for gas
or oil for each shipment for diesel fuel and at least once per month
for gaseous fuel. The sampling frequencies for diesel fuel and for
gaseous fuel are consistent with the frequency for sampling under
Appendix D to part 75.
Most gas-fired and oil-fired units that perform fuel sampling for
sulfur content under Appendix D also perform fuel sampling for carbon
content. Today's proposed rule would reduce the frequency with which
facilities need to sample oil or gas under Appendix D.
Discussion of Proposed Changes
The fuel sampling frequency specified in section 2.1 of Appendix G
would be made consistent with the proposed requirements for Appendix D
oil and gas sampling. Thus, all oil samples could be taken upon
delivery, either from the delivery vessel itself or from the storage
tank after a delivery is transferred. Gas samples would be taken
monthly (for pipeline natural gas), for each shipment (for gases
delivered in lots), or daily (for fuels that are analyzed daily for
sulfur). Coal samples would continue to be taken weekly.
Rationale
Appendix D of today's proposed rule would reduce the required
sampling frequency of oil and gaseous fuels delivered in lots. Based
upon information provided by one utility, the variability of carbon
content in oil is less than the variability of sulfur content (see
Docket A-97-35, Item II-D-18). Some utilities have stated that they
would prefer the procedures for sulfur and GCV to be similar (see
Docket A-97-35, Item II-D-24). Based upon this statement, the Agency
believes that facilities would also prefer to have consistent fuel
sampling procedures for Appendices D and G. Therefore, the Agency
believes it is appropriate to make the fuel sampling frequency for
carbon analysis under Appendix G consistent with the fuel sampling
frequency for sulfur content under Appendix D. Similarly, section 5.5
of Appendix F would be revised to make the gas sampling frequency
consistent with Appendix D. The Agency solicits comment on the proposed
changes to the fuel sampling frequency.
3. Addition of Missing Data Procedures for Fuel Analytical Data
Background
Appendix D provides procedures for substituting missing fuel
analytical information, either for sulfur or GCV. However, Appendix G
to part 75 does not specify what should be done if carbon content data
are missing.
Some software programmers asked EPA what missing data procedures
should be used for carbon content data (see Docket A-97-35, Item II-E-
5). The Agency responded to this question at a public conference and in
policy guidance (see Docket A-97-35, Items II-E-5, and II-I-9, Policy
Manual, Question 6.3). In its policy guidance, EPA stated that
facilities should ``[f]ill in the most recent carbon content . . .
available for that fuel type (gas, oil or
[[Page 28102]]
coal) of the same grade (for oil) or rank (for coal). If at all
possible, use a carbon content value from the same fuel supply.''
Discussion of Proposed Changes
Today's proposed rule would allow facilities to substitute for
missing carbon content prior to January 1, 2000, using either the most
recent carbon content for that fuel type, grade and rank, or procedures
parallel to those of Appendix D. Beginning January 1, 2000, facilities
would substitute for missing carbon content data using procedures
consistent with Appendix D. For gaseous fuels and for oil sampled
manually, these procedures would provide for a conservative maximum
carbon content value. Specifically, the permissible conservative carbon
content values would be either the maximum carbon content measured in
the previous calendar year or, if this information were not available,
a default value based upon handbook fuel characteristics. For weekly
coal samples or composite oil samples, CO2 mass emissions
would be calculated using the highest carbon content from the previous
four carbon samples available.
Rationale
Software programmers have already indicated that it is useful to
have a procedure for filling in missing carbon content data for
purposes of programming (see Docket A-97-35, Item II-E-5). Some
utilities have stated that they would prefer the missing data
procedures to be similar for both sulfur and GCV, even if both values
are conservative (see Docket A-97-35, Item II-E-24). Therefore, the
Agency believes that facilities would also prefer to have Appendix G
missing data procedures for carbon content that are parallel with those
for sulfur content and GCV in Appendix D. Thus, today's proposal would
allow for missing data for manual oil samples or for gaseous fuel using
the maximum carbon content measured in the previous calendar year or,
if this information were not available, a default value based upon
handbook fuel characteristics.
In determining the conservative default carbon content values that
would be used for missing data substitution in the event that no
previous carbon content samples are available, the Agency consulted
several handbook reference tables on fuel characteristics.
Specifically, the Agency reviewed handbook values for the carbon
content of coal (of various ranks), oil (of various grades), and gas
(of different types). (see Docket A-97-35, Items II-I-18, II-I-19, II-
I-20). In the case of coal, there was a fairly wide range of carbon
content values for different ranks of coal. Therefore, today's rule
would propose separate default carbon content values for Anthracite,
Bituminous, and Subbituminous/Lignite. In contrast, the carbon content
values for different grades of residual oil were fairly consistent. For
this reason, today's rule proposes a single default carbon content
value for all grades of oil. Finally, for gaseous fuels, the handbooks
which were reviewed presented a fairly narrow range of values for
natural gas but a much wider range of values for other types of gaseous
fuels. Therefore, today's rule proposes a value for natural gas and a
separate, conservative value for all other types of gaseous fuels.
The Agency solicits comment on the proposed revisions to the
missing data procedures under Appendix D.
R. Reporting Issues
1. Partial Unit Operating Hours and Emission and Fuel Flow Rates
Background
For affected units that use CEMS to account for emissions under
part 75, hourly emission rates of SO2 (in lb/hr),
NOX (in lb/mmBtu), and CO2 (in tons/hr), and
hourly heat input rates (in mmBtu/hr) are calculated using the
applicable equations in Appendix F. For affected units that use fuel
flow meters and fuel analysis (or default emission rates) rather than
CEMS, the applicable equations in Appendices D, F and G (for certain
gas-fired units) are used to determine the hourly SO2 and
CO2 mass emission rates and heat input rates. For oil and
gas-fired peaking units that use Appendix E to account for
NOX emissions, the hourly NOX emission rates in
lb/mmBtu are derived from a graph of NOX emission rate
versus heat input rate, the hourly heat input rates being derived from
the applicable equation in Appendix F. Under Sec. 75.54(b)(2), unit
operating time is reported by rounding the actual operating time up to
the nearest 15 minutes.
The equations in Appendices D through G assume that each unit
operating hour consists of a full 60 minutes of unit operation (or, for
common stacks, that emissions are discharged through the stack for 60
minutes in each hour); the equations do not attempt to account for
partial unit operating hours. This is a shortcoming in the current
rule, because partial unit operating hours sometimes occur during
periods of unit startup, shutdown, and malfunction. Therefore, to
ensure accurate accounting of SO2 and CO2 mass
emissions and unit heat input, part 75 should address the issue of
partial unit operating hours. Note, that because NOX
emission rates are measured with respect to heat input (lb/mmBtu),
rather than with respect to time (lb/hr), this discussion is not
relevant for NOX emission rate. Many vendors and utilities
have asked EPA for guidance on how to calculate mass emission rates
during partial unit operating hours (see, e.g., Docket A-97-35, Item
II-D-4).
The crux of the partial unit operating hour issue is when to adjust
the emission data for unit operating time, before the reporting of
hourly values or at the quarterly summation. For many units, there are
very few hours of partial operation, and adjusting the data for
operating time merely involves multiplying by 1, a seemingly
inconsequential issue. For other units, such as peaking and cycling
units, which start up and shut down often, the issue of how the data is
reported is relevant because there can be a significant amount of
partial unit operating hours. Definitive and standardized reporting
requirements allow facilities and/or vendors to program their software
such that their calculated result equals the result calculated by EPA.
For SO2 and CO2, the question is whether to
report hourly emissions on a mass basis (i.e., lb or tons) or on a mass
emission rate basis (i.e., lb/hr or tons/hr). For heat input, the
question is whether to report the total hourly heat input (in mmBtu) or
the hourly heat input rate (in mmBtu/hr). For example, suppose that a
unit emits for a full 60 minutes in a particular clock hour at an
SO2 concentration of 602.5 parts per million (ppm), a
CO2 concentration of 10.0 percent, a volumetric flow rate of
4,000,000 standard cubic feet per hour (scfh), and a heat input rate of
300 mmBtu/hr. Suppose further that the same unit operates for only 15
minutes in the next hour and all of the parameters (i.e.,
SO2 and CO2 concentration, flow rate, and heat
input rate) remain unchanged. If unit operating time is disregarded,
the SO2 mass emission rate (calculated from Equation F-1 in
Appendix F) would be the same (400 lb/hr) for both the partial
operating hour and the full unit operating hour. Similarly, the
CO2 mass emission rate would be the same (22.8 tons/hr) and
the heat input rate would be the same (300 mmBtu/hr) for both the full
and partial operating hours. The mass emission rates and heat input
rate for the partial unit operating hour are the same as the full-hour
values because they are based solely upon data recorded during unit
operation, i.e., in
[[Page 28103]]
the first 15 minutes of the hour. The hourly average rates for the
partial hour do not include ``zero'' values for the three 15-minute
periods of unit non-operation during the clock hour (e.g., an
SO2 emission rate of (400 lb/hr + 0 + 0 + 0)/4 = 100 lb/hr
would not be appropriate). If the emission and heat input rates are
adjusted by multiplying them by the operating time, then, for the full
operating hour (i.e., operating time = 1.0), the SO2 and
CO2 mass emissions and heat input would be, respectively,
400 lb SO2, 22.8 tons CO2, and 300 mmBtu. For the
partial hour (operating time = 0.25), the corresponding values would
all be divided by four, i.e., 100 lb SO2, 5.7 tons
CO2, and 75 mmBtu, respectively.
Software vendors and utilities have requested clarification as to
whether hourly SO2 mass emission values should be reported
as totals, in lb, or as rates, in lb/hr. As early as November of 1993,
EPA stated that hourly SO2 mass emission values should be
reported as rates in lb/hr. Then, when determining quarterly cumulative
SO2 mass emissions, each hourly emission rate would be
converted to a mass basis by multiplying it by the unit operating time
(expressed as a fraction of an hour) for the same hour. Similarly,
hourly heat input values would be expressed as rates, in mmBtu/hr, and
hourly CO2 mass emissions would be expressed as rates, in
tons/hr. Parallel issues were also addressed by the Agency's policy,
for units that determine SO2 and CO2 mass
emissions and heat input from fuel flow rates and fuel analyses under
Appendix D to part 75 (see Docket A-97-35, Item II-I-9, Policy Manual,
Questions 14.14, 14.36 and 14.37).
Some utilities have requested that the Agency change its policy and
allow reporting of hourly total SO2 and CO2 mass
emissions and heat input instead of mass emission rates and heat input
rates (see Docket A-97-35, Item II-E-14). The utilities argued that
this would simplify determination of the total year-to-date
SO2 mass emissions, in order to estimate the number of
allowances needed to cover a unit's emissions or to prepare a report on
mass emissions for a state environmental agency, because the reported
values would already be multiplied by the hourly operating time. Thus,
by performing the multiplication by operating time before reporting the
hourly value rather than waiting until calculating the quarterly value,
it might save a calculation step if a facility wanted to use the data
for another purpose. For these reasons, reporting of totals is a
preferred approach for some facilities. However, other utilities that
have incorporated the correct rate approach into their software have
indicated that they would prefer not to have to revise their software
to report in totals.
Partial unit operating hours must also be considered in the
recording and reporting of hourly unit load. The standard missing data
procedures in Sec. 75.33 require historical flow rate data to be placed
in load ``bins'' (ranges) based upon the maximum operating electrical
generation (or steam flow rate) of the unit. However, the recorded
hourly volumetric flow rate value in scfh applies only to the fraction
of the hour in which the unit operates. Therefore, the reported load
for the hour should be based upon the average electrical generation
during the period when the unit operates. Thus, the electrical
generation should be recorded as a rate for the period when the unit
operates, rather than an integrated total for the entire hour. The
units for reporting hourly load should, therefore, be MWe or 1000 lb/hr
of steam, and not MW-hr or 1000 lb of steam.
Discussion of Proposed Changes
In today's rulemaking, EPA is proposing to amend part 75 to clarify
that heat input, fuel flow, SO2 mass emissions, and
CO2 mass emissions are all to be reported on an hourly basis
as rates. Today's proposal also would clarify that the hourly emission
rates are to be based only upon data collected during periods of unit
operation (i.e., for partial unit operating hours, emission rates or
heat input rates of zero that are recorded during periods of non-
operation are not to be included in the hourly average emission rates).
These clarifications are found in proposed Sec. 75.57, and Appendices
D, E and F to part 75. Today's proposed rule would also clarify that
the proper units of reporting for load are MWe and lb/hr of steam.
Today's proposal would also provide new options for reporting unit
operating time. While the current requirement to report operating time
rounded to the nearest 15 minutes would be retained as an option, the
proposal would allow more flexibility by specifying that, for reporting
purposes, unit operating time be rounded up to the nearest fraction of
an hour (in equal increments that can range from one hundredth to one
quarter of an hour, at the option of the owner or operator).
Consistent with the requirement to report hourly SO2 and
CO2 mass emissions and hourly heat input as rates, today's
rulemaking proposes to revise the quarterly summation formulas for
SO2 and CO2 and to add summation formulas for
heat input in Appendix F to part 75. The proposed formulas show that
hourly mass emission rates or heat input rates would be multiplied by
unit operating time before summing to get total mass emissions. Today's
proposal also includes new formulas in Appendix D for summing hourly
SO2 mass emission rates and hourly heat input values from
fuel flowmeter systems in order to determine quarterly and annual total
SO2 mass emissions and total heat input. The Appendix D and
F equations revised or added to address summations include Equations D-
6, D-7, D-8, D-9, F-3, F-12, F-24, and F-25.
In addition, EPA is proposing optional recordkeeping provisions for
determining total heat input, total SO2 mass emissions or
total CO2 mass emissions for the hour. In addition to
reporting the required emission and heat input rates, owners or
operators could choose to report the total hourly heat input and mass
emissions under this option.
Rationale
As stated above, some utilities have expressed a preference for
reporting hourly total values for SO2 and CO2
mass emissions and heat input, rather than rates (see Docket A-97-35,
Item II-E-14). They have stated that this is easier to understand and
that reporting hourly total values, instead of or in addition to rates,
would make it easier to determine the cumulative total mass emissions
at any time during the year.
One representative requested that EPA consider allowing either
method of calculation (i.e., hourly rates or totals), so long as the
annual mass emissions and heat inputs are correctly determined and
reported. EPA notes that, although this approach may appear
advantageous because it would not require some facilities to reprogram
their DAHS software, it would require other facilities to reprogram
their software and it would make it difficult for EPA to verify
emissions calculations from reported hourly data. Because EPA considers
it essential to the Acid Rain Program to be able to recalculate annual
compliance values based upon hourly emission information reported by
facilities, the Agency is not revising the rule to take the
representative's suggestion. EPA considered using the total mass
emissions (or total heat input) approach instead of the mass emission
rate (or heat input rate) approach currently stated in Agency policy
(see Docket A-97-35, Item II-I-9, Policy Manual, Questions 14.14 and
14.36). In fact, as discussed in section III.H. of this preamble, the
Agency is proposing, under subpart H of part 75, model
[[Page 28104]]
reporting requirements for NOX mass emissions that would (if
adopted by an applicable state or federal authority) require hourly
NOX mass emissions to be reported as a total value (in lb)
rather than an hourly mass emission rate (in lb/hr). However, using
hourly mass emission totals for values currently reported to the Agency
would have the distinct disadvantage of requiring both EPA and the
utilities who correctly implemented the mass emission rate approach to
reprogram software to perform the new calculations, whereas retaining
the use of SO2 and CO2 emission and heat input
hourly rates offers several advantages.
First, using hourly mass emission rates and heat input rates
instead of totals is consistent with the units of measure in which flow
rate is recorded. Volumetric flow monitors measure flow rate during a
given time in standard cubic feet per hour scfh, rather than total flow
in standard cubic feet (scf). When SO2 concentration is
multiplied by volumetric flow rate, one calculates a mass emission rate
rather than a total mass of SO2. Similarly, multiplying a
volumetric flow rate by a diluent gas concentration yields a heat input
rate in mmBtu/hr, rather than a total heat input in mmBtu.
Second, the current missing data procedures for volumetric flow
rate, which are based upon the assumption that flow is a rate that is
comparable from one hour to another, rather than a total volumetric
flow that will vary depending upon the unit operating time, would no
longer be appropriate if volumetric flow rate were changed to a total
volumetric flow. Third, for Appendix E gas-fired or oil-fired peaking
units, it is critical that heat input rate, and not total heat input,
be used to determine the NOX emission rate. The Appendix E
correlation curve formulas are based upon heat input rate rather than
total heat input. Appendix E allows a facility to create a correlation
of the NOX emission rate measured in the stack during stack
testing and heat input combusted during that same period of time,
rather than installing CEMS on gas-fired or oil-fired peaking units. If
a facility were mistakenly to use the total heat input from an hour
rather than the heat input rate, it would correlate to the wrong
portion of the NOX to heat input rate correlation curve and
would incorrectly estimate NOX emission rate. For example,
if heat input totals were used to determine NOX emission
rate from the Appendix E curve, the unit would have a different
NOX emission rate if it combusted 25,000 mmBtu in half an
hour than if it combusted 25,000 mmBtu during a full hour. This would
apply both under the current provisions of Appendix E and today's
revised provisions to Appendix E.
In view of the above considerations, today's proposed rule would
affirm that facilities are to report SO2 and CO2
emissions and heat input as rates on an hourly basis. However,
facilities would also be allowed, at their discretion, to report
SO2 and CO2 emissions and heat input as hourly
totals, in addition to reporting them as rates. This approach would not
require reprogramming of computerized reporting software for those
utilities that are following EPA's current policy, and would provide
consistent reporting that allows EPA to recalculate emissions and heat
input values. Those utilities that find recording and reporting of
hourly total SO2 and CO2 mass emissions and heat
input to be desirable would be able to do so. EPA will provide the
necessary electronic record types to support this optional reporting.
Although today's proposed rule would affirm that emissions and heat
input are to be reported as rates, rather than totals, EPA has become
concerned that for partial unit operating hours, some utilities are
incorrectly calculating hourly average flow rates by including flow
rates of zero in the hourly average to represent periods of non-
operation, rather than basing the average flow rate solely on the
minutes of operation of the affected unit during the clock hour. In one
example, it appears that the software is designed to calculate the
average flow rate by including data from all minutes during those
fifteen-minute quadrants of an hour when the unit operates, thus
including some minutes when the unit is not operating, rather than
creating an average flow rate just from merely those minutes when the
unit is operating and emitting (see Docket A-97-35, Item II-C-17). EPA
suspects that still other utilities may be calculating an average
hourly flow rate that includes flow rates of zero for whole quadrants
of an hour when a unit does not operate. This can result in the flow
rate values for partial operating hours being under-reported to EPA and
a lowering of the average flow rates in the load ranges used to provide
substitute flow rate data, both of which can cause underestimation of
SO2 mass emissions.
The Agency is also concerned that this same kind of improper data
averaging may be occurring when hourly gas concentrations are
determined during partial operating hours. EPA would, therefore,
require in today's proposal that facilities base all of their reported
hourly average concentrations, flow rates, emission rates, and heat
input rates solely upon data that are recorded during unit operation
(that is, when the unit is combusting fuel and emitting).
Some utilities have indicated that the approach of averaging in
readings of zero from periods of non-operation has been incorporated to
compensate for having to report operating time rounded up to the
nearest fifteen minutes (Note, this is not an acceptable approach). A
utility representative indicated that reporting operating time to less
precision can cause overestimation of emissions because the operating
time is multiplied by the mass emission rate. Thus, a mass emission
rate of 400 lb/hr measured over a period of 20 minutes, during an hour
when the unit shut down, would be multiplied by an operating time of .5
hr (i.e., 20 minutes rounded up to the nearest fifteen minutes) and
would result in 200 lb of SO2 being reported rather than the
132 lb of SO2 that was actually emitted. The utility
suggested that a solution would be to allow operating time to be
reported to more precision than is currently allowed. Therefore,
today's proposal would allow flexibility for reporting unit operating
time to greater precision. While the current requirement to report
operating time rounded up to the nearest 15 minutes would be retained
as an option, the proposal would allow more flexibility by specifying
that unit operating time be rounded up to the nearest fraction of an
hour (in equal increments that can range from one hundredth to one
quarter of an hour, at the option of the owner or operator). Thus, a
facility could decide whether it had enough partial operating hours
(e.g., unit start-ups and shutdowns) to merit changing their software
to report operating time to more precision.
2. Use of Bias-Adjusted Flow Rates in Heat Input Calculations.
In late 1995, the first year of the Phase I SO2
allowance program, EPA conducted an audit of the Phase I-affected
units. Data from the second quarter of 1995 were retrieved from the
Emission Tracking System (ETS) in order to determine whether the
SO2 emission rates and heat input values were being properly
reported. The results of the audit showed that a number of sources were
not reporting heat input correctly. The problem in most instances was
that the unadjusted flow rate was being used in the heat input
equation, rather than the bias-adjusted value. EPA believes that this
is attributable to the fact that part 75 does not explicitly state that
the bias-adjusted flow rate is to be used in heat input
[[Page 28105]]
calculations. The Agency has attempted to clarify this through policy
guidance (see Docket A-97-35, Item II-I-9, Policy Manual, Question
14.81). To correct the situation, the necessary language would be added
to section 7.6.5 of Appendix A in today's proposed rule.
3. Removing the Restriction on Using the Diluent Cap Only for Start-Up
Background:
Based on the May 17, 1995 direct final rule, sections 3.3.4, 4.1,
4.4.1, 5.1, 5.2.1, 5.2.2, 5.2.3, and 5.2.4 of Appendix F currently
provide for the substitution of a constant CO2 or
O2 value for a measured value from a CO2 or
O2 monitor during unit start-up. This provision was
originally created in response to concerns from some utilities that
their NOX emission rate in lb/mmBtu was being overestimated
during unit start-up (see Docket A-90-51, Item IV-D-220, Letter from
English, Mark G., Deputy General Counsel, Kansas City Power & Light
Company on EPA's Proposed Part 75 regulations; see also Docket A-94-16,
Item II-F-2). During unit start-up or other periods when the unit is at
a low load level, CO2 concentrations are lower than during
normal operation and O2 concentrations are higher than
during normal operation. The NOX emission rate equation,
however, is not designed to be used in these situations because it
assumes complete combustion and normal operating conditions. As a
result, the NOX emission rate equation overestimates the
NOX emission rate when the CO2 concentration is
very low or the O2 concentration is very high, such as
during start-up. The equations for calculating emission rates in lb/
mmBtu use measured CO2 concentration or the difference
between ambient air's O2 concentration and the measured
O2 concentration in the denominator. For example,
NOX emission rate is calculated using a NOX
pollutant concentration monitor and a CO2 diluent monitor
using the following equation:
[GRAPHIC] [TIFF OMITTED] TP21MY98.001
When a small CO2 concentration is entered into this
equation, the calculated NOX emission rate will be very high
and will overestimate the actual emissions.
The idea of capping CO2 or O2 concentration
was implemented in part 75 for determination of NOX emission
rate, CO2 mass emissions, and heat input during unit start-
up. The cap concentration was set at a minimum CO2
concentration of 5.0 percent CO2 and a maximum O2
concentration of 14.0 percent O2, based upon some
information provided by utilities for boilers (see Docket A-94-16, Item
II-D-34).
Some utilities asked EPA to consider extending this cap on diluent
gas concentrations to other situations when a unit is operating at a
low level (see, e.g., Docket A-97-35, Items II-D-20 and 30, and Docket
A-97-35, Items II-E-13 and II-E-14). In addition to unit start-up, this
might include periods of unit shutdown or unit ``banking,'' where a
unit is combusting a very small amount of fuel to keep the boiler warm,
but little or no electricity is generated. During these other
situations where a unit operates at a low level, the CO2
concentration will be very low and the O2 concentration will
be very high, resulting in high calculated NOX emission rate
values like those during unit start-up. One software vendor
specifically mentioned that it would be easiest to implement the
diluent cap if it could be used any time the CO2
concentration would fall below or the O2 concentration would
rise above the cap value (see Docket A-97-35, Item II-E-7). This could
be implemented mathematically in the software, rather than having to
examine the unit operation or the number of hours since the unit
started operating in order to trigger use of the diluent cap.
During the process of implementing the May 17, 1995 direct final
rule, EPA issued guidance that explained that facilities may use the
diluent cap values for calculating NOX emission rate during
unit start-up whenever the CO2 concentration is below 5.0
percent or the O2 concentration is above 14.0 percent, and
also may use the actual measured CO2 or O2
concentration values at all times for calculating CO2 mass
emissions or heat input (see Docket A-97-35, Item II-I-9, Policy
Manual, Question 14.39). In Question 14.39, EPA recommended that even
if the diluent cap is used to calculate NOX emission rate,
the actual diluent measurement should be used for the purpose of
calculating CO2 mass emissions or heat input, because the
purpose of the diluent cap was ``to avoid using an extreme diluent
concentration in the denominator of the equation to calculate emission
rate in lb/mmBtu.'' The formulas for calculating hourly CO2
mass emission rate or hourly heat input rate do not use the
CO2 or O2 concentrations in the denominator of
the equation. Thus, use of the diluent cap would tend to overestimate
both CO2 mass emission rate and hourly heat input.
Discussion of Proposed Changes
Today's proposed rule would allow facilities to use diluent cap
values of 14.0 percent O2 or 5.0 percent CO2 for
boilers and 19.0 percent O2 or 1.0 percent CO2
for turbines. For the purpose of calculating NOX emission
rates in lb/mmBtu, the diluent cap would be allowed to be used for any
hour in which the average measured CO2 concentration is
below the cap value or the average measured O2 concentration
is above the cap value. Diluent cap values would still be allowed to be
used to calculate CO2 mass emissions or heat input, as well
as NOX (or SO2) emission rate in lb/mmBtu.
Rationale
EPA acknowledges that there are periods of low unit operation or
low load in addition to unit start-up where the calculated
NOX emission rate would be overestimated if it were based
upon measured diluent concentrations. Therefore, the Agency believes
that extending use of the diluent cap is appropriate. The Agency
believes that allowing use of the diluent cap anytime when the actual
measured value is above the cap (for O2) or below the cap
(for CO2) is easier to program and to implement than
limiting the use of the diluent cap based upon unit load, another
option that EPA considered. The Agency believes that it is unlikely
that a unit would ever be able to operate at a high load and still have
an O2 or CO2 concentration beyond the diluent cap
value. Therefore, it is not necessary to limit the use of the diluent
cap value based on unit load.
The Agency is also proposing new diluent cap values for turbines.
Turbines tend to operate with much higher levels of excess
O2 than boilers. For example, Method 20 of Appendix A, 40
CFR part 60, the procedure for testing SO2, NOX
and diluent gas from stationary gas turbines subject to the NSPS,
requires testers to correct data to a typical concentration of 15.0
percent O2. Emissions data reported to EPA confirms that for
turbines, hourly concentrations of O2 are typically between
14.0 and 16.0 percent and hourly concentrations of CO2 are
typically between 3.0 and 4.0 percent. Thus, a turbine's diluent gas
concentration is likely to consistently exceed the diluent cap value of
14.0 percent O2 and to be consistently below the cap value
of 5.0 percent CO2 promulgated in the May 17, 1995 direct
final rule. If these values were allowed to be used by turbines at all
times rather than just during unit start-up, a turbine
[[Page 28106]]
could conceivably report its NOX emission rate using only
the diluent cap value and never report the actual monitored diluent
concentrations, thereby consistently underestimating the NOX
emission rate. Therefore, today's proposal provides diluent cap values
of 19.0 percent O2 or 1.0 percent CO2 that are
clearly beyond the typical O2 or CO2
concentrations measured at turbines, while still providing some relief
at extreme diluent concentrations. It is EPA's observation that
turbines with NOX CEMS have not reported emissions using the
diluent cap thus far. Thus, no turbines should need to reprogram
software in order to report the use of the new diluent cap value for
turbines with a new method of determination code.
EPA considered removing the option for facilities to use the
diluent cap for heat input rate and CO2 concentration, as
well as for NOX (and SO2) emission rate in lb/
mmBtu, but is not proposing to do so in today's proposal. As explained
previously, the diluent cap was created in order to calculate more
representative NOX emission rate data during certain unusual
circumstances. However, when a diluent cap value is used to calculate
the hourly CO2 mass emission rate or the heat input rate,
the final calculation would often be less representative of actual
emissions or heat input during those hours. The Agency also found that
allowing some facilities to use the diluent cap only for NOX
emission rate and others to use the diluent cap also for hourly
CO2 mass emission rate and heat input rate makes it
difficult to check emissions and heat input rate data to verify that
calculations are performed correctly. This is because a data
acquisition and handling system could use either the actual reported
diluent gas concentration or the diluent cap value to calculate
NOX emission rate, CO2 mass emission rate, or
heat input rate, but there is currently no provision in the electronic
data reporting format for a facility to indicate which value was used
to calculate the heat input. However, some utilities have indicated
that making a change to discontinue using the diluent cap for
calculations of heat input rate and CO2 mass emission rate
would require a significant change in their software calculations (see
Docket A-97-35, Item II-E-25). Therefore, today's proposed rule would
allow facilities the options of (1) not using the diluent cap at all,
(2) using the diluent cap only for calculating NOX (or
SO2) emission rate in lb/mmBtu, or (3) using the diluent cap
for calculating NOX (or SO2) emission rate in lb/
mmBtu, heat input rate, and CO2 emissions. In addition, EPA
is proposing to add a minor additional reporting requirement to
indicate whether the diluent cap is used in calculating CO2
and heat input in the electronic data reporting format. This would
allow EPA to verify facilities' calculations, while requiring less
reprogramming than changing the calculations for heat input and
CO2 emissions.
The Agency solicits comment on the proposed revisions relating to
the diluent cap.
4. Complex Stacks--General Issues
Background
Many power plants regulated under part 75 have relatively simple
stack and monitoring configurations. Many utilities have one stack for
each affected unit and have CEMS installed on the stack. Other plants
have more than one unit discharging to the atmosphere through a common
stack, with CEMS installed on the common stack. Still others have
individual units that exhaust into multiple stacks and have CEMS
installed on each stack. The monitoring requirements for these various
configurations are addressed in Secs. 75.13, 75.16, 75.17, and 75.18.
EPA has issued guidance to assist utilities in preparing quarterly
reports for these unit and stack configurations (see Docket A-97-35,
Items II-I-4 and II-I-9, Policy Manual, Section 17).
For the configurations described above, the process of accounting
for emissions and heat input from the units and stacks will follow
simple mathematical rules. For example, for single unit-single stack
configurations, the emissions and heat input for the unit are directly
determined from the stack CEMS (or from an excepted methodology, where
applicable). For units discharging through a common stack with CEMS on
the common stack, the combined emissions and heat input are determined
from the CEMS, and the heat input to each individual unit is determined
by apportionment of the combined heat input, using a ratio of the unit
load to the combined load of all units utilizing the common stack. For
a single unit exhausting through multiple stacks, the sum of the
SO2 and CO2 mass emissions and heat input for the
different stacks equals the total SO2 and CO2
mass emissions and heat input for the unit.
However, in implementing part 75, EPA has become aware of a number
of affected units that have stack exhaust configurations which are more
complex than the configurations described above. For example, one
utility has a configuration in which two units can emit through two
different stacks at the same time, combining their emissions in both
stacks (see Docket A-97-35, Items, II-C-1, II-D-12). In this case, the
stack configuration is both a common stack and a multiple stack
configuration. EPA has had significant problems in determining the
emissions and heat input from these units, and in one case, EPA
rejected the quarterly reports for the units (see Docket A-97-35, Item
II-C-8). The utility worked closely with EPA to resolve the reporting
issues resulting from this unusual situation (see Docket A-97-35, Item
II-D-21). Other utilities with similar situations have contacted the
Agency to ensure there would not be problems with their reporting (see,
e.g. Docket A-97-35, Item II-D-5).
There have been other cases in which a unit that is accountable for
holding SO2 allowances shares a common stack with a unit
that does not hold SO2 allowances (e.g., where an affected
unit and a non-affected unit share a common stack or, prior to 1/1/
2000, where a Phase I unit and a Phase II unit share a common stack).
These are termed ``subtractive stack'' situations in the following
discussion. Utilities with subtractive stack situations have generally
used the provisions of Sec. 75.16(a)(2)(ii)(C) or
Sec. 75.16(b)(2)(ii)(B). These provisions allow a facility to monitor
separately the common stack and the unit with no allowance requirement
and to subtract the emissions from the non-affected or Phase II unit
from the common stack emissions. In some cases, it has not been clear
in the electronic quarterly reports whether a utility is reporting
combined emissions from all of the units using the common stack or
whether the emissions from the non-affected unit(s) have already been
subtracted out of the reported emissions (see Docket A-97-35, Item II-
C-18). This confusion in interpreting the quarterly emissions reports
has made compliance determination difficult.
The Agency found that there is a potential problem with the
underestimation of emissions using this subtractive approach. In some
cases, the error in the monitors' measurements might be such that a
larger emissions value is subtracted from a smaller value, resulting in
the reporting of false negative emissions (see Docket A-97-35, Item A-
94-16-IV-D-18, Comments from Monitor Labs). In other cases, there may
be an incentive for making inaccurate measurements with the monitoring
systems installed on a unit with no allowance requirement. For
[[Page 28107]]
example, if the SO2 pollutant concentration monitor on a
unit with no allowance requirement did not operate properly and had a
significant amount of missing data, the facility would calculate
SO2 emissions from the unit using a conservative, high
concentration value. Therefore, emissions reported for the units with
allowance requirements would, as a result of the subtraction, be less
than the actual emissions. Thus, a facility might have a disincentive
for good monitor performance and accuracy, because it could lower the
emissions reported for the units with allowance requirements. Though
allowed under the current wording of Appendix A to part 75 and subpart
D of part 75, this is contrary to the intent of the missing data
substitution procedures, which is to encourage good monitor performance
while preventing any systematic underestimation of emissions. (See
Docket A-97-35, Items II-B-13, II-E-4, and II-I-12.)
Discussion of Proposed Changes
Today's proposed rulemaking would add a general regulatory
requirement to Secs. 75.16 and 75.17 for facilities with complex stack
configurations (i.e., subtractive stack situations or configurations
involving combinations of common stacks and multiple stacks) to receive
approval from EPA's Administrator for a method of calculating and
reporting emissions from the units and stacks in the configuration. The
facility would be required to reach agreement with the Agency on issues
such as: identification of the stack in its quarterly report,
representation of the configuration in its monitoring plan, groups of
units for which cumulative emissions must be reported, testing
procedures, use of the bias test, and use of the missing data
substitution procedures. This would apply both to sources that already
have certified monitoring equipment and are submitting quarterly
reports and to units that do not yet have certified monitoring systems
(e.g. new units).
Rationale
The Agency evaluated two basic approaches to resolving issues in
these complex stack monitoring configurations. First, EPA considered
resolving the issues through policy guidance and through instructions
for submitting quarterly reports. Second, the Agency considered putting
detailed instructions in part 75 for reporting from and testing of
monitoring systems installed in these complex stack configurations.
These rule provisions would have explicitly addressed missing data
substitution to ensure that when emissions are reported, they are not
underestimated from units with an allowance requirement or a
NOX emission limitation. For example, EPA could have
required, for the subtracted unit(s), that the facility only use those
provisions of the standard missing data procedures that are not
intended to be conservative estimates, such as the average
SO2 concentration during the hour before and the hour after
a missing data period. Another approach for missing data substitution
could have been to count zero emissions for the unit with no allowance
requirement during any missing data periods. Or perhaps creation of a
site-specific missing data procedure could have been required (see
Docket A-97-35, Items II-E-4 and II-I-12). To prevent a potential
underestimation of emissions and a disincentive for more accurate
monitoring due to application of a bias adjustment on a monitor on a
unit with no allowance requirement where its emissions are subtracted
from a common stack, EPA could have required that the bias calculation
be based upon both the monitors on the common stack and the monitors on
units with no allowance requirement, resulting in a single bias
adjustment factor for the subtractive stack situation.
However, EPA's experience thus far in implementing the program
indicates that each complex monitoring configuration tends to be
unique. Thus, the Agency has rejected the two approaches discussed
above and has decided instead to make General regulatory revisions that
allow for case-by-case resolution of issues in individual plant
situations, rather than making extensive, detailed revisions to part 75
to address each unique situation.
The Agency prefers to make regulatory revisions rather than
addressing issues solely through policy and guidance. In some cases,
the Agency has given advice to utilities on how to report emissions,
and the utility involved has not followed the Agency guidance (see
Docket A-97-35, Items II-C-7, II-C-24, and II-D-8). In another case,
the current provisions of part 75 for missing data substitution and for
the bias test appeared to be in conflict with guidance that the Agency
wanted to issue in order to ensure that emissions are not
underestimated in a subtractive stack situation (see Docket A-97-35,
Item II-B-13). Therefore, today's proposed rule would require owners or
operators of facilities with complex stack configurations to apply for
approval of their monitoring plans and reporting methodologies from
EPA's Administrator on a case-by-case basis. The Agency believes that
the General regulatory provisions requiring approval of a complex
monitoring situation by EPA's Administrator will give both facilities
and the Agency flexibility to deal with site-specific cases, while also
giving the Agency regulatory authority to resolve any case-specific
problems.
It is possible that any final rule resulting from today's proposal
may not be promulgated until 1999. Thus, EPA is proposing to require
the Administrator's approval of the monitoring plans and reporting
methodologies only for those situations that will exist on and after
January 1, 2000. Any subtractive stack situations that exist only
during the duration of Phase I would not fall under this requirement.
However, complex stack situations that exist where affected and non-
affected units share a common stack would need to meet today's proposed
requirement. Similarly, in situations where coal-fired units sharing a
common stack have different NOX emission limitations under
part 76, or situations where some units sharing a common stack have a
NOX emission limitation under part 76 and others have no
NOX emission limitations under part 76, any complex
monitoring configuration would need to be approved by EPA's
Administrator.
5. Complex Stacks--Heat Input at Common Stacks
Background
For a unit that utilizes a flow monitor to determine SO2
mass emissions, section 5 of Appendix F to part 75 requires heat input
to be calculated using the installed flow monitor and a diluent gas
(O2 or CO2) monitor. The January 11, 1993 final
rule indicated that units with common stacks, multiple stacks, or
bypass stacks should follow the same General procedures for monitoring
heat input as are used for monitoring SO2 under Sec. 75.16.
As written, those procedures allowed facilities to monitor their heat
input either by placing individual monitors on each unit that serves a
common stack or by placing monitors only on the common stack and
measuring a combined heat input from all of the units sharing the
common stack. The May 17, 1995 rule required the combined heat input
measured by monitors on the common stack to be apportioned to the
individual units, in two specific provisions. First, unit level heat
input was required under Sec. 75.16(e)(2) for cases in which a
knowledge of the heat input for each unit is critical to compliance
determination (i.e., for situations where any units using the common
stack have
[[Page 28108]]
a NOX emission limit). Second, Sec. 75.16(e)(3) required
unit level heat input to be determined for all other common stacks, but
only until the year 2000. The November 20, 1996 rule outlined the
acceptable methodology for apportioning heat input, i.e., by using the
ratio of the unit load in MWe or lb of steam per hour to the combined
load of all units utilizing the common stack (provided that all of the
units utilizing the common stack are combusting fuel with the same F-
factor).
Discussion of Proposed Changes
Today's proposed rule would revise the existing requirements found
in Sec. 75.54(b) and two specific provisions of Sec. 75.16(e) for
accounting of heat input for units serving a common stack, a by-pass
stack, or multiple stacks. First, EPA would require determination and
reporting of the unit level heat input to be continued after the year
2000 for all affected units, rather than restricting it to certain
situations after 2000. Second, EPA would clarify that the proper units
of measure for load to be used in an apportionment of common stack heat
input to determine unit level heat input are totals of MWe-hr and 1000
lb of steam, rather than rates of MWe and 1000 lb/hr of steam.
Rationale
EPA considered leaving the current provisions of Sec. 75.16(e) and
Sec. 75.54(b) from the May 17, 1995 and November 20, 1996 rules
unchanged. However, this would have the serious drawback of requiring
the facilities to reprogram their computer software for certain units
and not for others. Corresponding monitoring plan changes would also be
required. Additionally, EPA would have to reprogram its emission
tracking software to accommodate two different heat input reporting
methodologies for common stacks. In view of these considerations, EPA
is proposing to continue to receive individual heat input data from all
affected units. This information is useful for developing inventories
of total NOX mass emissions in tons in support of other
Agency rulemakings. Without such information, the inventories would be
based on assumptions about how units operate, rather than being based
on unit level heat input as reported from the facility.
The Agency believes that a relatively small number of sources would
be affected by this proposed change. This is because (1) most coal-
fired units would still need to report unit level heat input under the
current provisions of Sec. 75.16(e)(2), even after the year 2000; and
(2) gas-fired and oil-fired units using fuel flowmeters to determine
heat input and to implement the procedures of Appendix D or Appendix E
would still be required to monitor heat input for each unit under
section 2.1 of Appendix D. Because of the usefulness of having heat
input data for individual units, because of the burden of reprogramming
software to remove the heat input apportionment by the year 2000, and
because of the small number of sources that would benefit from
retaining the current provisions of Sec. 75.16(e)(3), EPA believes it
is reasonable to require all units that measure combined heat input at
a common stack to continue to apportion heat input to the individual
units. The Agency solicits comment on the number of sources that would
be affected by this revision.
6. Start-Up Reporting--Units Shutdown Over the Compliance Deadline
Background
As currently written, part 75 requires that units which are
shutdown over an applicable compliance date specified in Sec. 75.4 must
submit a notice of the planned and (if different) actual shutdown date.
In addition, Sec. 75.4(d) provides an extended certification deadline
for such units of ``the earlier of 45 unit operating days or 180
calendar days after the date that the unit recommences commercial
operation of the affected unit.'' If an owner or operator subsequently
recommences commercial operation of the unit, a notice related to the
planned and (if different) actual date of recommencement of commercial
operation is required. In addition to these notices, Sec. 75.64
requires that after the applicable compliance date passes, the owner or
operator must submit quarterly reports for such units. If the unit
remains shut down and does not operate during the quarter, the
quarterly report must show zero emissions. Utility commenters (see,
e.g., Docket A-97-35, Items II-D-20, II-D-30) have recommended that
this quarterly report requirement for shutdown units be deleted because
it is unnecessary and burdensome.
Discussion of Proposed Changes
Section 75.64(a) would be modified so that quarterly reporting is
not required until the first quarter in which a previously shutdown
unit recommences commercial operation. In this case, the first
quarterly report would contain data beginning with the hour in which
the unit recommences commercial operation.
Rationale
Units that are shutdown over their applicable certification
deadlines are required to submit notice, pursuant to Sec. 75.61(a)(3),
of the planned date of recommencement of commercial operation and also
must submit a follow-up notice if the actual date of recommencement of
commercial operation is different from the planned date. As a result of
these notice provisions, EPA will know whenever the status of a
shutdown unit changes. Because shutdown units have no emissions, the
Agency believes that quarterly reporting in addition to the notice
provisions is unnecessary to fulfill the emission reporting objectives
of the Act.
The Agency notes, however, that the proposed revision differs from
that suggested by certain utilities (see Docket A-97-35, Item II-D-30).
The utilities proposed tying the reporting requirement to the
certification deadline in Sec. 75.4(d). However, under Sec. 75.4(d),
facilities are required to report emissions data using special
provisions in that section prior to the extended certification deadline
in Sec. 75.4(d). Thus, the proposed revisions would tie the obligation
for quarterly reporting to the quarter in which commercial operation is
recommenced.
7. Start-Up Reporting--New Units
Background
As currently written, Sec. 75.64(a) requires the first quarterly
report for new units to be submitted for the quarter corresponding to
the compliance date in Sec. 75.4. However, the current provision is
unclear about which hourly emissions data need to be included in the
first quarterly report if the compliance deadline does not correspond
to the first hour in the quarter.
Discussion of Proposed Changes
Section 75.64(a) would be modified to clarify that a new unit must
start reporting data beginning with the earlier of the date and time of
provisional certification or the compliance deadline in Sec. 75.4(b).
Rationale
These proposed revisions are generally consistent with existing
implementation of the new unit reporting requirements, and primarily
would serve to clarify ambiguous elements of the current rule.
[[Page 28109]]
8. Recordkeeping and Reporting Provisions
Background
Subpart F and subpart G of the existing part 75 regulation set
forth the recordkeeping and reporting requirements that accompany the
monitoring provisions of part 75. Specifically, in subpart F,
Sec. 75.53 contains the monitoring plan requirements, Sec. 75.54
contains the general recordkeeping provisions, Sec. 75.55 lists the
general recordkeeping provisions for specific situations, and
Sec. 75.56 consists of the certification, quality assurance and quality
control record provisions. In subpart G, Sec. 75.62 lists the
monitoring plan reporting provisions, Sec. 75.62 contains the reporting
requirements for initial certification and recertification
applications, and Sec. 75.64 discusses the provisions for quarterly
reports. Quarterly reports are electronic data files containing
emissions and operating data from affected units, as well as monitoring
plan information and the results of certification and quality assurance
tests. Under Sec. 75.64, these electronic data reports are required to
be submitted to the Agency each calendar quarter. This electronic
information is used by the Agency for many different purposes,
including implementation of the SO2 allowance trading
program, determination of compliance with emission limits, development
of reports on utility emissions, and modeling of air quality to assess
the effectiveness of the Act.
In order to effectively use the electronic quarterly report
information, EPA created a standardized reporting format, the
electronic data reporting (EDR) format. The electronic file formats and
record structures of the EDR provide the vehicle by which required
information is submitted to the Agency every calendar quarter. The EDR
primarily defines the order, length, and placement of information
within the electronic report or file. The individual tables of the EDR
define the record type, type code, start column, data element
description, units, range, length, and FORTRAN format for each data
element in the electronic report. The information in the EDR fields
mirrors the required information set forth in subparts F and G of part
75. Considering both the volume of information contained in each
quarterly report (e.g, operating and emissions data for each of the
hours in the quarter) and the number of reports submitted to the Agency
(i.e., currently, 1765 reports are received each quarter for the 2055
affected units; some reports contain information for more than one unit
if several units are interrelated, as in a common stack configuration),
a standard format is critical in order for the Agency to review,
verify, and use the information reported. A standard format allows the
Agency to develop software to receive and verify the files and to
correlate and separate out specific information for compliance
determinations. A standard format also allows software vendors to
create standard software which can be utilized by many affected units.
This is more cost effective than developing site-specific software and
thus reduces the software cost to industry.
Today's rulemaking proposes a number of revisions to subparts F and
G of part 75 (the reporting and recordkeeping sections of the rule).
The majority of these changes are necessary to implement the proposed
substantive revisions to the sections of the rule and appendices
discussed elsewhere in this notice. In addition, EPA is
proposingrevisions to these subparts in order to streamline
implementation of the program and to coordinate reporting under the
Acid Rain Program with other programs.
To support the changes to the recordkeeping provisions, new
Secs. 75.57, 75.58, and 75.59 would be added. These sections would
replace existing Secs. 75.54, 75.55, and 75.56. The addition of new
sections is necessary because the proposed revisions would not be
mandatory until January 1, 2000, and to have the proposed revisions
listed throughout existing effective sections could lead to confusion.
However, an owner or operator would be free to follow the provisions of
Secs. 75.57, 75.58, and 75.59 before January 1, 2000, if he chooses to
do so. In addition, the owner or operator would be required to satisfy,
prior to January 1, 2000, the elements in these sections that support a
regulatory option proposed in other sections of part 75 if the owner or
operator elects to implement that option prior to January 1, 2000.
Because, as discussed above, the Acid Rain Program relies on a
standardized electronic data reporting format, EPA has also developed
draft revisions to the EDR formats and instructions (draft EDR version
2.1). The following discussion refers to both the rule sections and EDR
record types (RTs) that would be affected by the proposed revisions.
Discussion of Proposed Changes
There are a number of proposed rule changes to the recordkeeping
and reporting requirements of part 75 and corresponding draft EDR
revisions that would be necessary to implement the substantive
revisions proposed by EPA and discussed elsewhere in this preamble.
These include the following requirements:
(1) Changes to support new CO2 missing data requirements
(see Sec. 75.57 and RT 202, 210, and 211);
(2) Changes to support new reporting, QA and missing data
requirements for moisture monitoring (see Secs. 75.53, 75.57, and
75.59, and RT 211, 212, 220, and 618);
(3) Changes to support optional Appendix I (flow methodology for
gas and oil units) (see Secs. 75.57 and 75.58, and RT 220, 302, 303,
608, and 609);
(4) Changes to support more flexibility for units that have
multiple range analyzers (see Secs. 75.53 and 75.59, and RT 230, 530,
600, 601, and 602);
(5) Changes to support the use of the diluent cap during all hours
(see Sec. 75.57 and RT 300 and 330);
(6) Changes to support test exemptions and extensions for units
that operate infrequently (see Secs. 75.59 and 75.64, and RT 301, 697,
and 698);
(7) Changes to support increased flexibility in fuel sampling (see
Sec. 75.58 and RT 302, 303, 313, and 314);
(8) Changes to allow reporting of hourly total values in addition
to hourly rates (see Sec. 75.57 and RT 300, 310, and 330);
(9) Changes to support the proposed re-definition of unit operating
loads (see Secs. 75.53 and 75.59, and RT 535 and 611);
(10) Changes to support reporting of conditional data during
recertification events (see Sec. 75.59, and RT 556);
(11) Changes to support a new quarterly flow-to-load QA check for
flow monitors (see Sec. 75.59, and RT 605 and 606);
(12) Changes to allow QA test grace periods (see Sec. 75.59, and RT
699);
(13) Changes to support simplified reporting for low mass emissions
units (see Secs. 75.53, 75.58, and 75.63, and RT 360, 508, and 531);
(14) Changes to support fuel flow-to-load QA checks for fuel flow
meters (see Sec. 75.59, and RT 628 and 629); and
(15) Changes to support expanded reporting of RATA supporting
information (see Sec. 75.59, and RT 614, 615, 616, 617, and 618).
In addition, since the EDR version 1.3 was released, EPA has
developed additional record types to aid in the implementation of the
program, by allowing the designated representative to certify the
validity of quarterly reports using an electronic certification
statement. The proposed revisions would adopt the necessary rule
language to implement these miscellaneous record types (see Sec. 75.64,
and RT 900, 901, 910, and 920).
[[Page 28110]]
The proposed revisions would also set forth optional requirements
for reporting of NOX mass emissions that states or EPA could
adopt as part of a NOX mass trading program, such as the OTC
NOX Budget Program. In this situation both a rule change and
an EDR change would be needed (see Secs. 75.57 and 75.64 and RT 301,
307, and 328).
The proposed rule revisions also include a number of changes that
EPA believes will facilitate implementation of the program. These
include:
(1) Reporting of test numbers, reasons for tests and indicators of
aborted tests (see Sec. 75.59, and RT 560, 600, 601, 602, 603, 610, and
611);
(2) Changing the deadlines for reporting the RATA supporting
information that was originally required on January 1, 1998 (see
Sec. 75.59, and RT 614, 615, 616, 617, and 618);
(3) Reporting of an optional record type that will allow facilities
to provide contact person information that many facilities currently
provide in quarterly report cover letters (see Sec. 75.59, and RT 999);
(4) Based on comments received, the rule would be revised so that
reporting the reasons for missing data as part of the quarterly report
would become optional, but would still need to be maintained on-site
(see Secs. 75.56 and 75.59, and RT 550);
(5) Reporting of facility location, identification, and EDR version
numbers to support the transition from EDR 1.3 to EDR 2.1 (see
Sec. 75.64, and RT 100 and 102);
(6) Reporting of information documenting the calculation of heat
input (see Sec. 75.57, and RT 300);
(7) Reporting of reference method backup QA data (see
Sec. 75.59(a)(11), and RTs 260, 261, and 262);
(8) Expanded reporting of unit definition information (see
Secs. 75.53, and RTs 504, 585, 586, and 587);
(9) Reporting of Appendix E segment ID information (see Sec. 75.58,
and RT 323, 324, and 560);
(10) Reporting of qualification data for peaking units or gas-fired
units (see Sec. 75.53, and RT 507);
(11) Reporting of the qualifying test for off-line calibrations
(see Sec. 75.59, and RT 623);
(12) Reporting of Appendix E emission rate test data (see
Secs. 75.59, and RT 650-653);
(13) Reporting of span effective date information and flow rate
span values (see Sec. 75.53, and RT 530); and
(14) Removal of the recordkeeping provisions of Secs. 75.50, 75.51,
and 75.52 that are no longer effective.
Rationale
The majority of the proposed changes to subparts F and G are needed
to support proposed substantive changes elsewhere in part 75. EPA is
also proposing certain minor revisions to the order and wording of
provisions in these subparts so that the records required by the rule
match up consistently with the record type descriptions in the EDR.
Certain utility groups previously had objected that EPA had not made
the EDR format available for formal public notice and comment. The
Agency maintains that it is not required to provide notice and comment
for the EDR. The data included in (or proposed to be included in) the
EDR are also listed in the rule (or the proposed rule revisions) as
requirements under the recordkeeping and/or reporting provisions of
Secs. 75.53 through 75.64, which have already undergone (or are
undergoing) public notice and comment. Since the EDR simply shows how
to present electronically the data whose submission is (or will be)
required by the rule, it is the rule, not the EDR, that imposes the
data requirements. Notice and comment on the contents of the EDR would
therefore be unnecessary and duplicative. Moreover, the requirement to
present the rule's data requirements in a specified format is
authorized by Sec. 75.64(d), which requires a quarterly report to be
submitted in the format specified by the Administrator. Like the data
requirements, this format requirement in part 75 was adopted after
public notice and comment.
In today's rulemaking, EPA has developed draft EDR revisions
simultaneously with the proposed rule revisions and is therefore
including the draft EDR revisions in the docket for comment at the same
time as the proposed rule revisions (see Docket A-97-35, Item II-A-12).
EPA is also posting the draft EDR v2.1 revisions and draft EDR v2.1
reporting instructions on the Acid Rain Homepage (www.epa.gov/
acidrain). However, the Agency maintains that notice and comment are
not necessary for revisions to the EDR so long as the data included in
the EDR is the same as the data required by rule provisions that have
undergone or are undergoing notice and comment. Thus, future EDR
revisions may be made without prior notice and comment on the EDR in
order to implement rule revisions for which notice and opportunity for
comment are provided. However, the Agency will continue its informal
procedures for involving the affected stakeholders in any such EDR
revisions.
There are a number of other proposed changes to Secs. 75.54-75.64
that have been included to implement existing provisions in other
sections of part 75. First, information on test numbers and reasons for
tests would be required so that quality-assurance test data can be more
easily correlated and interpreted. Second, the reporting of various
run-specific and point-specific RATA support information would be
required (e.g., point velocity head readings, gas reference method
quality-assurance data, moisture reference method data, etc.). The
Agency believes that most testing companies currently either collect
these data electronically or enter the data into computer programs
manually to determine RATA results. By requiring the reporting of these
data elements in a standard electronic format, the Agency believes that
both facilities and regulatory personnel would be able to more easily
interpret data that are currently provided by test contractors in many
different hardcopy formats.
The Agency is proposing not to require the electronic reporting of
RATA support information prior to the year 2000. Sections 75.56
(a)(5)(iii)(F) and (a)(7) and Sec. 75.64(a)(1) of part 75 currently
require RATA supporting information to be reported in the electronic
quarterly report. EPA believes, however, that it would be more cost
effective to require the more detailed RATA support records to be
electronically reported beginning in the year 2000, rather than having
a two-stage implementation. The Agency has notified all designated
representatives that this RATA supporting information will not be
required to be reported electronically, in RT612 and 613 of the
quarterly report, prior to January 1, 2000.
The Agency notes that certain data elements (e.g., yaw angle, pitch
angle, axial velocity, wall effect point identifier, etc.) have been
included in anticipation of future revisions to EPA Reference Method 2.
EPA is presently evaluating a number of alternative flow rate
measurement methodologies, such as the use of a 3-dimensional probe.
Depending on the outcome of the Agency's evaluation, one or more of
these alternative flow measurement techniques may be allowed beginning
in the year 2000. Therefore, EPA believes it is appropriate to include
data elements to support these anticipated Method 2 revisions in draft
EDR version 2.1.
Finally, by changing the requirements for reporting the results of
the most recent RATA from requiring it to be reported in the quarter in
which it was
[[Page 28111]]
performed, to requiring it to be reported in the quarter in which it
was performed and each subsequent quarter in which a BAF that was
calculated using the results of that RATA are used, EPA would make the
individual quarterly reports more self contained and make it easier for
people who are using the reported data to understand how the BAFs
reported in those reports were applied. EPA considered adding a field
to the hourly emissions data record for each pollutant to indicate the
BAF applied in that hour. However, the Agency received requests from
utilities on an early draft of the EDR revisions that the hourly
emissions data record types not be revised to add a field for BAF. The
Agency believes that reporting the results of the most recent RATA,
including the BAF, in each quarterly report would accommodate the
utilities' requests not to add the BAF to each hourly record type and
would achieve the objective of making the quarterly reports easier to
interpret because the BAF being applied will be found in each quarterly
report. In addition, since electronic RATA results involve a relatively
small amount of information that can be copied into subsequent reports
and does not have to be recreated, it should not be a significant
burden to reporting facilities.
The proposed revisions would also remove the requirement to report
the reasons for missing data and make it optional. However, even if the
information is not reported, the reasons for missing data would have to
be maintained on site in a manner suitable for inspection. Based on the
high data availability achieved during initial implementation of the
program, the Agency believes that this type of information is not
needed in the review of most quarterly reports. For those situations in
which the Agency may wish to review this information, the records would
still be on-site for audit purposes or for submittal to the Agency.
The EPA is also proposing to incorporate additions which would
allow the reporting of electronic signatures and certification
statements so that no hardcopy reporting of any kind (e.g., cover
letters) would be necessary to meet the quarterly report requirements.
Finally, the removal of recordkeeping Secs. 75.50, 75.51, and 75.52
(and the corresponding explanatory text included in Appendix J to the
existing rule) is necessary because those sections were scheduled for
replacement during the May 17, 1995 rule revisions. At that time,
Secs. 75.54, 75.55, and 75.56 were added as replacements for
Secs. 75.50, 75.51, and 75.52, effective January 1, 1996. Because the
effective date is now past, the old sections and Appendix J will be
removed and reserved in order to prevent any confusion.
9. Electronic Transfer of Quarterly Reports
Background
Sections 75.64(a) and (d) of the original January 11, 1993 Acid
Rain rule requires emissions, monitoring, and quality assurance data to
be electronically reported to the Administrator on a quarterly basis in
a format to be specified by the Administrator. Version 1.3 of the
Electronic Data Reporting (EDR) format (see Docket A-97-35, Item II-I-
5) further specifies the record structures to be used to report the
required data elements. Page 3-3 of the May 1995 Acid Rain Program CEMS
Submission Instructions (see Docket A-97-35, Item II-I-4) further
specifies the mode of transmission of the electronic data file to the
Agency. Three modes of transfer are listed as options: (a) by mail on
diskette, (b) by mail on magnetic tape, or (c) through direct
electronic transfer.
Since the beginning of the program, the Agency has received
quarterly reports by mail on diskette and through direct electronic
transfer. To date, the magnetic tape option has never been utilized.
Based on the first four years of implementation of part 75, the Agency
believes that the use of the direct electronic transfer mode of
transmission has many advantages to the Agency and to the affected
sources. In fact, more than seventy percent of the reports for sources
currently affected by part 75 were submitted directly to the EPA
mainframe with EPA-provided software in second quarter 1997, and the
number of sources using this option has steadily increased over time
(see Docket A-97-35, Item II-I-8).
Discussion of Proposed Changes
Today's proposal would require quarterly reports to be submitted
via direct electronic transfer unless otherwise approved by the
Administrator. This would remove the option of sending files through
the mail on interceding media except for hardship cases where a modem
is not available or where technical difficulties prevent the successful
transmission of files via modem.
An additional revision to section 4 of Appendix A to part 75 would
require data acquisition and handling systems (DAHS) to be capable of
transmitting a record of measurements and other required information by
direct computer-to-computer electronic transfer via modem and EPA-
provided software.
Rationale
For each quarterly report submitted, the Agency performs an
assessment which results in a feedback report for the submitting
designated representative. This feedback report provides information to
the facility that may be used in making trading decisions, that may
indicate that a change is needed to the facility software, and/or that
may indicate that the file needs to be corrected and resubmitted. A
major advantage of submission through direct electronic transfer with a
modem and EPA-provided software is that the designated representative
submitting the file receives the EPA assessment of the submitted data
much more quickly than for a file that is transmitted through the mail
on diskette. Currently, for a file that is submitted to the Agency by
electronic transfer via modem and EPA-provided software, the EPA
assessment is received by the designated representative, via modem and
EPA-provided software, immediately (typically within ten minutes) after
the transmission of the quarterly report file. However, for files
submitted on diskette that must travel through the mail system and be
processed by Agency personnel, a letter containing the EPA assessment
is currently sent to the designated representative through the mail and
arrives 45 days or later from when the submission was originally
received by the Agency. Therefore, with direct electronic transfer,
potential errors get corrected and resolved more quickly and trading
decisions can be made with assurance that submitted data meets the
minimum quality standards acceptable to the Agency. Additionally, the
source may electronically submit the quarterly report, via modem and
EPA software, prior to the deadline, immediately receive the EPA
assessment, fix any errors, and resubmit the file by the deadline. Many
utilities have indicated that this is an important advantage over
submission of the quarterly report by diskette.
Another benefit of direct electronic transfer is the reduced risk
of error in transmission to the Agency or handling at the Agency.
Throughout the implementation of the program, many files submitted on
diskette through the mail have been lost, returned to the sender,
damaged in transit, or contained viruses (see Docket A-97-35, Item II-
I-8). When a file is submitted using direct electronic transfer of a
quarterly report, the designated representative submitting the file(s)
receives an immediate
[[Page 28112]]
confirmation that the file was received by the Agency.
Further, immediate feedback from the agency on quarterly report
submissions may also contribute to cost savings for facilities if a
file submitted via direct electronic transfer is rejected and required
to be amended and resubmitted. Utilities have indicated that submitting
the report to EPA, receiving feedback, and making the necessary
corrections to the file in a single work session significantly reduces
the cost of reworks, particularly for facilities that retain their
master file at the individual plant locations.
An additional advantage to direct electronic transfer is the
reduced cost to the Agency resulting from the minimized EPA labor hours
required to process a diskette. For instance, a diskette transmitted
through the mail must be catalogued, scanned for readability and
viruses, uploaded to the EPA mainframe Emissions Tracking System, and
renamed. On the other hand, transmission of a file by direct computer-
to-computer electronic transfer using EPA software eliminates all of
those manual steps because they are performed automatically by the EPA
software used for transmission of the report.
A possible concern about a requirement to submit the quarterly
report via modem is the possibility that source may not be equipped
with a modem and electronic transfer capability. Although the Agency
believes that most sources currently have a modem or will have a modem
by the year 2000, the Agency understands that a very small percentage
might not. Therefore, the Agency would accept petitions from sources
unable to transmit files via modem in order to allow transmission via
diskette for hardship cases.
Additionally, a utility group representative raised a concern about
the possibility of a computer at either the facility source or at the
EPA being inoperative at the time of the deadline for transmission,
preventing a source from successfully transferring the quarterly report
to the Agency. In order to minimize the risk of this type of problem,
there is a wide window, currently thirty days, during which EPA will
accept quarterly report transmissions each quarter. Additionally, EPA
has instituted preventative measures to minimize the possibility that
the EPA computer would be inoperative for an extended length of time,
preventing quarterly report transmission. Nevertheless, the Agency
accepts that it is conceivable that a technical difficulty could
prevent the successful electronic submission of a quarterly report and,
therefore, would also approve diskette submission on an as-needed basis
for sources unable to transfer a file via modem and EPA-provided
software due to technical difficulties. Furthermore, EPA solicits
comment on whether it should allow a grace period for late submissions
due to a technical difficulty with the EPA computer.
Finally, section 4 of Appendix A to part 75 would be amended to
require the DAHS to be capable of transmitting the required information
by direct electronic transfer via modem and EPA-provided software, for
consistency with the proposed Sec. 75.64(f). In addition, section 4 of
Appendix A to part 75 would retain the requirement for the DAHS to be
capable of transmitting a record of measurements and other required
information via an IBM-compatible personal computer diskette so that an
on-site inspector could collect electronic data on a diskette for
review.
S. Revised Traceability Protocol for Calibration Gases
Background
Currently, Appendix H to part 75 requires affected units to follow
a 1987 version of EPA Protocol procedures for developing calibration
gases. This protocol document has been superseded by a later version,
the ``EPA Traceability Protocol for Assay and Certification of Gaseous
Calibration Standards,'' September 1997, EPA 600/R-97/121. The 1997
document is actually five protocols. Two of these protocols (formerly
known as Protocols 1 and 2) have been combined to allow both CEMS and
ambient air analyzers to be calibrated from gases produced either
without dilution (Procedure G1) or with dilution (Procedure G2). The
remaining three protocols (Procedures P1, P2, and P3) describe
procedures that are mandatory for ambient air quality analyzers (not
continuous emission monitoring systems).
The 1997 Protocol document, described above, is required by other
parts of the CFR, such as the NSPS provisions in part 60. Because the
old and new protocols specify different certification periods (i.e.,
useful shelf lives) for most calibration gases, some affected units
that must comply with both part 60 and part 75 have been forced to
replace calibration gas cylinders more frequently because of the
shorter certification period in the 1987 Protocol procedures required
by part 75.
Under the 1987 Protocol document, affected units with low
SO2 emission rates occasionally had difficulty finding
calibration gases that were within the concentration ranges required by
Appendix A to part 75. The 1997 Protocol document allows calibration
gases to be developed over a wider range of concentrations than was
previously allowed.
Under the current part 75 rule, ``Protocol 1 gases must be vendor-
certified to be within 2.0 percent of the concentration specified on
the cylinder label (tag value).'' However, no method is specified to
determine the uncertainty value. The overall uncertainty in the
concentration estimated for a calibration gas comes from many different
sources, including uncertainty in the reference standards, uncertainty
in the analyzer multi-point calibration, uncertainty in the zero/span
correction factors, and measurement imprecision.
Discussion of Proposed Changes and Rationale
Today's rule proposes to remove Appendix H and revise parts 72 and
75 to be consistent with the 1997 Protocol document. The following
sections of part 75 would be revised: Secs. 72.2 and 72.3; sections
5.1.1 through 5.1.6, 6.2, and 6.3.1 of Appendix A; and all of Appendix
H.
The final rule would incorporate by reference the 1997 Protocol
document. This is the preferred option for the following reasons: (a)
calibration gas certification periods would be identical under parts 60
and 75, thereby allowing affected units to reduce expenditures on
calibration gas without sacrificing accuracy or performance; (b) lower
emitting affected units would more easily be able to comply with the
required range of calibration gas concentrations; (c) improved assaying
procedures and accuracy determinations would be allowed; and (d) a
wider selection of calibration gases would be allowed.
While today's proposal would retain the requirement for EPA
protocol gases to be within 2.0 percent of the tag value, section 5.1.3
in Appendix A would be revised to specify the use of the uncertainty
calculation procedure in section 2.1.8 of the 1997 Protocol document
for estimating the analytical uncertainty associated with the assay of
the calibration gas. This uncertainty estimate includes the uncertainty
of the reference standard and any gas manufacturer's intermediate
standard (GMIS) and interference correction equation that may be used
in developing the calibration gas.
EPA proposes to change the term ``Protocol 1 gas'' to ``EPA
protocol gas'' because the 1997 Protocol document combines the Protocol
1 and Protocol 2
[[Page 28113]]
procedures; therefore, the term ``Protocol 1 gas'' would no longer be
used.
Today's proposal would also continue to allow a ``research gas
mixture'' to be used as a calibration gas. However, an RGM would need
to meet the same 2.0 percent uncertainty requirement that a protocol
gas would meet.
The proposed rule would explicitly allow GMISs to be used as
calibration gas for two reasons. First, an EPA protocol gas may be made
from a GMIS. Therefore, GMISs are at least as accurate as EPA protocol
gases. Second, GMISs are more readily available and less expensive than
standard reference material or National Institute of Standards and
Technology (NIST) traceable reference material, both of which are
allowable as calibration gas under part 75.
Today's proposal clarifies that NIST/EPA-approved certified
reference materials (CRMs) would be acceptable as calibration gas by
adding those CRMs to the definition of ``calibration gas'' in
Sec. 72.2.
The 1997 Protocol document accepts primary reference standards from
the Netherlands Measurement Institute as being equivalent to standard
reference materials from the NIST. As a result, today's proposal adds
``standard reference material-equivalent compressed gas primary
reference material'' to the ``calibration gas'' definition in Sec. 72.2
and to section 5.1.2 of Appendix A.
Finally, the definition of ``zero air material'' would be revised
to accommodate other acceptable procedures.
Major differences between the 1987 Protocol procedures and the 1997
Protocol procedures are explained on pages 1-1 through 1-3 of the 1993
Protocol document and on pages 1-1 through 1-2 of the 1997 Protocol
document (see Docket A-97-35, Items II-I-23 and 24).
T. Appendix I--New Optional Stack Flow Monitoring Methodology
Background
Section 412 of the Act requires that units subject to title IV
install SO2 concentration monitors and volumetric flow
monitors for the purpose of determining SO2 emissions. The
purpose of the volumetric flow requirement is to enable a unit to
convert SO2 concentrations into mass emission rates of
pounds per hour (lbs/hr). Volumetric flow is also used to determine
heat input rate in mmBtu/hr and CO2 mass emission rate in
ton/hr.
In December 1991, 56 FR 63002 (December 3, 1991), EPA proposed an
exception to the requirement to install SO2 concentration
monitors and volumetric flow monitors at oil- and gas-fired units in
Appendix D to part 75. The exception relies on fuel flowmeters and fuel
sampling and analysis to determine SO2 emissions from oil-
and gas-fired units. In comments on the December 1991 proposed rule,
some industry commenters also advocated allowing oil- and gas-fired
units to use a diluent monitor, an F-factor, and a fuel flowmeter as an
alternative to a volumetric flow monitor. An F-factor is a fuel-
specific constant that relates the heat content of a fuel and the
volume of gases given off upon combustion. It is used to convert
pollutant concentrations into units of pounds of pollutant per million
British thermal units of heat input (lb/mmBtu). EPA already allows the
use of F-factors in emissions monitoring under part 75 and under 40 CFR
part 60, subparts Da and Db. Method 19 of Appendix A to part 60 uses F-
factors as the reference methods for calculating SO2 and
NOX emissions in terms of lb/mmBtu for subpart Da and Db
units. F-factors also are used in the performance tests for certain
pollutants required under Sec. 60.8 to determine if a source is in
compliance with a particular emission standard in lb/mmBtu. Part 75
also uses F-factors in conjunction with diluent gas and volumetric flow
data to determine heat input under section 5 of Appendix F to part 75.
Table 19-1 of Method 19 in Appendix A to part 60 and Table 1 in section
3.3.5 of Appendix F to part 75 list the appropriate F-factors for
different types of fuel, including oil and natural gas.
Although the commenters supported the two exceptions included in
Appendix D, some commenters did not believe the exceptions would be
economical at all oil- and gas-fired units. According to one commenter,
fuel sampling protocols have an inherently high bias because they
assume a 100 percent conversion of fuel sulfur into SO2,
which results in higher emissions reporting from fuel sampling
protocols than from CEMS. The commenter claimed that the high bias
appears to be in the range of 5 to 10 percent. According to the
commenter, the higher emissions reporting ``penalty'' that is inherent
in fuel sampling protocols would justify installing SO2 CEMS
at some oil- and gas-fired units, particularly large, base-loaded oil-
fired units. In addition, the commenter claimed that, for oil- and gas-
fired units which install SO2 CEMS, use of the ``F-factor/
fuel flow method''--which includes use of an F-factor, a fuel
flowmeter, fuel sampling data, and a diluent (CO2 or O2)
concentration monitor--would provide much more accurate and precise
information than volumetric flow monitors (see Docket A-90-51, Item IV-
D-184).
In a four-day experiment performed in 1991 by one commenter,
measurements from the F-factor/fuel flow method were compared to those
generated by a combined SO2 CEMS and a volumetric flow
monitor. However, EPA did not believe that four consecutive days of
data were sufficient to support a conclusive equivalency determination.
Instead, in the January 11, 1993 final rule (58 FR 3590, 3643), EPA
reserved Appendix I to part 75 for the F-factor/fuel flow method and
stated that, to be approved, the method would have to meet the criteria
for alternative methods as required by section 412 of the Act and the
provisions of Sec. 75.40 in a 30-day (720 hour) trial.
Section 412 of the Act requires that an alternative monitoring
system provide information with ``the same precision, reliability,
accessibility, and timeliness as that provided by CEMS . . .'' 42
U.S.C. 7651k. To be approved, the alternative monitoring system must
meet the criteria for alternative methods in a 720 hour trial as
required by the provisions of subpart E of part 75. The rule designates
a certified CEMS or a reference method according to Appendix A to part
60 as the reference for evaluating the alternative monitoring system's
performance.
In order to meet the precision and reliability criteria, an
alternative monitoring system must achieve performance specifications
and quality assurance requirements equivalent to those for CEMS. In
addition, to demonstrate precision, an alternative monitoring system
must pass three statistical tests evaluating the flow CEMS and
alternative method in terms of their respective systematic error,
random error, and correlation. Additionally, to meet the reliability
criterion, the alternative monitoring system is required to match a
certified CEMS in terms of annual availability. Finally, to meet the
accessibility and timeliness criteria, an alternative monitoring system
must match the CEMS' ability to record requisite emissions data on an
hourly basis and report results within 24 hours.
In 1995, Long Island Lighting Company (LILCO) sponsored an
``alternative flow monitor demonstration project'' to demonstrate the
equivalency of fuel flow measurements and F-factor calculations to
stack instrument flue gas measurements for the determination of
volumetric flow. The project was
[[Page 28114]]
performed by Entropy at LILCO's Port Jefferson Unit 4, a 180 MW oil-
fired unit that burns residual oil with a maximum sulfur content of one
percent. The components of the alternative method consisted of a fuel
flowmeter and a CO2 CEMS. The alternative F-factor/fuel flow
method was compared to a flue gas volumetric flow CEMS.
Testing of the F-factor/fuel flow method took place in April-May
1995, and 739 hours of data were collected over a wide range of
operating loads (40 MW--190 MW). Fuel oil samples were taken daily and
analyzed for density and carbon content. The alternative method
successfully passed statistical tests but showed statistically
significant bias (see Docket A-97-35, Item II-D-14). Due to the bias
uncovered during the test, EPA concluded that the alternative flow
monitor demonstration project did not meet the requirements of subpart
E of part 75 for an alternative monitoring system. However, EPA is
proposing that a default multiplier, derived from the demonstration
data, be incorporated into the equations used under Appendix I to
compensate for the detected systematic bias and thereby help to ensure
that emissions are not underestimated when using the F-factor/fuel flow
method. With these provisions, EPA proposes to include the F-factor/
fuel flow method as an excepted method for determining flow in Appendix
I to part 75. The proposed default multiplier, 1.12, is based on the
data and results of the LILCO demonstration and is supported by EPA and
the Class of `85 Regulatory Response Group. The default multiplier
would be incorporated into the equations used under Appendix I whenever
a relative accuracy test audit is performed on a component-by-component
basis as was proposed in the LILCO demonstration.
Discussion of Proposed Changes
EPA proposes to include the F-factor/fuel flow method in Appendix I
as an excepted method for use in place of a volumetric flow monitor for
oil- and gas-fired units that burn only natural gas and/or fuel oil.
The F-factor/fuel flow method uses fuel flow measurement, fuel sampling
data, CO2 (or O2) CEMS data and F-factors to
determine the flow rate of the stack gas. EPA proposes limiting use of
the F-factor/fuel flow method to oil- and gas-fired units that burn
only natural gas and/or fuel oil because of the greater fuel
consistency of oil and natural gas and because the fuel flow rates of
oil and natural gas can be monitored accurately with a fuel flowmeter,
unlike the feed rate of coal.
Appendix I flow monitoring would be done using any of the following
combinations of components: a CO2 monitor and a volumetric
oil flowmeter, a CO2 monitor and a mass oil flowmeter, a
CO2 monitor and a volumetric gas flowmeter, an O2
monitor and a volumetric oil flowmeter, an O2 monitor and a
mass oil flowmeter, or an O2 monitor and a volumetric gas
flowmeter.
Today's proposal would amend Sec. 75.20, ``Certification and
Recertification Procedures,'' to add certification and recertification
procedures for units using Appendix I flow monitoring systems. Initial
certification of the components of the F-factor/fuel flow method would
be performed either component by component or on a system basis. If
each component is tested separately, then the fuel flowmeter would be
tested in accordance with section 2.1.5 of Appendix D, and the
CO2 or O2 monitor would have to pass a 7-day
calibration test, a linearity check, a cycle time test and a relative
accuracy test audit (RATA) using Method 3A from Appendix A to part 60.
A bias test would also have to be conducted. If the excepted Appendix I
flow monitoring system is tested as an entire system, then the
following tests would be performed: a 7-day calibration error test, a
linearity check, and a cycle time test on the CO2 or
O2 monitor, and a relative accuracy test audit on the entire
excepted flow monitoring system using Method 2 from Appendix A to part
60, and a bias test. The owner or operator would also test the data
acquisition and handling system. Upon successful completion of all
certification tests, the Appendix I system would be considered
provisionally certified.
Today's proposal would amend Sec. 75.21, ``Quality Assurance and
Quality Control Requirements,'' to include Appendix I flow monitoring
systems. A unit utilizing the optional F-factor/fuel flow method would
have to meet ongoing quality assurance testing requirements. First, the
daily and quarterly assessment requirements for a CO2 or
O2 monitor in sections 2.1 and 2.2 of Appendix B would have
to be followed. Second, one of the following would have to be met,
depending on whether the owner or operator chooses to test the method
on a component-by-component basis or on a system level: (1) the fuel
flow meter quality assurance requirements and a separate RATA on the
CO2 (or O2) monitor; or (2) a system level flow
RATA. If the components are tested separately, the applicable
procedures in section 2.1.6 of Appendix D would have to be followed for
the fuel flowmeter quality assurance (i.e., a flow meter accuracy test,
a transmitter accuracy test and primary element inspection, and/or the
supplemental quarterly fuel flow-to-load quality assurance testing) and
the applicable RATA procedures in sections 6.5 through 6.5.2.2 of
Appendix A for the CO2 (or O2) monitor would be
followed. In addition, the bias test would have to be performed on the
CO2 (or O2) monitor and, if the bias test is
failed, a bias adjustment factor (BAF) would have to be calculated and
applied to hourly data.
If the entire system is tested, the applicable procedures in
sections 6.5 through 6.5.2.2 of Appendix A would have to be used to
meet the performance specifications for flow relative accuracy in
section 3.3.4 of Appendix A. The bias test would have to be performed
on the volumetric flow data and, if the bias test is failed, a BAF
would have to be calculated using the procedures in section 7.6 of
Appendix A.
Several other sections of the rule would be modified or added in
order to incorporate the new excepted method described in Appendix I,
including Secs. 75.30, 75.57, 75.58, and 75.59. Section 75.30,
``General Provisions'' (for missing data substitution procedures),
would be modified by adding quality assured data from a certified
excepted flow monitoring system under Appendix I to the list of
monitoring systems that measure flow rate data, for which the missing
data substitution procedures of subpart D are required. If fuel
sampling data, fuel flow rate data, and diluent gas data are missing,
then the data acquisition and handling system would have to substitute
for missing volumetric flow data. In addition, Sec. 75.57, would
include additional information that Appendix I flow monitoring systems
must record. This includes fuel flow rate data and data from component
monitors. Section 75.58(g) would be added to address specific
volumetric flow rate record provisions for units using the optional
protocol in Appendix I. Section 75.59, ``Certification, Quality
Assurance and Quality Control Record Provisions,'' would also include
certification and quality assurance information that facilities must
record for Appendix I flow monitoring system tests.
Finally, the new proposed Appendix I would describe the
applicability, procedures, calculations, missing data, and
recordkeeping and reporting requirements for units using Appendix I to
determine flow.
The Appendix I formulas are more complex if an O2
monitor is used. EPA proposes to allow the use of an O2
monitor for Appendix I; however, the
[[Page 28115]]
initial programming of the formulas and monitoring plan development may
take longer for Appendix I flow monitoring systems that use an
O2 monitor.
Volumetric stack flow rate during oil combustion would be
calculated from (1) a bias adjustment factor from the applicable bias
test results; (2) the fuel flow rate (in gal/hr); (3) the fuel density
(in lb/gal); (4) the percent carbon by weight; (5) the CO2
(or O2) concentration percent by volume; and (6) the
appropriate conversion factor. The carbon content of the fuel would
have to be determined according to the procedures in section 2.1 of
Appendix G and the density of the oil would have to be determined
according to the procedures in section 2.2 of Appendix D.
Rationale: EPA is proposing an F-factor/fuel flow method in
Appendix I to part 75 as an excepted method to measure volumetric flow
directly with a flow monitor because this method would allow fuel flow
measurement with a gas or oil flowmeter, fuel sampling data,
CO2 (or O2) CEMS data, and F-factors to determine
the flow rate of the stack gas rather than a volumetric flow monitor.
The F-factor/fuel flow method would be available for use by oil-fired
and gas-fired units, as defined under Sec. 72.2, provided that they
only burn natural gas and/or fuel oil. For these units, EPA believes
that the proposed method would provide acceptably accurate measurements
of volumetric flow, while affording cost savings that some industry
representatives estimate could be substantial. The Agency solicits
comment on the proposed Appendix I and associated changes to part 75.
Appendix I may offer cost savings to some oil and gas fired units.
Representatives from oil- and gas-fired units have estimated that the
costs of operating, maintaining and testing volumetric flow monitors
range from approximately $15,000 to $25,000 per year. In contrast,
using the F-factor/fuel flow method is estimated to result in costs of
only approximately $5,000 to $7,000 per year due to elimination of the
operating, maintenance, testing and fuel costs associated with the
volumetric flow monitor.
U. The Use of Predictive Emissions Modeling Systems (PEMS)
A number of parties have submitted preliminary field test data
designed to demonstrate that EPA should set forth specific requirements
for alternative monitoring methodologies that predict NOX
emission rates at gas-fired units. These ``predictive emissions
modeling systems'' (PEMS) use mathematical models to predict
NOX emission rates based on sensor readings of key operating
parameters. The agency is evaluating the submitted data and will
consider taking further action under a future rulemaking if additional
study demonstrates the equivalency of PEMS to CEMS for well defined
classes of units.
IV. Administrative Requirements
A. Public Hearing
If requested as specified in the DATES section of this preamble, a
public hearing will be held to discuss the proposed regulations.
Persons wishing to make oral presentations at the public hearing should
contact EPA at the address given in the ADDRESSES section of this
preamble. If necessary, oral presentations will be limited to 15
minutes each. Any member of the public may file a written statement
with EPA before, during, or within 30 days of the hearing. Written
statements should be addressed to the Air Docket address given in the
ADDRESSES section of this preamble.
A verbatim transcript of the public hearing, if held, and all
written statements will be available for public inspection and copying
during normal working hours at EPA's Air Docket in Washington, DC (see
the ADDRESSES section of this preamble).
B. Public Docket
The Docket for this regulatory action is A-97-35. The docket is an
organized and complete file of all the information submitted to or
otherwise considered by EPA in the development of this proposed
rulemaking. The principal purposes of the docket are: (1) to allow
interested parties a means to identify and locate documents so that
they can effectively participate in the rulemaking process, and (2) to
serve as the record in case of judicial review. The docket is available
for public inspection at EPA's Air Docket, which is listed under the
ADDRESSES section of this preamble.
C. Executive Order 12866
Under Executive Order 12866 (58 FR 51735, October 4, 1993), the
Administrator must determine whether the regulatory action is
``significant'' and therefore subject to Office of Management and
Budget (OMB) review and the requirements of the Executive Order. The
Order defines ``significant regulatory action'' as one that is likely
to result in a rule that may:
(1) Have an annual effect on the economy of $100 million or more
or adversely affect in a material way the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, local or tribal governments or
communities;
(2) Create a serious inconsistency or otherwise interfere with
an action taken or planned by another agency;
(3) Materially alter the budgetary impact of entitlements,
grants, user fees, or loan programs or the rights and obligations of
recipients thereof; or
(4) Raise novel legal or policy issues arising out of legal
mandates, the President's priorities, or the principles set forth in
the Executive Order.
This proposed rule is not expected to have an annual effect on the
economy of $100 million or more. However, pursuant to the terms of
Executive Order 12866, it has been determined that this proposed rule
is a significant action because it raises novel policy issues. As such,
the proposed rule has been submitted for OMB review. Any written
comments from OMB and any EPA response to OMB comments are in the
public docket for this proposal.
D. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), P.L.
104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures to State, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million or more in any
one year. Before promulgating an EPA rule for which a written statement
is needed, section 205 of the UMRA generally requires EPA to identify
and consider a reasonable number of regulatory alternatives and adopt
the least costly, most cost-effective, or least burdensome alternative
that achieves the objectives of the rule. The provisions of section 205
do not apply when they are inconsistent with applicable law. Moreover,
section 205 allows EPA to adopt an alternative other than the least
costly, most cost-effective, or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted. Before EPA establishes any regulatory
requirements that may significantly or uniquely affect small
governments, including tribal governments, it must have developed under
section 203 of the UMRA a small government agency plan. The plan must
provide for notifying potentially affected small governments, enabling
officials of affected small governments
[[Page 28116]]
to have meaningful and timely input in the development of EPA
regulatory proposals with significant Federal intergovernmental
mandates, and informing, educating, and advising small governments on
compliance with the regulatory requirements.
This proposed rule is not expected to result in expenditures of
more than $100 million in any one year and, as such, is not subject to
section 202 of the UMRA. Although the proposed rule is not expected to
significantly or uniquely affect small governments, the Agency has
notified all potentially affected small governments that own or operate
units potentially affected by the proposal in order to assure that they
have the opportunity to have meaningful and timely input on the
proposed rule. EPA will continue to use its outreach efforts related to
part 75 implementation, including a policy manual that is generally
updated on a quarterly basis, to inform, educate, and advise all
potentially impacted small governments about compliance with part 75.
E. Paperwork Reduction Act
The information collection requirements in this proposal have been
submitted for approval to the OMB under the Paperwork Reduction Act, 44
U.S.C. 3501, et seq. An Information Collection Request (ICR) document
has been prepared by EPA (ICR No. 1835.01), and a copy may be obtained
from Sandy Farmer, OPPE Regulatory Information Division; U.S.
Environmental Protection Agency (2137); 401 M Street, SW, Washington,
DC 20460, by calling (202) 260-2740, or via the Internet at www.gov/
icr.
Currently, all affected utilities are required to keep records and
submit electronic quarterly reports under the provisions of part 75.
The proposed rule includes several new options for compliance with part
75 which have been requested by affected utilities. To implement these
options, EPA would have to modify the existing recordkeeping and
reporting requirements. In some circumstances, these changes would
result in significant reductions in the reporting and recordkeeping
burdens or costs for some units (such as low mass emissions units).
However, these changes would require modifications to the software used
to generate electronic reports. In addition, there would be some
increased burden or costs for certain units to fulfill the new quality
assurance procedures proposed in these proposed revisions. Finally,
several other technical revisions to the existing reporting and
recordkeeping requirements have been proposed to clarify existing
provisions or to facilitate reporting for other regulatory programs in
the context of Acid Rain Program reporting. Although these one-time
software changes would tend to increase the short-term burdens
allocated to the Acid Rain Program, such changes should reduce a
source's overall long-term burden by streamlining the source's
reporting obligations under both the Acid Rain Program and the Act.
The average annual projected hour burden is 2,608,836, which is
based on an estimated 835 likely respondents (on a per utility basis).
The projected cost burden resulting from the collection of information
is $47,555,000, which includes a total projected capital and start-up
cost of $1,436,000 (for monitoring equipment/software), and a total
projected operation and maintenance cost (which includes purchase of
testing contractor services and total projected fuel sampling and
analysis cost of $716,000) of $46,119,000. Burden means the total time,
effort, or financial resources expended by persons to generate,
maintain, retain, disclose, or provide information to or for a Federal
agency. This includes the time needed to review instructions; develop,
acquire, install, and utilize technology and systems for purposes of
collecting, validating, and verifying information, processing and
maintaining information, and disclosing and providing information;
adjust the existing ways to comply with any previously applicable
instructions and requirements; train personnel to be able to respond to
a collection of information; search data sources; complete and review
the collection of information; and transmit or otherwise disclose the
information.
An agency may not conduct or sponsor and a person is not required
to respond to a collection of information, unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations are listed in 40 CFR part 9 and 48 CFR chapter 15.
Comments are requested on the Agency's need for this information,
the accuracy of the provided burden estimates, and any suggested
methods for minimizing respondent burden, including through the use of
automated collection techniques. Send comments on the ICR to the
Director, OPPE Regulatory Information Division; U.S. Environmental
Protection Agency (2137); 401 M Street, SW, Washington, DC 20460; and
to the Office of Information and Regulatory Affairs, Office of
Management and Budget, 725 17th Street, NW, Washington, DC 20503,
marked ``Attention: Desk Officer for EPA.'' Include the ICR number in
any correspondence. Since OMB is required to make a decision concerning
the ICR between 30 and 60 days after May 21, 1998, a comment to OMB is
best assured of having its full effect if OMB receives it by June 22,
1998. The final rule will respond to any OMB or public comments on the
information collection requirements contained in this proposal.
F. Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA), 5 U.S.C. 601, et seq.,
generally requires an agency to conduct a regulatory flexibility
analysis of any rule subject to notice and comment rulemaking
requirements unless the agency certifies that the rule will not have a
significant economic impact on a substantial number of small entities.
Small entities include small businesses, small not-for-profit
enterprises, and governmental jurisdictions. This proposed rule would
not have a significant impact on a substantial number of small
entities.
Today's proposed revisions to part 75 result in a net cost
reduction to utilities affected by the Acid Rain Program, including
small entities. Most importantly, the proposed changes to Appendix D
and the addition of an optional calculation procedure instead of actual
monitoring for oil- and gas-fired units with low mass emissions would
significantly reduce the cost of complying with part 75 for oil-and
gas-fired units, many of which are owned or operated by small entities.
Therefore, I certify this action will not have a significant economic
impact on a substantial number of small entities.
G. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (``ANTTAA''), Pub L. No. 104-113 15 USC 272 note, directs
EPA to use voluntary consensus standards in its regulatory activities
unless to do so would be inconsistent with applicable law or otherwise
impractical. Voluntary consensus standards are technical standards
(e.g., materials specifications, test methods, sampling procedures,
business practices, etc.) that are developed or adopted by voluntary
consensus standards bodies. The NTTAA requires EPA to provide Congress,
through OMB, explanations when the Agency decides not to use available
and applicable voluntary consensus standards.
This regulatory action proposes to incorporate by reference
voluntary consensus standards pursuant to Sec. 12(d) of the NTTAA. The
EPA has adopted the general policy of using voluntary
[[Page 28117]]
consensus standards from technically knowledgeable groups such as the
Organization for International Standards (ISO), the American Society
for Testing and Materials (ASTM), the American Society of Mechanical
Engineers (ASME), the American Gas Association (AGA), the Gas
Processors Association (GPA), and the American Petroleum Institute
(API).
EPA invites public comment on the voluntary consensus standards
which are proposed to be incorporated by reference for use in part 75.
EPA has not identified any additional voluntary consensus standards
which might be applicable to this rulemaking. This does not indicate
that other applicable standards do not exist or that any other
standards should not be allowed. Therefore, EPA also invites public
comment on any other voluntary consensus standards which may be
appropriate for the proposed regulatory action. Further, if additional
applicable voluntary consensus standards are identified in the future,
the designated representative may petition under Sec. 75.66(c) to use
an alternative to any standard incorporated by reference and prescribed
in this part.
EPA proposes to incorporate by reference the following voluntary
consensus standards for use under part 75:
a. ASTM D5373-93 ``Standard Methods for Instrumental Determination
of Carbon, Hydrogen and Nitrogen in laboratory samples of Coal and
Coke.'' This standard is proposed to be incorporated by reference for
use under section 2.1 of Appendix G to part 75 and is discussed further
in section III.Q.1 of this preamble.
b. API Section 2 ``Conventional Pipe Provers'' from Chapter 4 of
the Manual of Petroleum Measurement Standards, October 1988 edition.
This standard is proposed to be incorporated by reference for use under
paragraph (g)(1)(i) of Sec. 75.20 and under section 2.1.5.1 of Appendix
D to part 75. The proposal to incorporate this standard by reference is
discussed further in section III.P.6.(b) of this preamble.
List of Subjects in 40 CFR Parts 72 and 75
Air pollution control, Carbon dioxide, Continuous emission
monitors, Electric utilities, Environmental protection, Nitrogen
oxides, Reporting and recordkeeping requirements, Sulfur dioxide.
Dated: April 27, 1998.
Carol M. Browner,
Administrator, U.S. Environmental Protection Agency.
For the reasons set out in the preamble, title 40 chapter 1 of the
Code of Federal Regulations is proposed to be amended as follows:
PART 72--PERMITS REGULATION
1. The authority for part 72 continues to read as follows:
Authority: 42 U.S.C. 7601 and 7651, et seq.
2. Section 72.2 is amended by revising the definitions of
``calibration gas,'' ``excepted monitoring system,'' ``gas-fired,''
``pipeline natural gas,'' ``span,'' ``stationary gas turbine,'' and
``zero air material''; by revising paragraph (2) of ``oil-fired'' and
paragraph (2) of the ``peaking unit''; by adding paragraph (3) to the
definition of ``peaking unit''; by adding new definitions for
``conditionally valid data,'' ``EPA protocol gas,'' ``gas
manufacturer's intermediate standard,'' ``low mass emissions unit,''
``maximum rated hourly heat input,'' ``ozone season,'' ``probationary
calibration error test,'' ``research gas mixture (RGM)'', and
``standard reference material-equivalent compressed gas primary
reference material''; and by removing the definition of ``protocol 1
gas,'' to read as follows:
Sec. 72.2 Definitions.
* * * * *
Calibration gas means:
(1) A standard reference material;
(2) A standard reference material-equivalent compressed gas primary
reference material;
(3) A NIST traceable reference material;
(4) NIST/EPA-approved certified reference materials;
(5) A gas manufacturer's intermediate standard;
(6) An EPA protocol gas;
(7) Zero air material; or
(8) A research gas mixture.
* * * * *
Conditionally valid data means data from a continuous monitoring
system that are not quality assured, but which may become quality
assured if certain conditions are met. Examples of data that may
qualify as conditionally valid are: data recorded by an uncertified
monitoring system prior to its initial certification; or data recorded
by a certified monitoring system following a significant change to the
system that may affect its ability to accurately measure and record
emissions. A monitoring system must pass a probationary calibration
error test, in accordance with section 2.1.1 of appendix B of part 75
of this chapter, to initiate the conditionally valid data status. In
order for conditionally valid emission data to become quality assured,
one or more quality assurance tests or diagnostic tests must be passed
within a specified time period.
* * * * *
EPA protocol gas means a calibration gas mixture prepared and
analyzed according to section 2 of the ``EPA Traceability Protocol for
Assay and Certification of Gaseous Calibration Standards,'' September
1997, EPA-600/R-97/121 or such revised procedure as approved by the
Administrator.
* * * * *
Excepted monitoring system means a monitoring system that follows
the procedures and requirements of Sec. 75.19 of this chapter or of
appendix D or E to part 75 for approved exceptions to the use of
continuous emission monitoring systems.
* * * * *
Gas-fired means:
(1) For all purposes under the Acid Rain Program, except for part
75 of this chapter, the combustion of:
(i) Natural gas or other gaseous fuel (including coal-derived
gaseous fuel), for at least 90.0 percent of the unit's average annual
heat input during the previous three calendar years and for at least
85.0 percent of the annual heat input in each of those calendar years;
and
(ii) Any fuel, except coal or solid or liquid coal-derived fuel for
the remaining heat input, if any.
(2) For purposes of part 75 of this chapter, the combustion of:
(i) Natural gas or other gaseous fuel with a total sulfur content
no greater than the total sulfur content of natural gas (including
coal-derived gaseous fuel) for at least 90.0 percent of the unit's
average annual heat input during the previous calendar years and for at
least 85.0 percent of the annual heat input in each of those calendar
years; and
(ii) Fuel oil, for the remaining heat input, if any.
(3) For purposes of part 75 of this chapter, a unit may initially
qualify as gas-fired if the designated representative demonstrates to
the satisfaction of the Administrator that the requirements of
paragraph (2) of this definition are met, or will in the future be met,
through one of the following submissions:
(i) For a unit for which a monitoring plan has not been submitted
under Sec. 75.62 of this chapter,
(A) The designated representative submits fuel usage data for the
unit for
[[Page 28118]]
the three calendar years immediately preceding the date of initial
submission of the monitoring plan for the unit under Sec. 75.62; or
(B) For a unit that does not have fuel usage data for one or more
of the three calendar years immediately preceding the date of initial
submission of the monitoring plan for the unit under Sec. 75.62, if the
designated representative submits: the unit's designated fuel usage;
all available fuel usage data (including the percentage of the unit's
heat input derived from the combustion of gaseous fuels), beginning
with the date on which the unit commenced commercial operation; and the
unit's projected fuel usage.
(ii) For a unit for which a monitoring plan has already been
submitted under Sec. 75.62, that has not qualified as gas-fired under
paragraph (3)(i) of this definition, and whose fuel usage changes, the
designated representative submits either:
(A) Three calendar years of data following the change in the unit's
fuel usage, showing that no less than 90.0 percent of the unit's
average annual heat input during the previous three calendar years, and
no less than 85.0 percent of the unit's annual heat input during any
one of the previous three calendar years is from the combustion of
gaseous fuels with a total sulfur content no greater than the total
sulfur content of natural gas and the remaining heat input is from the
combustion of fuel oil; or
(B) A minimum of 720 hours of unit operating data following the
change in the unit's fuel usage, showing that no less than 90.0 percent
of the unit's heat input is from the combustion of gaseous fuels with a
total sulfur content no greater than the total sulfur content of
natural gas and the remaining heat input is from the combustion of fuel
oil, and a statement that this changed pattern of fuel usage is
considered permanent and is projected to continue for the foreseeable
future.
(iii) If a unit qualifies as gas-fired under paragraph (2)(i) or
(ii) of this definition, the unit is classified as gas-fired as of the
date of the submission under such paragraph.
(4) For purposes of part 75 of this chapter, a unit that initially
qualifies as gas-fired must meet the criteria in paragraph (2) of this
definition each year in order to continue to qualify as gas-fired. If
such a unit fails to meet such criteria for a given year, the unit no
longer qualifies as gas-fired starting January 1 of the year after the
first year for which the criteria are not met. If a unit failing to
meet the criteria in paragraph (2) of this definition initially
qualified as a gas-fired unit under paragraph (3)(ii) of this
definition, the unit may qualify as a gas-fired unit for a subsequent
year only under paragraph (3)(i) of this definition.
* * * * *
Gas manufacturer's intermediate standard (GMIS) means a compressed
gas calibration standard that has been assayed and certified by direct
comparison to a standard reference material (SRM), an SRM-equivalent
PRM, a NIST/EPA-approved certified reference material (CRM), or a NIST
traceable reference material (NTRM), in accordance with section 2.1.2.1
of the ``EPA Traceability Protocol for Assay and Certification of
Gaseous Calibration Standards,'' September 1997, EPA-600/R-97/121.
* * * * *
Low mass emissions unit means a gas-fired or oil-fired unit that
burns only natural gas and/or fuel oil and that qualifies under
Secs. 75.19(a) and (b) of this chapter.
* * * * *
Maximum rated hourly heat input means a unit-specific maximum
hourly heat input (mmBtu) which is the higher of the manufacturer's
maximum rated hourly heat input or the highest observed hourly heat
input.
Oil-fired means:
* * * * *
(2) For purposes of part 75 of this chapter, a unit may qualify as
oil-fired if the unit burns only fuel oil and gaseous fuels with a
total sulfur content no greater than the total sulfur content of
natural gas and if the unit does not meet the definition of gas-fired.
* * * * *
Ozone season means the period of time from May 1st to September
30th, inclusive.
* * * * *
Peaking unit means:
* * * * *
(2) For purposes of part 75 of this chapter, a unit may initially
qualify as a peaking unit if the designated representative demonstrates
to the satisfaction of the Administrator that the requirements of
paragraph (1) of this definition are met, or will in the future be met,
through one of the following submissions:
(i) For a unit for which a monitoring plan has not been submitted
under Sec. 75.62,
(A) The designated representative submits capacity factor data for
the unit for the three calendar years immediately preceding the date of
initial submission of the monitoring plan for the unit under
Sec. 75.62; or
(B) For a unit that does not have capacity factor data for one or
more of the three calendar years immediately preceding the date of
initial submission of the monitoring plan for the unit under
Sec. 75.62, the designated representative submits: all available
capacity factor data, beginning with the date on which the unit
commenced commercial operation; and projected capacity factor.
(ii) For a unit for which a monitoring plan has already been
submitted under Sec. 75.62, that has not qualified as a peaking unit
under paragraph (2)(i) of this definition, and where capacity factor
changes, the designated representative submits either:
(A) Three calendar years of data following the change in the unit's
capacity factor showing an average capacity factor of no more than 10.0
percent during the three previous calendar years and a capacity factor
of no more than 20.0 percent in each of those calendar years; or
(B) One calendar year of data following the change in the unit's
capacity factor showing a capacity factor of no more than 10.0 percent
and a statement that this changed pattern of operation resulting in a
capacity factor less than 10.0 percent is considered permanent and is
projected to continue for the foreseeable future.
(3) For purposes of part 75 of this chapter, a unit that initially
qualifies as a peaking unit must meet the criteria in paragraph (1) of
this definition each year in order to continue to qualify as a peaking
unit. If such a unit fails to meet such criteria for a given year, the
unit no longer qualifies as a peaking unit starting January 1 of the
year after the year for which the criteria are not met. If a unit
failing to meet the criteria in paragraph (1) of this definition
initially qualified as a gas-fired unit under paragraph (2)(ii) of this
definition, the unit may qualify as a peaking unit for a subsequent
year only under paragraph (2)(i) of this definition.
* * * * *
Pipeline natural gas means natural gas that is provided by a
supplier through a pipeline and that contains 0.3 grains or less of
hydrogen sulfide per 100 standard cubic feet. The hydrogen sulfide
content of the natural gas must be documented 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
[[Page 28119]]
0.3 grains or less of hydrogen sulfide per 100 standard cubic feet.
* * * * *
Probationary calibration error test means an on-line calibration
error test performed in accordance with section 2.1.1 of appendix B of
part 75 of this chapter that is used to initiate a conditionally valid
data period.
* * * * *
Research gas mixture (RGM) means a calibration gas mixture
developed by agreement of a requestor and NIST that NIST analyzes and
certifies as ``NIST traceable.'' RGMs may have concentrations different
from those of standard reference materials.
* * * * *
Span means the highest pollutant or diluent concentration or flow
rate that a monitor component is required to be capable of measuring
under part 75 of this chapter.
* * * * *
Standard reference material-equivalent compressed gas primary
reference material (SRM-equivalent PRM) means those gas mixtures listed
in a declaration of equivalence in accordance with section 2.1.2 of the
``EPA Traceability Protocol for Assay and Certification of Gaseous
Calibration Standards,'' September 1997, EPA-600/R-97/121.
* * * * *
Stationary gas turbine means a turbine that is not self-propelled
and that combusts natural gas, other gaseous fuel with a total sulfur
content no greater than the total sulfur content of natural gas, or
fuel oil in order to heat inlet combustion air and thereby turn a
turbine, in addition to or instead of producing steam or heating water.
* * * * *
Zero air material means either:
(1) A calibration gas certified by the gas vendor not to contain
concentrations of SO2, NOX, or total hydrocarbons
above 0.1 parts per million (ppm), a concentration of CO above 1 ppm, a
concentration of CO2 above 400 ppm; or
(2) Ambient air conditioned and purified by a CEMS for which the
CEMS manufacturer or vendor certifies that the particular CEMS model
produces conditioned gas that does not contain concentrations of
SO2, NOX, or total hydrocarbons above 0.1 ppm, a
concentration of CO above 1 ppm, or a concentration of CO2
above 400 ppm; or
(3) For dilution-type CEMS, conditioned and purified ambient air
provided by a conditioning system concurrently supplying dilution air
to the CEMS; or
(4) A multicomponent mixture certified by the supplier of the
mixture that the concentration of the component being zeroed is less
than or equal to the applicable concentration specified in paragraph
(1) of this definition, and that the mixture's other components do not
interfere with the specific CEM readings or cause the CEM being zeroed
to read concentrations of the gas being zeroed.
3. Section 72.3 is amended by adding in alphabetical order, new
acronyms for kacfm, kscfh, and NIST to read as follows:
Sec. 72.3 Measurements, abbreviations, and acronyms.
* * * * *
kacfm--thousands of cubic feet per minute at actual conditions.
kscfh--thousands of cubic feet per hour at standard conditions.
NIST--National Institute of Standards and Technology.
* * * * *
Sec. 72.6 [Amended]
4. Section 72.6 is amended by removing from paragraph (b)(1) the
word ``operation'' and adding, in its place, the words ``commercial
operation.''
5. Section 72.90 is amended by revising paragraph (c)(3) to read as
follows:
Sec. 72.90 Annual compliance certification report.
* * * * *
(c) * * *
(3) Whether all the emissions from the unit, or a group of units
(including the unit) using a common stack, were monitored or accounted
for through the missing data procedures and reported in the quarterly
monitoring reports, including whether conditional data were reported in
the quarterly report. If conditional data were reported, the owner or
operator shall indicate whether the status of all conditional data has
been resolved and all necessary quarterly report resubmissions have
been made.
* * * * *
PART 75--CONTINUOUS EMISSION MONITORING
6. The authority citation for part 75 continues to read as follows:
Authority: 42 U.S.C. 7601 and 7651k.
7. Section 75.1 is amended by revising paragraph (a) to read as
follows:
Sec. 75.1 Purpose and scope.
(a) Purpose. The purpose of this part is to establish requirements
for the monitoring, recordkeeping, and reporting of sulfur dioxide,
nitrogen oxides, and carbon dioxide emissions, volumetric flow, and
opacity data from affected units under the Acid Rain Program pursuant
to Sections 412 and 821 of the Clean Air Act, 42 U.S.C. 7401-7671q as
amended by Public Law 101-549 (November 15, 1990) (the Act). In
addition, this part sets forth provisions for the monitoring,
recordkeeping, and reporting of NOX mass emissions with
which EPA, individual States, or groups of States may require sources
to comply in order to demonstrate compliance with a NOX mass
emission reduction program, if these provisions are adopted as
requirements under such a program.
* * * * *
8. Section 75.2 is amended by revising paragraph (a) and adding a
new paragraph (c) to read as follows:
Sec. 75.2 Applicability.
(a) Except as provided in paragraphs (b) and (c) of this section,
the provisions of this part apply to each affected unit subject to Acid
Rain emission limitations or reduction requirements for SO2
or NOX.
* * * * *
(c) The provisions of this part may apply to sources subject to a
State or federal NOX mass emission reduction program, if
these provisions are adopted as requirements under such a program.
9. Section 75.4 is amended by revising paragraphs (a) introductory
text and (d)(1) and adding a new paragraph (i) to read as follows:
Sec. 75.4 Compliance dates.
(a) The provisions of this part apply to each existing Phase I and
Phase II unit on February 10, 1993. For substitution or compensating
units that are so designated under the Acid Rain permit which governs
that unit and contains the approved substitution or reduced utilization
plan, pursuant to Sec. 72.41 or Sec. 72.43 of this chapter, the
provisions of this part become applicable upon the issuance date of the
Acid Rain permit. For combustion sources seeking to enter the Opt-in
Program in accordance with part 74 of this chapter, the provisions of
this part become applicable upon the submission of an Opt-in permit
application in accordance with Sec. 74.14 of this chapter. The
provisions of this part for the monitoring, recording, and reporting of
NOX mass emissions become applicable on the deadlines
specified in the applicable State or federal NOX mass
emission reduction program, if these provisions are adopted as
requirements under such a program. In accordance with Sec. 75.20, the
owner or operator of each existing affected unit shall ensure that all
monitoring systems required by
[[Page 28120]]
this part for monitoring SO2, NOX,
CO2, opacity, and volumetric flow are installed and that all
certification tests are completed no later than the following dates
(except as provided in paragraphs (d) through (h) of this section):
* * * * *
(d) * * *
(1) The maximum potential concentration of SO2, the
maximum potential NOX emission rate, the maximum potential
flow rate, as defined in section 2.1 of appendix A to this part, or the
maximum potential CO2 concentration, as defined in section
2.1.3.1 of appendix A to this part.
* * * * *
(i) In accordance with Sec. 75.20, the owner or operator of each
affected unit at which SO2 concentration is measured on a
dry basis or at which moisture corrections are required to account for
CO2 emissions, NOX emission rate in lb/mmBtu, or
heat input, shall ensure that the continuous moisture monitoring system
required by this part is installed and that all applicable initial
certification tests required under Sec. 75.20(c)(5), (c)(6), or (c)(7)
for the continuous moisture monitoring system are completed no later
than the following dates:
(1) January 1, 2000, for a unit that is existing and has commenced
commercial operation by October 3, 1999; or
(2) For a new affected unit which has not commenced commercial
operation by October 4, 1999, not later than 90 days after the date the
unit commences commercial operation; or
(3) For an existing unit that is shutdown and is not yet operating
by January 1, 2000, not later than the earlier of 45 unit operating
days or 180 calendar days after the date that the unit recommences
commercial operation.
10. Section 75.5 is amended by revising paragraph (f)(2) to read as
follows:
Sec. 75.5 Prohibitions.
* * * * *
(f) * * *
(2) The owner or operator is monitoring emissions from the unit
with another certified monitoring system or an excepted methodology
approved by the Administrator for use at that unit that provides
emission data for the same pollutant or parameter as the retired or
discontinued monitoring system; or
* * * * *
11. Section 75.6 is amended by redesignating paragraph (a)(40) as
paragraph (a)(41) and by adding new paragraphs (a)(40) and (f) to read
as follows:
Sec. 75.6 Incorporation by reference.
* * * * *
(a) * * *
(40) ASTM D5373-93, ``Standard Methods for Instrumental
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples
of Coal and Coke,'' for appendix G to this part.
* * * * *
(f) The following materials are available for purchase from the
following address: American Petroleum Institute, Publications
Department, 1220 L Street NW, Washington, DC 20005-4070: American
Petroleum Institute (API) Section 2, ``Conventional Pipe Provers,''
from Chapter 4 of the Manual of Petroleum Measurement Standards,
October 1988 (Reaffirmed 1993), for Sec. 75.20 and appendix D to this
part.
12. Section 75.10 is amended by revising paragraphs (d)(3) and (f)
to read as follows:
Sec. 75.10 General operating requirements.
* * * * *
(d) * * *
(3) Failure of an SO2, CO2, or O2
pollutant concentration monitor, flow monitor, or NOX
continuous emission monitoring system to acquire the minimum number of
data points for calculation of an hourly average in paragraph (d)(1) of
this section, shall result in the failure to obtain a valid hour of
data and the loss of such component data for the entire hour. An hourly
average NOX or SO2 emission rate in lb/mmBtu is
valid only if the minimum number of data points is acquired by both the
pollutant concentration monitor (NOX or SO2) and
the diluent monitor (O2 or CO2). For a moisture
monitoring system consisting of one or more oxygen analyzers capable of
measuring O2 on a wet-basis and a dry-basis, an hourly
average percent moisture value is valid only if the minimum number of
data points is acquired for both the wet-and dry-basis measurements.
Except for SO2 emission rate data in lb/mmBtu, if a valid
hour of data is not obtained, the owner or operator shall estimate and
record emission, moisture, or flow data for the missing hour by means
of the automated data acquisition and handling system, in accordance
with the applicable procedure for missing data substitution in subpart
D of this part.
* * * * *
(f) Minimum measurement capability requirement. The owner or
operator shall ensure that each continuous emission monitoring system
and component thereof is capable of accurately measuring, recording,
and reporting data, and shall not incur a full scale exceedance, except
as provided in sections 2.1.1.5, 2.1.2.5, and 2.1.4.3 of appendix A to
this part.
* * * * *
13. Section 75.11 is amended by revising paragraphs (a), (b),
(d)(1), (d)(2), (e)(2), (e)(3) introductory text, (e)(3)(ii),
(e)(3)(iv), and (e)(4) and by adding paragraph (d)(3), to read as
follows:
Sec. 75.11 Specific provisions for monitoring SO2 emissions
(SO2 and flow monitors).
(a) Coal-fired units. The owner or operator shall meet the general
operating requirements in Sec. 75.10 for an SO2 continuous
emission monitoring system and a flow monitoring system for each
affected coal-fired unit while the unit is combusting coal and/or any
other fuel, except as provided in paragraph (e) of this section, in
Sec. 75.16, and in subpart E of this part. During hours in which only
natural gas or gaseous fuel with a total sulfur content no greater than
the total sulfur content of natural gas (i.e., 20 grains
per 100 standard cubic feet (gr/100 scf)) is combusted in the unit, the
owner or operator shall comply with the applicable provisions of
paragraph (e)(1), (e)(2), or (e)(3) of this section.
(b) Moisture correction. Where SO2 concentration is
measured on a dry basis, the owner or operator shall install, operate,
maintain, and quality assure a continuous moisture monitoring system
for measuring and recording the moisture content of the flue gases, in
order to correct the measured hourly volumetric flow rates for moisture
when calculating SO2 mass emissions (in lb/hr) using the
procedures in appendix F to this part. The following continuous
moisture monitoring systems are acceptable: a continuous moisture
sensor; an oxygen analyzer (or analyzers) capable of measuring
O2 both on a wet basis and on a dry basis; or a stack
temperature sensor and a moisture look-up table, i.e., a psychrometric
chart (for saturated gas streams following wet scrubbers, only). The
moisture monitoring system shall include as a component the automated
data acquisition and handling system (DAHS) for recording and reporting
both the raw data (e.g., hourly average wet and dry-basis O2
values) and the hourly average values of the stack gas moisture content
derived from those data. When a moisture look-up table is used, the
moisture monitoring system shall be represented as a single component,
the certified DAHS, in the monitoring plan for the unit or common
stack.
* * * * *
(d) * * *
(1) By meeting the general operating requirements in Sec. 75.10 for
an SO2 continuous emission monitoring system
[[Page 28121]]
and flow monitoring system. If this option is selected, the owner or
operator shall comply with the applicable provisions in paragraph
(e)(1), (e)(2), or (e)(3) of this section during hours in which the
unit combusts only natural gas (or gaseous fuel with a total sulfur
content no greater than the total sulfur content of natural gas);
(2) By providing other information satisfactory to the
Administrator using the applicable procedures specified in appendix D
to this part for estimating hourly SO2 mass emissions.
Appendix D shall not, however, be used when the unit combusts gaseous
fuel with a total sulfur content greater than the total sulfur content
of natural gas (i.e., > 20 gr/100 scf); when such fuel is burned, the
owner or operator shall comply with the provisions of paragraph (e)(4)
of this section; or
(3) By using the low mass emissions excepted methodology in
Sec. 75.19(c) for estimating hourly SO2 mass emissions if
the affected unit qualifies as a low mass emissions unit under
Sec. 75.19(a) and (b).
(e) * * *
(2) When gaseous fuel with a total sulfur content no greater than
the total sulfur content of natural gas (i.e., 20 gr/100
scf) is combusted in the unit, the owner or operator may, in lieu of
operating and recording data from the SO2 monitoring system,
determine SO2 emissions by certifying an excepted monitoring
system in accordance with Sec. 75.20 and with appendix D to this part,
by following the fuel sampling and analysis procedures in section 2.3.1
of appendix D to this part, by meeting the recordkeeping requirements
of Sec. 75.55 or Sec. 75.58, as applicable, and by meeting all quality
control and quality assurance requirements for fuel flowmeters in
appendix D to this part. If this compliance option is selected, the
hourly unit heat input reported under Sec. 75.54(b)(5) or
Sec. 75.57(b)(5), as applicable, shall be determined using a certified
flow monitoring system and a certified diluent monitor, in accordance
with the procedures in section 5.2 of appendix F of this part. The flow
monitor and diluent monitor shall meet all of the applicable quality
control and quality assurance requirements of appendix B of this part.
(3) When gaseous fuel with a total sulfur content no greater than
the total sulfur content of natural gas (i.e., 20 gr/100
scf) is burned in the unit, the owner or operator may determine
SO2 mass emissions by using a certified SO2
continuous monitoring system, in conjunction with a certified flow rate
monitoring system. However, on and after January 1, 2000, the
SO2 monitoring system shall be subject to the following
provisions; prior to January 1, 2000, the owner or operator may comply
with these provisions:
* * * * *
(ii) The calibration response of the SO2 monitoring
system shall be adjusted, either automatically or manually, in
accordance with the procedures for routine calibration adjustments in
section 2.1.3 of appendix B to this part, whenever the zero-level
calibration response during a required daily calibration error test
exceeds the applicable performance specification of the instrument in
section 3.1 of appendix A to this part (i.e., 2.5 percent
of the span value or 5 ppm, whichever is less
restrictive). This calibration adjustment is optional if gaseous fuel
is burned in the affected unit only during unit startup.
* * * * *
(iv) In accordance with the requirements of section 2.1.1.2 of
appendix A to this part, for units that sometimes burn natural gas (or
gaseous fuel with a total sulfur content no greater than the total
sulfur content of natural gas) and at other times burn higher-sulfur
fuel(s) such as coal or oil, a second low-scale SO2
measurement range is not required when natural gas (or gaseous fuel
with a total sulfur content no greater than the total sulfur content of
natural gas) is combusted. For units that burn only natural gas (or
gaseous fuel with a total sulfur content no greater than the total
sulfur content of natural gas) and burn no other type(s) of fuel(s),
the owner or operator shall set the span of the SO2
monitoring system to a value no greater than 200 ppm.
(4) During any hours in which a unit combusts only gaseous fuel(s)
with a total sulfur content no greater than the total sulfur content of
natural gas (i.e., 20 gr/100 scf), the owner or operator
shall meet the general operating requirements in Sec. 75.10 for an
SO2 continuous emission monitoring system and a flow
monitoring system.
* * * * *
14. Section 75.12 is amended by revising the title; by
redesignating existing paragraphs (b), (c), and (d) as paragraphs (c),
(d), and (f), respectively; by adding new paragraphs (b) and (e); and
by revising the newly designated paragraph (c), to read as follows:
Sec. 75.12 Specific provisions for monitoring NOX emission
rate (NOX and diluent gas monitors).
* * * * *
(b) Moisture correction. If a correction for the stack gas moisture
content is needed to properly calculate the NOX emission
rate in lb/mmBtu, i.e., if the NOX pollutant concentration
monitor measures on a different moisture basis from the diluent
monitor, the owner or operator shall install, operate, maintain, and
quality assure a continuous moisture monitoring system, as defined in
Sec. 75.11(b).
(c) Determination of NOX emission rate. The owner or
operator shall calculate hourly, quarterly, and annual NOX
emission rates (in lb/mmBtu) by combining the NOX
concentration (in ppm), diluent concentration (in percent O2
or CO2), and percent moisture (if applicable) measurements
according to the procedures in appendix F to this part.
* * * * *
(e) Low mass emissions units. Notwithstanding the requirements of
Secs. 75.12(a) and (c), the owner or operator of an affected unit that
qualifies as a low mass emissions unit under Sec. 75.19(a) and (b)
shall comply with one of the following:
(1) Meet the general operating requirements in Sec. 75.10 for a
NOX continuous emission monitoring system;
(2) Meet the requirements specified in paragraph (d)(2) of this
section for using the excepted monitoring procedures in appendix E to
this part, if applicable; or
(3) Use the low mass emissions excepted methodology in
Sec. 75.19(c) for estimating hourly NOX emission rate and
hourly NOX mass emissions.
* * * * *
15. Section 75.13 is amended by revising paragraphs (a) and (c) and
by adding paragraph (d) to read as follows:
Sec. 75.13 Specific provisions for monitoring CO2
emissions.
(a) CO2 continuous emission monitoring system. If the
owner or operator chooses to use the continuous emission monitoring
method, then the owner or operator shall meet the general operating
requirements in Sec. 75.10 for a CO2 continuous emission
monitoring system and flow monitoring system for each affected unit.
The owner or operator shall comply with the applicable provisions
specified in Secs. 75.11(a) through (e) or Sec. 75.16, except that the
phrase ``SO2 continuous emission monitoring system'' is
replaced with ``CO2 continuous emission monitoring system,''
the phrase ``SO2 concentration'' is replaced with
``CO2 concentration,'' the term ``maximum potential
concentration of SO2'' is replaced with ``maximum potential
concentration of CO2,'' and the phrase ``SO2 mass
emissions'' is replaced with ``CO2 mass emissions.''
* * * * *
(c) Determination of CO2 mass emissions using an O2
monitor
[[Page 28122]]
according to appendix F. If the owner or operator chooses to use the
appendix F method, then the owner or operator may determine hourly
CO2 concentration and mass emissions with a flow monitoring
system; a continuous O2 concentration monitor; fuel F and
Fc factors; and, where O2 concentration is
measured on a dry basis, a continuous moisture monitoring system, as
defined in Sec. 75.11(b), using the methods and procedures specified in
appendix F to this part. For units using a common stack, multiple
stack, or bypass stack, the owner or operator may use the provisions of
Sec. 75.16, except that the phrase ``SO2 continuous emission
monitoring system'' is replaced with ``CO2 continuous
emission monitoring system,'' the term ``maximum potential
concentration of SO2'' is replaced with ``maximum potential
concentration of CO2,'' and the phrase ``SO2 mass
emissions'' is replaced with ``CO2 mass emissions.''
(d) Determination of CO2 mass emissions from low mass
emissions units. The owner or operator of a unit that qualifies as a
low mass emissions unit under Secs. 75.19(a) and (b) shall comply with
one of the following:
(1) Meet the general operating requirements in Sec. 75.10 for a
CO2 continuous emission monitoring system and flow
monitoring system;
(2) Meet the requirements specified in paragraph (b) or (c) of this
section for use of the methods in appendix G or F to this part,
respectively; or
(3) Use the low mass emissions excepted methodology in
Sec. 75.19(c) for estimating hourly CO2 mass emissions.
16. Section 75.16 is amended by:
a. Revising paragraphs (b)(2)(ii)(B), (b)(2)(ii)(D), (d)(2), and
(e)(1);
b. Removing paragraphs (e)(2) and (e)(3);
c. Redesignating existing paragraphs (e)(4) and (e)(5) as
paragraphs (e)(2) and (e)(3), respectively;
d. Revising the last sentence and adding a new sentence to the end
of the newly designated paragraph (e)(3); and
e. Adding a new paragraph (e)(4), to read as follows:
Sec. 75.16 Special provisions for monitoring emissions from common,
bypass, and multiple stacks for SO2 emissions and heat input
determinations.
* * * * *
(b) * * *
(2) * * *
(ii) * * *
(B) Install, certify, operate, and maintain an SO2
continuous emission monitoring system and flow monitoring system in the
duct from each nonaffected unit; determine SO2 mass
emissions from the affected units as the difference between
SO2 mass emissions measured in the common stack and
SO2 mass emissions measured in the ducts of the nonaffected
units, not to be reported as an hourly average value less than zero;
combine emissions for the Phase I and Phase II affected units for
recordkeeping and compliance purposes; calculate and report
SO2 mass emissions from the Phase I and Phase II affected
units, pursuant to an approach approved by the Administrator, such that
these emissions are not underestimated; or
* * * * *
(D) Petition through the designated representative and provide
information satisfactory to the Administrator on methods for
apportioning SO2 mass emissions measured in the common stack
to each of the units using the common stack and on reporting the
SO2 mass emissions. The Administrator may approve such
demonstrated substitute methods for apportioning and reporting
SO2 mass emissions measured in a common stack whenever the
demonstration ensures that there is a complete and accurate accounting
of all emissions regulated under this part and, in particular, that the
emissions from any affected unit are not underestimated.
* * * * *
(d) * * *
(2) Install, certify, operate, and maintain an SO2
continuous emission monitoring system and flow monitoring system in
each stack. Determine SO2 mass emissions from each affected
unit as the sum of the SO2 mass emissions recorded for each
stack. Notwithstanding the prior sentence, if another unit also
exhausts flue gases to one or more of the stacks, the owner or operator
shall also comply with the applicable common stack requirements of this
section to determine and record SO2 mass emissions from the
units using that stack and shall calculate and report SO2
mass emissions from the affected units and stacks, pursuant to an
approach approved by the Administrator, such that these emissions are
not underestimated.
(e) * * *
(1) The owner or operator of an affected unit using a common stack,
bypass stack, or multiple stack with a diluent monitor and a flow
monitor on each stack may choose to install monitors to determine the
heat input for the affected unit, wherever flow and diluent monitor
measurements are used to determine the heat input, using the procedures
specified in paragraphs (a) through (d) of this section, except that
the terms ``SO2 mass emissions'' and ``emissions'' are
replaced with the term ``heat input'' and the phrase ``SO2
continuous emission monitoring system and flow monitoring system'' is
replaced with the phrase ``a diluent monitor and a flow monitor.'' The
applicable equation in appendix F to this part shall be used to
calculate the heat input from the hourly flow rate, diluent monitor
measurements, and (if the equation in appendix F requires a correction
for the stack gas moisture content) hourly moisture measurements.
Notwithstanding the options for combining heat input in paragraphs
(a)(1)(ii), (a)(2)(ii), (b)(1)(ii), and (b)(2)(ii) of this section, the
owner or operator of an affected unit with a diluent monitor and a flow
monitor installed on a common stack to determine the combined heat
input at the common stack shall also determine and report heat input to
each individual unit.
* * * * *
(3) * * * The heat input may be apportioned either by using the
ratio of load (in MWe-hr) for each individual unit to the total load
for all units utilizing the common stack or by using the ratio of steam
flow (in 1000 lb) for each individual unit to the total steam flow for
all units utilizing the common stack. The heat input should be
apportioned according to the procedures in appendix F to this part.
(4) Notwithstanding paragraph (e)(1) of this section, any affected
unit that is using the procedures in this part to meet the monitoring
and reporting requirements of a State or federal NOX mass
emission reduction program must also meet the requirements for
monitoring heat input in Secs. 75.71 and 75.72.
17. Section 75.17 is amended by adding introductory text before
paragraph (a) and by revising paragraph (a)(2)(i)(C) to read as
follows:
Sec. 75.17 Specific provisions for monitoring emissions from common,
by-pass, and multiple stacks for NOX emission rate.
Notwithstanding the provisions of paragraphs (a), (b), and (c) of
this section, the owner or operator of an affected unit that is using
the procedures in this part to meet the monitoring and reporting
requirements of a State or federal NOX mass emission
reduction program must also meet the provisions for monitoring
NOX emission rate in Secs. 75.71 and 75.72.
(a) * * *
(2) * * *
(i) * * *
(C) Each unit's compliance with the applicable NOX
emission limit will be determined by a method satisfactory to
[[Page 28123]]
the Administrator for apportioning to each of the units the combined
NOX emission rate (in lb/mmBtu) measured in the common stack
and for reporting the NOX emission rate, as provided in a
petition submitted by the designated representative. The Administrator
may approve such demonstrated substitute methods for apportioning and
reporting NOX emission rate measured in a common stack
whenever the demonstration ensures that there is a complete and
accurate estimation of all emissions regulated under this part and, in
particular, that the emissions from any unit with a NOX
emission limitation are not underestimated.
* * * * *
18. Section 75.19 is added to subpart B to read as follows:
Sec. 75.19 Optional SO2, NOX, and CO2
emissions calculation for low mass emissions units.
(a) Applicability. (1) Consistent with the requirements of
paragraphs (a)(2) and (b) of this section, the low mass emissions
excepted methodology in paragraph (c) of this section may be used in
lieu of continuous emission monitoring systems or, if applicable, in
lieu of excepted methods under appendix D or E to this part, for the
purpose of determining hourly heat input, hourly NOX
emission rate, and hourly NOX, SO2, and
CO2 mass emissions from a low mass emissions unit. A low
mass emissions unit is a gas-fired or oil-fired unit that burns only
natural gas and/or fuel oil and that:
(i) Emits no more than 25 tons of SO2 annually and no
more than 25 tons of NOX annually; and
(ii) Has calculated emissions of no more than 25 tons of
SO2 annually and no more than 25 tons of NOX
annually based on the maximum rated hourly heat input, the actual
operating time for each fuel burned, and the low mass emissions
excepted methodology, calculations, and values in paragraph (c) of this
section.
(2) A unit may initially qualify as a low mass emissions unit only
under the following circumstances:
(i) The designated representative provides historical actual and
calculated emissions data from the previous three calendar years
immediately prior to the submission of an application to use the low
mass emissions excepted methodology, and the data demonstrates to the
satisfaction of the Administrator that the unit meets the criteria in
paragraphs (a)(1)(i) and (ii) of this section; or
(ii) If a unit does not have the historical data required in
paragraph (a)(2)(i) of this section for any one or more of the previous
three calendar years, the designated representative submits:
(A) Any historical annual emissions and operating data, as required
in paragraphs (a)(1)(i) and (a)(1)(ii) of this section, beginning with
the unit's first calendar year of commercial operation, and the data
demonstrates to the satisfaction of the Administrator that the unit
meets the criteria in paragraphs (a)(1)(i) and (a)(1)(ii) of this
section; and
(B) A demonstration satisfactory to the Administrator that the unit
will continue to qualify as a low mass emissions unit under the
requirements of this paragraph (a). The demonstration shall include any
historical emissions and operating data for less than a calendar year
for the unit and projected emissions information for the unit, as
determined using projected operating hours and fuel usage, and the low
mass emissions excepted methodology, calculations, and values in
paragraph (c) of this section.
(b) Disqualification. If a unit that initially qualifies as a low
mass emissions units under this section changes the fuel that is burned
in the unit such that a fuel other than natural gas or fuel oil is
combusted in the unit, the unit is disqualified from using the low mass
emissions excepted methodology as of the first hour that the new fuel
is combusted in the unit. In addition, if a unit that initially
qualifies as a low mass emissions unit under this section emits more
than 25 tons of SO2 or 25 tons of NOX in any
calendar year or has calculated emissions greater than 25 tons of
SO2 or 25 tons of NOX in any calendar year, as
determined using the low mass emission equations in paragraph (c) of
this section, the owner or operator of the unit shall have two quarters
from the end of the quarter in which the exceedance occurs to install,
certify, and report SO2, NOX, and CO2
from monitoring systems that meet the requirements of Secs. 75.11,
75.12, and 75.13, respectively. The unit shall be disqualified as a low
mass emissions unit as of the end of the second quarter following the
quarter in which either of the 25 ton limits was exceeded. A unit that
has been disqualified from using the low mass emissions excepted
methodology may subsequently qualify again as a low mass emissions unit
under paragraph (a)(2) of this section, provided that if such unit
qualified under paragraph (a)(2)(ii) of this section, the unit may
subsequently qualify again if the unit meets the requirements of
paragraph (a)(2)(i) of this section.
(c) Low mass emissions excepted methodology, calculations, and
values.--(1) Operating time. (i) Report an hourly record if the unit
operated for any portion of the hour or if records are missing, as to
whether or not the unit operated for any portion of that hour.
(ii) Quarterly operating time (hr) is equal to the sum of all of
the reported operating hours in the quarter, such that any hour in
which the unit combusted fuel for any portion of the hour is considered
a full hour.
(iii) Year-to-date cumulative operating time (hr) is equal to the
sum of all of the reported operating hours in the year to date, such
that any hour in which the unit combusted fuel for any portion of the
hour is considered a full hour.
(2) Heat input. (i) Hourly heat input (mmBtu) is equal to the
maximum rated hourly heat input, as defined in Sec. 72.2 of this
chapter. However, the owner or operator of an affected unit may
petition the Administrator under Sec. 75.66 for a lower value for
maximum rated hourly heat input than that defined in Sec. 72.2 of this
chapter. The Administrator may approve such lower value if the owner or
operator demonstrates that either the maximum hourly heat input
specified by the manufacturer or the highest observed hourly heat
input, or both, are not representative of the unit's current
capabilities because modifications have been made to the unit, limiting
its capacity permanently.
(ii) Calculate the quarterly total heat input (mmBtu) using
Equation 7a as follows:
HIqtr = Tqtr x HIhr
(Eq. 7a)
where:
Tqtr = Actual number of operating hours in the quarter, in
hr.
HIhr = Hourly heat input under paragraph (c)(2)(i) of this
section, in mmBtu.
(iii) Calculate the year-to-date cumulative heat input (mmBtu) as
the sum of all of the hourly heat input values in the year to date.
(3) SO2. (i) Calculate the hourly total SO2
mass emissions (lbs) using Equation 7b and the appropriate fuel-based
SO2 emission factor from Table 1a for the fuel being burned
in that hour. If more than one fuel is burned in the hour, use the
highest emission factor for all of the fuels burned in the hour. If
records are missing as to which fuel was burned in the hour, use the
highest emission factor for all of the fuels capable of being burned in
that unit.
Table 1a.--SO2 Emission Factors (lb/mmBtu) for Various Fuel Types
------------------------------------------------------------------------
Fuel type SO2 Emission factors
------------------------------------------------------------------------
Pipeline Natural Gas...................... 0.0006 lb/mmBtu.
[[Page 28124]]
Natural Gas............................... 0.06 lb/mmBtu.
Residual Oil.............................. 2.1 lb/mmBtu.
Diesel Fuel............................... 0.5 lb/mmBtu.
------------------------------------------------------------------------
WSO2 = EFSO2 x HIhr
(Eq. 7b)
Where:
WSO2 = SO2 mass emissions, in lbs.
EFSO2 = Fuel-based SO2 emission factor
from Table 1a of this section, in lb/mmBtu.
HIhr = Hourly heat input under paragraph (c)(2)(i) of this
section, in mmBtu.
(ii) Calculate the quarterly total SO2 mass emissions
(tons) by summing all of the hourly SO2 mass emissions under
paragraph (c)(3)(i) of this section in the quarter and dividing by 2000
lb/ton.
(iii) Calculate the year-to-date cumulative SO2 mass
emissions (tons) by summing all of the SO2 mass emissions
under paragraph (c)(3)(i) of this section in the year to date.
(4) NOX. (i) Determine the hourly NOX
emission rate (lb/mmBtu) by using the appropriate fuel and boiler type
default NOX emission rate in Table 1b for the fuel being
burned in that hour. If more than one fuel is burned in the hour, use
the highest emission rate for all of the fuels burned in the hour. If
records are missing as to which fuel was burned in the hour, use the
highest emission factor for all of the fuels capable of being burned in
that unit.
Table 1b.--NOX Emission Rates (lb/mmBtu) for Various Boiler/Fuel Types
------------------------------------------------------------------------
NOX
Boiler type Fuel type Emission
rate
------------------------------------------------------------------------
Tangentially fired................. Oil................... 0.366
Tangentially fired................. Gas................... 0.290
Dry Bottom Wall fired.............. Oil................... 0.490
Dry Bottom Wall fired.............. Gas................... 0.400
Combustion Turbine................. Oil................... 0.258
Combustion Turbine................. Gas................... 0.172
Combined Cycle..................... Oil................... 0.273
Combined Cycle..................... Gas................... 0.273
------------------------------------------------------------------------
(ii) Calculate the hourly total NOX mass emissions (lbs)
as the product of the NOX emission rate (lb/mmBtu) and
hourly heat input (mmBtu), using Equation 7c as follows:
WNOX = EFNOX x HIhr
(Eq. 7c)
where:
WNOX = NOX mass emissions, in lbs.
EFNOX = Boiler-type and fuel-type NOX emission
factor from Table 1b of this section, in lb/mmBtu.
HIhr = Hourly heat input under paragraph (c)(2)(i) of this
section, in mmBtu.
(iii) Calculate the quarterly average NOX emission rate
(lb/mmBtu) by summing all of the hourly NOX emission rates
for the quarter and dividing the total by the number of reported
operating hours under paragraph (c)(1)(i) of this section in the
quarter.
(iv) Calculate the quarterly total NOX mass emissions
(tons) by summing all of the hourly NOX mass emissions under
paragraph (c)(4)(ii) of this section in the quarter and dividing the
total by 2000 lb/ton.
(v) Calculate the year-to-date cumulative average NOX
emission rate (lb/mmBtu) by summing all of the hourly NOX
emission rates for all of the hours in the year to date and dividing
the total by the number of reported operating hours under paragraph
(c)(1)(i) of this section in the year to date.
(vi) Calculate the year-to-date cumulative NOX mass
emissions total (tons) by summing all of the hourly NOX mass
emissions under paragraph (c)(4)(ii) of this section in the year to
date.
(5) CO2. (i) Calculate the hourly total CO2
mass emissions (tons) using Equation 7d and the appropriate fuel-based
CO2 emission factor from Table 1c for the fuel being burned
in that hour. If more than one fuel is burned in the hour, use the
highest emission factor for all of the fuels burned in the hour. If
records are missing as to which fuel was burned in the hour, use the
highest emission factor for all of the fuels capable of being burned in
that unit.
Table 1c.--CO2 Emission Factors (ton/mmBtu) for Gas and Oil
------------------------------------------------------------------------
Fuel type CO2 emission factors
------------------------------------------------------------------------
Natural Gas............................... 0.059 ton/mmBtu.
Oil....................................... 0.081 ton/mmBtu.
------------------------------------------------------------------------
WCO2=EFCO2 x HIhr
(Eq. 7d)
Where:
WCO2 = CO2 mass emissions, in tons.
EFCO2 = Fuel-based CO2 emission factor from Table
1c, in ton/mmBtu.
HIhr = Hourly heat input under paragraph (c)(2)(i) of this
section, in mmBtu.
(ii) Calculate the quarterly total CO2 mass emissions
(tons) by summing all of the hourly CO2 mass emissions under
paragraph (c)(5)(i) of this section in the quarter.
(iii) Calculate the year-to-date cumulative CO2 mass
emissions (tons) by summing all of the hourly CO2 mass
emissions under paragraph (c)(5)(i) of this section in the year to
date.
(d) The quality control and quality assurance requirements in
Sec. 75.21 are not required for a low mass emissions unit for which the
optional low mass emissions excepted methodology in paragraph (c) of
this section is being used in lieu of a continuous emission monitoring
system or an excepted monitoring system under appendix D or E to this
part.
Subpart C--[Amended]
19. Section 75.20 is amended by:
a. Revising the title of the section;
b. Revising the titles of paragraphs (a)(3), (a)(4), (c), (d), (g),
(g)(1), (g)(2), (g)(4), and (g)(5);
c. Revising paragraphs (a) introductory text, (a)(1), (a)(3),
(a)(4) introductory text, (a)(4)(i), (a)(4)(ii), (a)(4)(iii),
(a)(5)(i), (b), (c) introductory text, (c)(1)(iii), (d)(1), (d)(2), (g)
introductory text, (g)(1) introductory text, (g)(1)(i), (g)(2), (g)(4),
and (g)(5);
d. Removing existing paragraph (c)(3);
e. Revising and redesignating existing paragraphs (c)(4), (c)(5),
(c)(6), (c)(7), and (c)(8) as paragraphs (c)(3), (c)(4), (c)(8),
(c)(9), and (c)(10), respectively; and revising newly designated
paragraphs (c)(4) introductory text, (c)(8) introductory text,
(c)(8)(i),
[[Page 28125]]
(c)(9)(ii), and (c)(10) introductory text; and
f. Adding new paragraphs (c)(5), (c)(6), (c)(7), (g)(6), (g)(7),
(h), and (i), to read as follows:
Sec. 75.20 Initial certification and recertification procedures.
(a) Initial certification approval process. The owner or operator
shall ensure that each continuous emission or opacity monitoring system
required by this part, which includes the automated data acquisition
and handling system, and, where applicable, the CO2
continuous emission monitoring system, meets the initial certification
requirements of this section and shall ensure that all applicable
initial certification tests under paragraph (c) of this section are
completed by the deadlines specified in Sec. 75.4 and prior to use in
the Acid Rain Program. In addition, whenever the owner or operator
installs a continuous emission or opacity monitoring system in order to
meet the requirements of Secs. 75.13 through 75.18, where no continuous
emission or opacity monitoring system was previously installed, initial
certification is required.
(1) Notification of initial certification test dates. The owner or
operator or designated representative shall submit a written notice of
the dates of initial certification testing at the unit as specified in
Sec. 75.61(a)(1).
* * * * *
(3) Provisional approval of certification (or recertification)
applications. Upon the successful completion of the required
certification (or recertification) procedures of this section for each
continuous emission or opacity monitoring system or component thereof,
each continuous emission or opacity monitoring system or component
thereof shall be deemed provisionally certified (or recertified) for
use under the Acid Rain Program for a period not to exceed 120 days
following receipt by the Administrator of the complete certification
(or recertification) application under paragraph (a)(4) of this
section, provided that no continuous emission or opacity monitor
systems for a combustion source seeking to enter the Opt-in Program in
accordance with part 74 of this chapter shall be deemed provisionally
certified (or recertified) for use under the Acid Rain Program. Data
measured and recorded by a provisionally certified (or recertified)
continuous emission or opacity monitoring system or component thereof,
in accordance with the requirements of appendix B to this part, will be
considered valid quality-assured data (retroactive to the date and time
of provisional certification or recertification)), provided that the
Administrator does not invalidate the provisional certification (or
recertification) by issuing a notice of disapproval within 120 days of
receipt by the Administrator of the complete certification (or
recertification) application. Note that if the data validation
procedures of paragraph (b)(3) of this section are applied to the
initial certification (or recertification) of a continuous emissions
monitoring system, it is possible for data recorded by the CEMS during
the certification (or recertification) test period to be quality
assured retrospectively, upon completion of all of the certification
(or recertification) tests. Therefore, in certain instances, the date
and time of provisional certification (or recertification) of the CEMS
may be earlier than the date and time of completion of the required
certification (or recertification) tests.
(4) Certification (or recertification) application formal approval
process. The Administrator will issue a notice of approval or
disapproval of the certification (or recertification) application to
the owner or operator within 120 days of receipt of the complete
certification (or recertification) application. In the event the
Administrator does not issue such a written notice within 120 days of
receipt, each continuous emission or opacity monitoring system which
meets the performance requirements of this part and is included in the
certification (or recertification) application will be deemed certified
(or recertified) for use under the Acid Rain Program.
(i) Approval notice. If the certification (or recertification)
application is complete and shows that each continuous emission or
opacity monitoring system meets the performance requirements of this
part, then the Administrator will issue a written notice of approval of
the certification (or recertification) application within 120 days of
receipt.
(ii) Incomplete application notice. A certification (or
recertification) application will be considered complete when all of
the applicable information required to be submitted in Sec. 75.63 has
been received by the Administrator, the EPA Regional Office, and the
appropriate State and/or local air pollution control agency. If the
certification (or recertification) application is not complete, then
the Administrator will issue a written notice of incompleteness that
provides a reasonable timeframe for the designated representative to
submit the additional information required to complete the
certification (or recertification) application. If the designated
representative has not complied with the notice of incompleteness by a
specified due date, then the Administrator may issue a notice of
disapproval specified under paragraph (a)(4)(iii) of this section. The
120-day review period shall not begin prior to receipt of a complete
application.
(iii) Disapproval notice. If the certification (or recertification)
application shows that any continuous emission or opacity monitoring
system or component thereof does not meet the performance requirements
of this part, or if the certification (or recertification) application
is incomplete and the requirement for disapproval under paragraph
(a)(4)(ii) of this section has been met, the Administrator shall issue
a written notice of disapproval of the certification (or
recertification) application within 120 days of receipt. By issuing the
notice of disapproval, the provisional certification (or
recertification) is invalidated by the Administrator, and the data
measured and recorded by each uncertified continuous emission or
opacity monitoring system or component thereof shall not be considered
valid quality-assured data beginning with the following time: from the
hour of the probationary calibration error test that began the initial
certification (or recertification) test period, if the data validation
procedures of paragraph (b)(3) of this section were used to
retrospectively validate data; or from the date and time of completion
of the invalid certification tests until the date and time that the
owner or operator completes subsequently approved initial certification
tests, if the data validation procedures of paragraph (b)(3) of this
section were not used. The owner or operator shall follow the
procedures for loss of initial certification in paragraph (a)(5) of
this section for each continuous emission or opacity monitoring system
or component thereof which is disapproved for initial certification.
For each disapproved recertification, the owner or operator shall
follow the procedures of paragraph (b)(5) of this section.
* * * * *
(5) * * *
(i) Until such time, date, and hour as the continuous emission
monitoring system or component thereof can be adjusted, repaired, or
replaced and certification tests successfully completed, the owner or
operator shall substitute the following values, as applicable, for each
hour of unit operation during the period of invalid
[[Page 28126]]
data specified in paragraph (a)(4)(iii) of this section or in
Sec. 75.21: the maximum potential concentration of SO2 as
defined in section 2.1.1.1 of appendix A to this part to report
SO2 concentration; the maximum potential NOX
emission rate, as defined in Sec. 72.2 of this chapter to report
NOX emissions; the maximum potential flow rate, as defined
in section 2.1.4.1 of appendix A to this part to report volumetric
flow; or the maximum potential concentration of CO2, as
defined in section 2.1.3.1 of appendix A to this part to report
CO2 concentration data; and
* * * * *
(b) Recertification approval process. Whenever the owner or
operator makes a replacement, modification, or change in a certified
continuous emission monitoring system or continuous opacity monitoring
system that is determined by the Administrator to significantly affect
the ability of the system to accurately measure or record the
SO2 or CO2 concentration, stack gas volumetric
flow rate, NOX emission rate, or opacity, or to meet the
requirements of Sec. 75.21 or appendix B to this part, the owner or
operator shall recertify the continuous emission monitoring system or
continuous opacity monitoring system, according to the procedures in
this paragraph. Furthermore, whenever the owner or operator makes a
replacement, modification, or change to the flue gas handling system or
the unit operation that is determined by the Administrator to
significantly change the flow or concentration profile, the owner or
operator shall recertify the monitoring system according to the
procedures in this paragraph. Examples of changes which require
recertification include: replacement of the analyzer; change in
location or orientation of the sampling probe or site; changing of flow
rate monitor polynomial coefficients; and complete replacement of an
existing continuous emission monitoring system or continuous opacity
monitoring system. The owner or operator shall recertify a continuous
opacity monitoring system whenever the monitor path length changes or
as required by an applicable State or local regulation or permit. Any
change to a stack flow rate or gas monitoring system for which the
Administrator determines that a RATA is not necessary shall not be
considered a recertification event. In such cases, any other tests that
the Administrator determines to be necessary (linearity checks,
calibration error tests, DAHS verifications, etc.) shall be performed
as diagnostic tests, rather than recertification tests. The data
validation procedures in paragraph (b)(3) of this section shall be
applied to linearity checks, 7-day calibration error tests, and cycle
time tests when these are required as diagnostic tests. When the data
validation procedures of paragraph (b)(3) of this section are applied
in this manner, replace the word ``recertification'' with the word
``diagnostic.''
(1) Tests required. For recertification testing after changing the
flow rate monitor polynomial coefficients, the owner or operator shall
complete a 3-level RATA. For all other recertification testing, the
owner or operator shall complete all initial certification tests in
paragraph (c) of this section that are applicable to the monitoring
system, except as otherwise approved by the Administrator.
(2) Notification of recertification test dates. The owner,
operator, or designated representative shall submit notice of testing
dates for recertification under this paragraph as specified in
Sec. 75.61(a)(1)(ii), unless all of the tests in paragraph (c) of this
section are required for recertification, in which case the owner or
operator shall provide notice in accordance with the notice provisions
for initial certification testing in Sec. 75.61(a)(1)(i).
(3) Recertification test period requirements and data validation.
(i) In the period extending from the hour of the replacement,
modification or change made to a monitoring system that triggers the
need to perform recertification test(s) of the CEMS to the hour of
successful completion of a probationary calibration error test
(according to paragraph (b)(3)(ii) of this section) following the
replacement, modification, or change to the CEMS, the owner or operator
shall either substitute for missing data, according to the standard
missing data procedures in Secs. 75.33 through 75.37, or report
emission data using a reference method or another monitoring system
that has been certified or approved for use under this part.
(ii) Once the modification or change to the CEMS has been completed
and all of the associated repairs, component replacements, adjustments,
linearization, and reprogramming of the CEMS have been completed, a
probationary calibration error test is required to establish the
beginning point of the recertification test period. In this instance,
the first successful calibration error test of the monitoring system
following completion of all necessary repairs, component replacements,
adjustments, reprogramming, and any preliminary tests (e.g., trial RATA
runs or a challenge of the monitor with calibration gases other than
those used to perform the daily calibration error test) shall be the
probationary calibration error test. The probationary calibration error
test must be passed before any of the required recertification tests
are commenced.
(iii) Beginning with the hour of commencement of a recertification
test period, emission data recorded by the CEMS are considered to be
conditionally valid, contingent upon the results of the subsequent
recertification tests.
(iv) Each required recertification test shall be completed no later
than the following number of unit operating hours after the
probationary calibration error test that initiates the test period:
(A) For a linearity test and/or cycle time test, 168 consecutive
unit operating hours;
(B) For a RATA (whether normal-load or multiple-load), 720
consecutive unit operating hours; and
(C) For a 7-day calibration error test, 21 consecutive unit
operating days.
(v) All recertification tests shall be performed hands-off, as
follows. No adjustments to the calibration of the CEMS, other than the
adjustments described in section 2.1.3 of appendix B to this part, are
permitted prior to or during the recertification test period. Routine
daily calibration error tests shall be performed throughout the
recertification test period, in accordance with section 2.1.1 of
appendix B to this part. The additional calibration error test
requirements in section 2.1.3 of appendix B to this part shall also
apply during the recertification test period.
(vi) If all of the required recertification tests and required
daily calibration error tests are successfully completed in succession
with no failures, and if each recertification test is completed within
the time period specified in paragraph (b)(3)(iv)(A), (B), or (C) of
this section, then all of the conditionally valid emission data
recorded by the CEMS shall be considered quality assured, from the hour
of commencement of the recertification test period until the hour of
completion of the required test(s).
(vii) If a required recertification test is failed or aborted due
to a problem with the CEMS, or if a calibration error test is failed
during a recertification test period, data validation shall be done as
follows:
(A) If any required recertification test is failed, it shall be
repeated. If any recertification test other than a 7-day calibration
error test is failed or aborted due to a problem with the CEMS, the
original recertification test period is ended, and a new
recertification test period must be commenced with a
[[Page 28127]]
probationary calibration error test. The tests that are required in
this new recertification test period will include any tests that were
required for the initial recertification event which were not
successfully completed and any recertification or diagnostic tests that
are required as a result of changes made to the monitoring system to
correct the problems that caused the failure of the recertification
test. The new recertification test sequence shall not be commenced
until all necessary maintenance activities, adjustments,
linearizations, and reprogramming of the CEMS have been completed;
(B) If a linearity test, RATA, or cycle time test is failed or
aborted due to a problem with the CEMS, all conditionally valid
emission data recorded by the CEMS are invalidated, from the hour of
commencement of the recertification test period to the hour in which
the test is failed or aborted. Data from the CEMS remain invalid until
the hour in which a new recertification test period is commenced,
following corrective action, and a probationary calibration error test
is passed, at which time the conditionally valid status of emission
data from the CEMS begins;
(C) If a 7-day calibration error test is failed within the
recertification test period, previously-recorded conditionally valid
emission data from the CEMS are not invalidated, provided that the
calibration error on the day of the failed 7-day calibration error test
does not exceed twice the performance specification in section 3 of
appendix A to this part; and
(D) If a calibration error test is failed (i.e., the results of the
test exceed twice the performance specification in section 3 of
appendix A to this part) during a recertification test period, the CEMS
is out-of-control as of the hour in which the calibration error test is
failed. Emission data from the CEMS shall be invalidated prospectively
from the hour of the failed calibration error test until the hour of
completion of a subsequent successful calibration error test following
corrective action, at which time the conditionally valid status of data
from the monitoring system resumes. Failure to perform a required daily
calibration error test during a recertification test period shall also
cause data from the CEMS to be invalidated prospectively, from the hour
in which the calibration error test was due until the hour of
completion of a subsequent successful calibration error test.
Previously-passed recertification tests in the sequence and previously-
recorded conditionally valid data shall not be affected by a late
calibration error test. Whenever a calibration error test is failed or
missed during a recertification test period, no further recertification
tests shall be performed until the required subsequent calibration
error has been passed, re-establishing the conditionally valid status
of data from the monitoring system.
(viii) If any required recertification test is not completed within
its allotted time period, data validation shall be done as follows. For
a late linearity test, RATA, or cycle time test that is passed on the
first attempt, data from the monitoring system shall be invalidated
from the hour of expiration of the recertification test period until
the hour of completion of the late test. For a late 7-day calibration
error test, whether or not it is passed on the first attempt, data from
the monitoring system shall also be invalidated from the hour of
expiration of the recertification test period until the hour of
completion of the late test. For a late linearity test, RATA, or cycle
time test that is failed on the first attempt or aborted on the first
attempt due to a problem with the monitor, all conditionally valid data
from the monitoring system shall be considered invalid back to the hour
of the first probationary calibration error test which initiated the
recertification test period. Data from the monitoring system shall
remain invalid until the hour of successful completion of the late
recertification test and any additional recertification or diagnostic
tests that are required as a result of changes made to the monitoring
system to correct problems that caused failure of the late
recertification test.
(ix) If any required recertification test of a monitoring system
has not been completed by the end of a calendar quarter and if data
contained in the quarterly report is conditionally valid pending the
results of test(s) to be completed in a subsequent quarter, the owner
or operator shall indicate this by means of a suitable conditional data
flag in the electronic quarterly report for that quarter. The owner or
operator shall resubmit the report for that quarter if the required
recertification test is subsequently failed. In the resubmitted report,
the owner or operator shall use the appropriate missing data routine in
Sec. 75.31 or Sec. 75.33 to replace with substitute data each hour of
conditionally valid data that was invalidated by the failed
recertification test. In addition, if the owner or operator submits any
conditionally valid data (as defined in Sec. 72.2 of this chapter) in
any of the four quarterly reports for a given year, the owner or
operator shall indicate the status of the conditionally valid data
(i.e., resolved or unresolved) in the annual compliance certification
report required under Sec. 72.90 of this chapter for that year.
Alternatively, if any required recertification test is not completed by
the end of a particular calendar quarter but is completed no later than
30 days after the end of that quarter (i.e., prior to the deadline for
submitting the quarterly report under Sec. 75.64), the test data and
results may be submitted with the earlier quarterly report even though
the test date(s) are from the next calendar quarter. In such instances,
if the recertification test(s) are passed in accordance with the
provisions of paragraph (b)(3) of this section, conditionally valid
data may be reported as quality-assured, in lieu of reporting a
conditional data flag. If the recertification test(s) is failed and if
conditionally valid data are replaced, as appropriate, with substitute
data, then neither the reporting of a conditional data flag nor
resubmission is required.
(x) If the replacement, modification, or change requiring
recertification of the CEMS is such that the data collected by the
prior certified monitoring system are no longer representative, such as
after a change to the flue gas handling system or unit operation that
requires changing the span value to be consistent with section 2.1 of
appendix A to this part, the owner or operator shall substitute for
missing data as follows, in the period extending from the hour of
commencement of the replacement, modification, or change requiring
recertification of the CEMS to the hour of commencement of the
recertification test period:
(A) For a change that results in a significantly higher
concentration or flow rate, substitute maximum potential values
according to the procedures in paragraph (a)(5) of this section; or
(B) For a change that results in a significantly lower
concentration or flow rate, substitute data using the standard missing
data procedures.
(C) The owner or operator shall then use the initial missing data
procedures in Sec. 75.31, beginning with the first hour of quality
assured data obtained with the recertified monitoring system, unless
otherwise provided by Sec. 75.34 for units with add-on emission
controls.
(4) Recertification application. The designated representative
shall apply for recertification of each continuous emission or opacity
monitoring system used under the Acid Rain Program. The owner or
operator shall submit the recertification application in accordance
with Sec. 75.60, and each complete recertification application shall
include the information specified in Sec. 75.63.
(5) Approval or disapproval of request for recertification. The
procedures for
[[Page 28128]]
provisional certification in paragraph (a)(3) of this section shall
apply to recertification applications. The Administrator will issue a
written notice of approval or disapproval according to the procedures
in paragraph (a)(4) of this section. In the event that a
recertification application is disapproved, data from the monitoring
system are invalidated and the applicable missing data procedures in
Sec. 75.31 or Sec. 75.33 shall be used from the date and hour of
receipt of such notice back to the hour of the probationary calibration
error test that began the recertification test period. Data from the
monitoring system remain invalid until a subsequent probationary
calibration error test is passed, beginning a new recertification test
period. The owner or operator shall repeat all recertification tests or
other requirements, as indicated in the Administrator's notice of
disapproval, no later than 30 unit operating days after the date of
issuance of the notice of disapproval. The designated representative
shall submit a notification of the recertification retest dates, as
specified in Sec. 75.61(a)(1)(ii), and shall submit a new
recertification application according to the procedures in paragraph
(b)(4) of this section.
(c) Initial certification and recertification procedures. Prior to
the deadline in Sec. 75.4, the owner or operator shall conduct initial
certification tests and in accordance with Sec. 75.63, the designated
representative shall submit an application to demonstrate that the
continuous emission or opacity monitoring system and components thereof
meet the specifications in appendix A to this part. The owner or
operator shall compare reference method values with output from the
automated data acquisition and handling system that is part of the
continuous emission monitoring system being tested. Except as specified
in paragraphs (b)(1), (d), and (e) of this section, the owner or
operator shall perform the following tests for initial certification or
recertification of continuous emission or opacity monitoring systems or
components according to the requirements of appendix A to this part:
(1) * * *
(iii) A relative accuracy test audit. For the NOX-
diluent system, the RATA shall be done on a system basis, in units of
lb/mmBtu.
* * * * *
(3) The initial certification test data from an O2-or a
CO2-diluent gas monitor certified for use in a
NOX continuous emission monitoring system may be submitted
to meet the requirements of paragraph (c)(4) of this section. Also, for
a diluent monitor that is used both as a CO2 monitoring
system and to determine heat input, only one set of diluent monitor
certification data need be submitted (under the component and system
identification numbers of the CO2 monitoring system).
(4) For each CO2 pollutant concentration monitor, each
O2 monitor which is part of a CO2 continuous
emission monitoring system, each diluent monitor used to monitor heat
input and each SO2-diluent continuous emission monitoring
system:
* * * * *
(5) For each continuous moisture monitoring system consisting of
wet-and dry-basis O2 analyzers:
(i) A 7-day calibration error test of each O2 analyzer;
(ii) A cycle time test of each O2 analyzer;
(iii) A linearity test of each O2 analyzer; and
(iv) A RATA, directly comparing the percent moisture measured by
the monitor to a reference method.
(6) For each continuous moisture sensor:
(i) A 7-day calibration error test; and
(ii) A RATA, directly comparing the percent moisture measured by
the monitor sensor to a reference method.
(7) For a continuous moisture monitoring system consisting of a
temperature sensor and a data acquisition and handling system (DAHS)
software component programmed with a moisture lookup table:
(i) A demonstration that the correct moisture value for each hour
is being taken from the moisture lookup tables and applied to the
emission calculations. At a minimum, the demonstration shall be made at
three different temperatures covering the normal range of stack
temperatures.
(ii) [Reserved]
(8) The owner or operator shall ensure that initial certification
or recertification of a continuous opacity monitor for use under the
Acid Rain Program is conducted according to one of the following
procedures:
(i) Performance of the tests for initial certification or
recertification, according to the requirements of Performance
Specification 1 in appendix B to part 60 of this chapter; or
* * * * *
(9) * * *
(ii) Proper computation and application of the missing data
substitution procedures in subpart D of this part and the bias
adjustment factors in section 7 of appendix A to this part.
(10) The owner or operator shall provide, or cause to be provided,
adequate facilities for initial certification or recertification
testing that include:
* * * * *
(d) Initial certification and recertification and quality assurance
procedures for optional backup continuous emission monitoring systems.
(1) Redundant backups. The owner or operator of an optional
redundant backup continuous emission monitoring system shall comply
with all the requirements for initial certification and recertification
according to the procedures specified in paragraphs (a), (b), and (c)
of this section. The owner or operator shall operate the redundant
backup continuous emission monitoring system during all periods of unit
operation, except for periods of calibration, quality assurance,
maintenance, or repair. The owner or operator shall perform upon the
redundant backup continuous emission monitoring system all quality
assurance and quality control procedures specified in appendix B to
this part, except that the daily assessments in section 2.1 of appendix
B to this part are optional for days on which the redundant backup
monitoring system is not used to report emission data under this part.
For any day on which a redundant backup monitoring system is used to
report emission data, the system must meet all of the applicable daily
assessment criteria in appendix B to this part.
(2) Non-redundant backups. The owner or operator of an optional
non-redundant backup continuous emission monitoring system shall comply
with all of the following requirements for initial certification,
quality assurance, recertification, and data reporting:
(i) For a non-redundant backup gas monitoring system that has its
own separate probe, sample interface, and analyzer or for a non-
redundant backup flow monitor, all of the tests in paragraph (c) of
this section are required for initial certification of the system,
except for the 7-day calibration error test.
(ii) For a non-redundant backup gas monitoring system consisting of
one or more like-kind replacement analyzers that use the same probe and
sample interface as a primary monitoring system, no initial
certification of the non-redundant backup monitoring system is
required. Note that a non-redundant backup analyzer, connected to the
same probe and interface as a primary analyzer in order to satisfy the
dual span requirements of section
[[Page 28129]]
2.1.1.4 or 2.1.2.4 of appendix A to this part, shall be considered a
like-kind, non-redundant backup analyzer.
(iii) Each non-redundant backup monitoring system shall comply with
the daily and quarterly quality assurance and quality control
requirements in appendix B to this part for each day and quarter that
the non-redundant backup monitoring system is used to report data,
except that the requirements for when a linearity test must be
performed are superseded by the requirements of this section. The owner
or operator shall ensure that each non-redundant backup continuous
emission monitoring system passes a linearity check (for pollutant
concentration and diluent gas monitors) or a calibration error test
(for flow monitors) prior to each use for recording and reporting
emissions. For a non-redundant backup NOX-diluent or
SO2-diluent monitoring system consisting of a primary
pollutant analyzer and a like-kind replacement diluent analyzer (or
vice-versa), provided that the primary analyzer is operating and is not
out-of-control with respect to any of its quality assurance
requirements, only the like-kind replacement analyzer must pass a
linearity check before the system is used for data reporting. When a
non-redundant backup monitoring system is brought into service prior to
conducting the linearity test, a probationary calibration error test
(as described in paragraph (b)(3)(ii) of this section), which will
begin a period of conditionally valid data, may be performed in order
to allow the use of data retrospectively, as follows. Conditionally
valid data from the CEMS are validated back to the hour of completion
of the probationary calibration error test if the following conditions
are met: if no adjustments are made to the monitor other than those
specified in section 2.1.3 of appendix B to this part between the
probationary calibration error test and the successful completion of
the linearity test, and if the linearity test is passed within 168 unit
operating hours of the probationary calibration error test. However, if
the linearity test is either failed, aborted due to a problem with the
CEMS, or not completed as required, then all of the conditionally valid
data are invalidated back to the hour of the probationary calibration
error test, and data from the CEMS remain invalid until the hour of
completion of a successful linearity test.
(iv) When data are reported from a non-redundant backup monitoring
system, the appropriate bias adjustment factor (BAF) shall be
determined as follows:
(A) Apply the BAF from the most recent RATA of the non-redundant
backup system (even if that RATA was done more than 12 months
previously); or
(B) If no RATA results are available for the non-redundant backup
system (e.g., for a non-redundant backup gas monitoring system that
uses the same probe and sample interface as the primary monitoring
system), apply the primary monitoring system BAF.
(v) A non-redundant backup system may not be used for reporting
data from a particular affected unit or common stack for more than 720
hours in any one calendar year, unless the monitoring system passes a
RATA at that same unit or stack.
(vi) For each non-redundant backup gas monitoring system that has
its own separate probe, sample interface, and analyzer and for each
non-redundant backup flow monitor, no more than eight successive
calendar quarters shall elapse following the quarter in which the last
RATA of the monitoring system was done at a particular unit or stack,
without performing a subsequent RATA. Otherwise, the monitoring system
may not be used to report data from that unit or stack until the hour
of completion of a successful RATA at that location.
* * * * *
(g) Initial certification and recertification procedures for
excepted monitoring systems under appendices D and E. The owner or
operator of a gas-fired unit, oil-fired unit, or diesel-fired unit
using the optional protocol under appendix D or E to this part shall
ensure that an excepted monitoring system under appendix D or E to this
part meets the applicable general operating requirements of Sec. 75.10,
the applicable requirements of appendices D and E to this part, and the
initial certification or recertification requirements of this
paragraph.
(1) Initial certification and recertification testing. The owner or
operator shall use the following procedures for initial certification
and recertification of an excepted monitoring system under appendix D
or E to this part.
(i) When the optional SO2 mass emissions estimation
procedure in appendix D to this part or the optional NOX
emissions estimation protocol in appendix E to this part is used, the
owner or operator shall provide data from a flowmeter accuracy test (or
shall provide a statement of calibration if the flowmeter meets the
accuracy standard by design) for each fuel flowmeter, according to the
appropriate calibration procedures using one of the following standard
methods: ASME MFC-3M-1989 with September 1990 Errata, ``Measurement of
Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi''; ASME MFC-4M-
1986 (Reaffirmed 1990) ``Measurement of Gas Flow by Turbine Meters'';
ASME MFC-5M-1985, ``Measurement of Liquid Flow in Closed Conduits Using
Transit-Time Ultrasonic Flowmeters''; ASME MFC-6M-1987 with June 1987
Errata, ``Measurement of Fluid Flow in Pipes Using Vortex Flow
Meters''; ASME MFC-7M-1987 (Reaffirmed 1992), ``Measurement of Gas Flow
by Means of Critical Flow Venturi Nozzles''; ASME MFC-9M-1988 with
December 1989 Errata, ``Measurement of Liquid Flow in Closed Conduits
by Weighing Method''; ISO 8316: 1987(E) ``Measurement of Liquid Flow in
Closed Conduits--Method by Collection of the Liquid in a Volumetric
Tank''; Section 8, Calibration from American Gas Association
Transmission Measurement Committee Report No. 7: Measurement of Gas by
Turbine Meters (1985 Edition); American Gas Association Report No. 3:
Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids
Part 1: General Equations and Uncertainty Guidelines (October 1990
Edition), Part 2: Specification and Installation Requirements (February
1991 Edition), and Part 3: Natural Gas Applications (August 1992
Edition), excluding the modified calculation procedures of Part 3; or
American Petroleum Institute (API) Section 2, ``Conventional Pipe
Provers,'' from Chapter 4 of the Manual of Petroleum Measurement
Standards, October 1988 (Reaffirmed 1993), as required by appendices D
and E to this part (all methods incorporated by reference under
Sec. 75.6).
* * * * *
(2) Initial certification and recertification testing notification.
The designated representative shall provide initial certification
testing notification and periodic retesting notification for an
excepted monitoring system under appendix E to this part as specified
in Sec. 75.61. The designated representative shall submit
recertification testing notification, as specified in Sec. 75.61, for
quality assurance related NOX emission rate testing under
section 2.3 of appendix E to this part for an excepted monitoring
system under appendix E to this part. Initial certification testing
notification or periodic retesting notification is not required for
testing of a fuel flowmeter or for testing of an excepted monitoring
system under appendix D to this part.
* * * * *
[[Page 28130]]
(4) Initial certification or recertification application. The
designated representative shall submit an initial certification or
recertification application in accordance with Secs. 75.60 and 75.63.
(5) Provisional approval of initial certification and
recertification applications. Upon the successful completion of the
required initial certification or recertification procedures for each
excepted monitoring system under appendix D or E to this part, each
excepted monitoring system under appendix D or E to this part shall be
deemed provisionally certified for use under the Acid Rain Program
during the period for the Administrator's review. The provisions for
the initial certification or recertification application formal
approval process in paragraph (a)(4) of this section shall apply,
except that ``continuous emission or opacity monitoring system'' shall
be replaced with ``excepted monitoring system'' and except that ``shall
follow the procedures for loss of initial certification in paragraph
(a)(5)'' or ``shall follow the procedures of paragraph (b)(5)'' shall
be replaced with ``shall follow the procedures for loss of
certification in paragraph (g)(7)''. Data measured and recorded by a
provisionally certified excepted monitoring system under appendix D or
E to this part will be considered quality assured data from the date
and time of completion of the last initial certification or
recertification test, provided that the Administrator does not revoke
the provisional certification by issuing a notice of disapproval in
accordance with the provisions in paragraph (a)(4) or (b)(5) of this
section.
(6) Recertification requirements. Recertification of an excepted
monitoring system under appendix D or E to this part is required for
any modification to the system or change in operation that could
significantly affect the ability of the system to accurately account
for emissions and for which the Administrator determines that an
accuracy test of the fuel flowmeter or a retest under appendix E to
this part to re-establish the NOX correlation curve is
required. Examples of such changes or modifications include fuel
flowmeter replacement, changes in unit configuration, or exceedance of
operating parameters.
(7) Procedures for loss of certification or recertification for
excepted monitoring systems under appendices D and E to this part. In
the event that a certification or recertification application is
disapproved for an excepted monitoring system, data from the monitoring
system are invalidated, and the applicable missing data procedures in
section 2.4 of appendix D or section 2.5 of appendix E to this part
shall be used from the date and hour of receipt of such notice back to
the hour of the provisional certification. Data from the excepted
monitoring system remain invalid until all required tests are repeated
and the excepted monitoring system is again provisionally certified.
The owner or operator shall repeat all certification or recertification
tests or other requirements, as indicated in the Administrator's notice
of disapproval, no later than 30 unit operating days after the date of
issuance of the notice of disapproval. The designated representative
shall submit a notification of the certification or recertification
retest dates if required under paragraph (g)(2) of this section and
shall submit a new certification or recertification application
according to the procedures in paragraph (g)(4) of this section.
(h) Initial certification and recertification procedures for low
mass emission units using the excepted methodologies under Sec. 75.19.
The owner or operator of a gas-fired, oil-fired, or diesel-fired unit
using the optional low mass emissions excepted methodologies under
Sec. 75.19 shall meet the applicable general operating requirements of
Sec. 75.10, the applicable requirements of Sec. 75.19, and the
applicable certification requirements of this paragraph (h).
(1) Monitoring plan. The designated representative shall submit a
monitoring plan in accordance with Secs. 75.53 and 75.62.
(2) Certification application. The designated representative shall
submit a certification application in accordance with
Sec. 75.63(a)(1)(iii).
(3) Approval of certification applications. Upon submission of the
required certification application for approval to use the low mass
emissions excepted methodology under Sec. 75.19, the excepted
methodology shall be deemed provisionally certified for use under the
Acid Rain Program during the period for the Administrator's review. The
provisions for the certification application formal approval process in
the introductory text of paragraph (a)(4) and in paragraphs (a)(4)(i),
(ii), and (iv) of this section shall apply, except that ``continuous
emission or opacity monitoring system'' shall be replaced with
``excepted methodology.''
(4) Disapproval of certification applications. If the Administrator
determines that the certification application does not demonstrate that
the unit meets the requirements of Secs. 75.19(a) and (b), the
Administrator shall issue a written notice of disapproval of the
certification application within 120 days of receipt. By issuing the
notice of disapproval, the provisional certification is invalidated by
the Administrator, and the data recorded under the excepted methodology
shall not be considered valid. The owner or operator shall follow the
procedures for loss of certification:
(i) The owner or operator shall substitute the following values, as
applicable, for each hour of unit operation during the period of
invalid data specified in paragraph (a)(4)(iii) of this section or in
Secs. 75.21(e) (introductory paragraph) and 75.21(e)(1): the maximum
potential concentration of SO2, as defined in section 2.1 of
appendix A to this part to report SO2 concentration; the
maximum potential NOX emission rate, as defined in Sec. 72.2
of this chapter to report NOX emissions; the maximum
potential flow rate, as defined in section 2.1 of appendix A to this
part to report volumetric flow; or the maximum CO2
concentration used to determine the maximum potential concentration of
SO2 in section 2.1.1.1 of appendix A to this part to report
CO2 concentration data until such time, date, and hour as a
continuous emission monitoring system or excepted monitoring system,
where applicable, is installed and provisionally certified;
(ii) The designated representative shall submit a notification of
certification test dates, as specified in Sec. 75.61(a)(1)(ii), and a
new certification application according to the procedures in paragraph
(a)(2) of this section; and
(iii) The owner or operator shall install and provisionally certify
continuous emission monitoring systems or excepted monitoring systems,
where applicable, no later than 180 unit operating days after the date
of issuance of the notice of disapproval.
(i) Initial certification and recertification procedures for
excepted flow monitoring systems under appendix I. The owner or
operator of a gas-fired unit, oil-fired unit, or diesel-fired unit
using the optional protocol under appendix I to this part shall ensure
that an excepted flow monitoring system under appendix I to this part
meets the applicable general operating requirements of Sec. 75.10, the
applicable requirements of appendix I to this part, and the initial
certification and recertification requirements of this paragraph.
(1) Initial certification and recertification testing. The owner or
operator shall, where applicable, use the
[[Page 28131]]
following procedures for certification and recertification of an
excepted flow monitoring system under appendix I to this part.
(i) For an excepted flow monitoring system under appendix I to this
part where each component is tested separately, perform the following
tests on each O2 or CO2 component monitor:
(A) 7-day calibration error test;
(B) Linearity check;
(C) Cycle time test;
(D) Relative accuracy test audit using Test Method 3A from appendix
A to part 60 of this chapter; and
(E) Bias test.
(ii) For an excepted flow monitoring system under appendix I to
this part where each component is tested separately, meet the
certification procedures under paragraph (g)(1)(i) of this section and
the recertification procedures under paragraph (g)(6) of this section
on each fuel flowmeter component using the standards specified, or meet
the testing procedure under section 2.1.5.2 of appendix D to this part.
(iii) For an excepted flow monitoring system under appendix I to
this part that is tested as an entire system, perform the following
tests:
(A) 7-day calibration error test on the O2 or
CO2 monitor,
(B) Linearity check on the O2 or CO2 monitor,
(C) Cycle time test on the O2 or CO2 monitor,
(D) Relative accuracy test audit on the entire excepted flow
monitoring system under appendix I to this part, using Test Method 2
(or its allowable alternatives) from appendix A to part 60 of this
chapter, and
(E) Bias test on the entire excepted flow monitoring system under
appendix I to this part.
(iv) For the automated data acquisition and handling system used as
part of an excepted flow monitoring system under appendix I to this
part, the owner or operator shall perform tests designed to verify:
(A) The proper computation of hourly averages for volumetric flow
rates, heat input, and pollutant mass emissions; and
(B) The proper computation and application of the missing data
substitution procedures for volumetric flow in subpart D of this part.
(2) Initial certification and recertification testing notification.
The designated representative shall provide initial certification and
recertification testing notification for an excepted flow monitoring
system under appendix I to this part, as specified in Sec. 75.61, for
any relative accuracy test audit.
(3) Monitoring plan. The designated representative shall submit a
monitoring plan in accordance with Secs. 75.53 and 75.62. For a unit
that previously had a flow monitoring system or an excepted monitoring
system under appendix D to this part and later submits a revised
monitoring plan for an excepted flow monitoring system under appendix I
to this part, the designated representative shall submit the revised
monitoring plan no later than 45 days prior to the first day of
certification testing.
(4) Certification or recertification application. The designated
representative shall submit an initial certification or recertification
application in accordance with Secs. 75.60 and 75.63.
(5) Approval of initial certification and recertification
applications. Upon successful completion of the required initial
certification or recertification procedures for each excepted
monitoring system under appendix I to this part, each excepted
monitoring system under appendix I to this part shall be deemed
provisionally certified for use under the Acid Rain Program during the
period for the Administrator's review. The provisions for the initial
certification (or recertification) application formal approval process
in paragraph (a)(4) of this section shall apply, except that
``continuous emission or opacity monitoring system'' shall be replaced
with ``excepted monitoring system'' and except that ``shall follow the
procedures for loss of initial certification in paragraph (a)(5)'' or
``shall follow the procedures of paragraph (b)(5)'' shall be replaced
with ``shall follow the procedures for loss of certification in
paragraph (i)(7)''. Data measured and recorded by a provisionally
certified excepted monitoring system under appendix I to this part will
be considered quality assured data from the date and time of completion
of the final certification test, provided that the Administrator does
not revoke the provisional certification by issuing a notice of
disapproval within 120 days of receipt of the complete initial
certification or recertification application in accordance with the
provisions in paragraph (a)(4) of this section.
(6) Recertification requirements. A recertification of an excepted
flow monitoring system under appendix I to this part is required for
any modification to the equipment used in the appendix I excepted flow
monitoring system that would require recertification under paragraph
(b) or (g) of this section.
(7) Procedures for loss of certification for excepted monitoring
systems under appendix I to this part. In the event that a
certification or recertification application is disapproved for an
excepted monitoring system under appendix I to this part, data from the
monitoring system are invalidated, and the applicable missing data
procedures in section 4 of appendix I to this part shall be used from
the date and hour of receipt of such notice back to the hour of the
provisional certification. Data from the excepted monitoring system
remain invalid until all required tests are repeated and the excepted
monitoring system is again provisionally certified. The owner or
operator shall repeat all certification or recertification tests or
other requirements, as indicated in the Administrator's notice of
disapproval, no later than 30 unit operating days after the date of
issuance of the notice of disapproval. The designated representative
shall submit a notification of the certification or recertification
retest dates, if required under paragraph (i)(2) of this section, and
shall submit a new certification or recertification application
according to the procedures in paragraph (i)(4) of this section.
20. Section 75.21 is amended by:
a. Revising paragraphs (a)(2), (a)(4), (a)(5), (a)(6) and (e);
b. Redesignating existing paragraphs (a)(7) and (a)(8) as
paragraphs (a)(9) and (a)(10), respectively; revising newly designated
paragraph (a)(9); and
c. Adding new paragraphs (a)(7), (a)(8), and (f), to read as
follows:
Sec. 75.21 Quality assurance and quality control requirements.
(a) * * *
(2) The owner or operator shall ensure that each non-redundant
backup continuous emission monitoring system meets the quality
assurance requirements of Sec. 75.20(d) for each day and quarter that
the system is used to report data.
* * * * *
(4) When a unit combusts only natural gas or gaseous fuel with a
total sulfur content no greater than the total sulfur content of
natural gas and SO2 emissions are determined in accordance
with Sec. 75.11(e)(3), the owner or operator of a unit with an
SO2 continuous emission monitoring system is not required to
perform the daily or quarterly assessments of the SO2
monitoring system under appendix B to this part on any day or in any
calendar quarter in which only natural gas (or gaseous fuel with a
total sulfur content no greater than the total sulfur content
[[Page 28132]]
of natural gas) is combusted in the unit. Notwithstanding, the results
of any daily calibration error test and linearity test of the
SO2 monitoring system performed while the unit is combusting
only natural gas (or gaseous fuel with a total sulfur content no
greater than the total sulfur content of natural gas) shall be
considered valid. If any such test is failed, the SO2
monitoring system shall be considered to be out-of-control. The length
of the out-of-control period shall be determined in accordance with the
applicable procedures in section 2.1.4 or 2.2.3 of appendix B to this
part.
(5) For a unit with an SO2 continuous monitoring system,
in which natural gas (or gaseous fuel with a total sulfur content no
greater than the total sulfur content of natural gas) is sometimes
burned as a primary and/or backup fuel and in which higher-sulfur
fuel(s) such as oil or coal are, at other times, burned as primary or
backup fuel(s), the owner shall perform the relative accuracy test
audits of the SO2 monitoring system (as required by section
6.5 of appendix A to this part and section 2.3.1 of appendix B to this
part) only when the higher-sulfur fuel is combusted in the unit and
shall not perform SO2 relative accuracy test audits when
gaseous fuel is the only fuel being combusted.
(6) If the designated representative certifies that a unit with an
SO2 monitoring system burns only fuel(s) with a total sulfur
content no greater than the total sulfur content of natural gas, the
SO2 monitoring system is exempted from the relative accuracy
test audit requirements in appendices A and B to this part. For the
purposes of this part, a fuel having a total sulfur content no greater
than 0.05 percent sulfur by weight shall be deemed to qualify as a
``fuel with a total sulfur content no greater than the total sulfur
content of natural gas.''
(7) If the designated representative certifies that a particular
unit with an SO2 monitoring system combusts fuel(s) with a
total sulfur content greater than the total sulfur content of natural
gas (i.e., >0.05 percent sulfur by weight) only as emergency backup
fuel(s) or for short-term testing, the SO2 monitoring system
shall be conditionally exempted from the RATA requirements of
appendices A and B to this part, provided that the unit combusts the
higher-sulfur fuel(s) for no more than 480 hours per calendar year. If,
in a particular calendar year, the higher-sulfur fuel usage exceeds 480
hours, a RATA of the SO2 monitor shall be performed (while
combusting the higher-sulfur fuel) either by the end of the calendar
quarter in which the exceedance occurs or by the end of a 720 unit
operating hour grace period following the quarter in which the
exceedance occurs (see SO2 RATA provisions in section 2.3.3
of appendix B to this part for further discussion of the grace period).
(8) On and after January 1, 2000, the quality assurance provisions
of Secs. 75.11(e)(3)(i) through 75.11(e)(3)(iv) shall apply (except
that the term ``gaseous fuel'' shall be replaced with ``fuel'') to all
units with SO2 monitoring systems during hours in which only
fuel having a total sulfur content no greater than the total sulfur
content of natural gas (i.e., 0.05 percent sulfur by weight)
is combusted in the unit, except for units that use such fuel only for
unit startup.
(9) Provided that a unit with an SO2 monitoring system
is not exempted under paragraph (a)(6) or (a)(7) of this section from
the SO2 RATA requirements of this part, any calendar quarter
during which a unit combusts only fuel(s) with a total sulfur content
no greater than the total sulfur content of natural gas (i.e.
0.05 percent sulfur by weight) shall be excluded in
determining the quarter in which the next relative accuracy test audit
must be performed for the SO2 monitoring system. However, no
more than eight successive calendar quarters shall elapse after a
relative accuracy test audit of an SO2 monitoring system,
without a subsequent relative accuracy test audit having been
performed. The owner or operator shall ensure that a relative accuracy
test audit is performed either by the end of the eighth successive
elapsed calendar quarter since the last RATA or in the next calendar
quarter in which a fuel with a total sulfur content greater than the
total sulfur content of natural gas is burned in the unit.
* * * * *
(e) Consequences of audits. The owner or operator shall invalidate
data from a continuous emission monitoring system or continuous opacity
monitoring system upon failure of an audit under paragraph (a)(4)(iv)
of Sec. 75.20, an audit under appendix B to this part, or any other
audit, beginning with the unit operating hour of completion of a failed
audit as determined by the Administrator. The owner or operator shall
not use invalidated data for reporting either emissions or heat input,
nor for calculating monitor data availability.
(1) Audit decertification. Whenever both an audit of a continuous
emission or opacity monitoring system (or component thereof, including
the data acquisition and handling system), or an audit of any excepted
monitoring system under appendix D, E, or I to this part, or of any
alternative monitoring system under subpart E of this part, and a
review of the initial certification application or of a recertification
application, reveal that any system or component should not have been
certified or recertified because it did not meet a particular
performance specification or other requirement of this part, both at
the time of the initial certification or recertification application
submission and at the time of the audit, the Administrator will issue a
notice of disapproval of the certification status of such system or
component. For the purposes of this paragraph, an audit shall be either
a field audit of the facility or an audit of any information submitted
to EPA or the State agency regarding the facility. By issuing the
notice of disapproval, the certification status is revoked,
prospectively, by the Administrator. The data measured and recorded by
each system shall not be considered valid quality-assured data from the
date of issuance of the notification of the revoked certification
status until the date and time that the owner or operator completes
subsequently approved initial certification or recertification tests.
The owner or operator shall follow the procedures in Sec. 75.20(a)(5)
for initial certification or Sec. 75.20(b)(5) for recertification to
replace, prospectively, all of the invalid, non-quality-assured data
for each disapproved system.
(2) Out-of-control period. Whenever a continuous emission
monitoring system or continuous opacity monitoring system fails a
quality assurance audit, an audit under Sec. 75.20(a)(4)(iv), or
another audit, the system is out-of-control. The owner or operator
shall follow the procedures for out-of-control periods in Sec. 75.24.
(f) Excepted flow monitoring systems under appendix I. The owner or
operator of an affected unit shall operate, calibrate, and maintain
each excepted flow monitoring system under appendix I to this part used
under the Acid Rain Program according to the quality assurance and
quality control procedures in appendices B and I to this part.
21. Section 75.22 is amended by revising paragraphs (a)(2), (a)(4),
and (c)(1) introductory text to read as follows:
Sec. 75.22 Reference test methods.
(a) * * *
(2) Method 2 or its allowable alternatives, except for 2B and 2E,
are the reference methods for determination of volumetric flow.
* * * * *
[[Page 28133]]
(4) Method 4 (either the standard procedure described in section 2
of the method or the moisture approximation procedure described in
section 3 of the method) shall be used to correct pollutant
concentrations from a dry basis to a wet basis (or from a wet basis to
a dry basis) and shall be used when relative accuracy test audits of
continuous moisture monitoring systems are conducted. For the purpose
of determining the stack gas molecular weight, however, the alternative
techniques for approximating the stack gas moisture content described
in section 1.2 of Method 4 may be used in lieu of the procedures in
sections 2 and 3 of the method.
* * * * *
(c) * * *
(1) Instrumental EPA Reference Methods 3A, 6C, 7E, and 20 shall be
conducted using calibration gases as defined in section 5 of appendix A
to this part. Otherwise, performance tests shall be conducted and data
reduced in accordance with the test methods and procedures of this part
unless the Administrator:
* * * * *
22. Section 75.24 is amended by revising paragraph (d) to read as
follows:
Sec. 75.24 Out-of-control periods.
* * * * *
(d) When the bias test indicates that an SO2 monitor,
volumetric flow monitor, or NOX continuous emission
monitoring system is biased low (i.e., the arithmetic mean of the
differences between the reference method value and the monitor or
monitoring system measurements in a relative accuracy test audit exceed
the bias statistic in section 7 of appendix A to this part), the owner
or operator shall adjust the monitor or continuous emission monitoring
system to eliminate the cause of bias such that it passes the bias test
or calculate and use the bias adjustment factor as specified in section
2.3.4 of appendix B to this part and in accordance with Sec. 75.7.
* * * * *
23. Section 75.30 is amended by revising paragraphs (a)(2) and (d)
to read as follows:
Sec. 75.30 General provisions.
(a) * * *
(2) A valid quality assured hour of flow data (in scfh) has not
been measured and recorded for an affected unit from a certified flow
monitor, or from a certified excepted flow monitoring system under
appendix I to this part, or by an approved alternative monitoring
system under subpart E of this part; or
* * * * *
(d) The owner or operator shall comply with the applicable
provisions of this paragraph during hours in which a unit with an
SO2 continuous emission monitoring system combusts only
natural gas or gaseous fuel with a total sulfur content no greater than
the total sulfur content of natural gas.
(1) Whenever a unit with an SO2 continuous emission
monitoring system combusts only pipeline natural gas and the owner or
operator is using the procedures in section 7 of appendix F to this
part to determine SO2 mass emissions pursuant to
Sec. 75.11(e)(1), the owner or operator shall, for purposes of
reporting heat input data under Sec. 75.54(b)(5) or Sec. 75.57(b)(5),
as applicable, and for the calculation of SO2 mass emissions
using Equation F-23 in section 7 of appendix F to this part, substitute
for missing data from a flow monitoring system, CO2-diluent
monitor or O2-diluent monitor using the missing data
substitution procedures in Sec. 75.36.
(2) Whenever a unit with an SO2 continuous emission
monitoring system combusts gaseous fuel with a total sulfur content no
greater than the total sulfur content of natural gas (i.e.,
20 gr/100 scf) and the owner or operator uses the gas
sampling and analysis and fuel flow procedures in appendix D to this
part to determine SO2 mass emissions pursuant to
Sec. 75.11(e)(2), the owner or operator shall substitute for missing
total sulfur content, gross calorific value, and fuel flowmeter data
using the missing data procedures in appendix D to this part and shall
also, for purposes of reporting heat input data under Sec. 75.54(b)(5)
or Sec. 75.57(b)(5), substitute for missing data from a flow monitoring
system, CO2-diluent monitor, or O2-diluent
monitor using the missing data substitution procedures in Sec. 75.36.
(3) The owner or operator of a unit with an SO2
monitoring system shall not include hours, when the unit combusts only
natural gas (or a gaseous fuel with total sulfur content no greater
than the total sulfur content of natural gas), in the SO2
data availability calculations in Sec. 75.32 or in the calculations of
substitute SO2 data using the procedures of either
Sec. 75.31 or Sec. 75.33, when SO2 emissions are determined
in accordance with Sec. 75.11(e)(1) or (e)(2). For the purpose of the
missing data and availability procedures for SO2 pollutant
concentration monitors in Secs. 75.31 and 75.33 only, all hours during
which the unit combusts only natural gas, or gaseous fuel with a total
sulfur content no greater than the total sulfur content of natural gas,
shall be excluded from the definition of ``monitor operating hour,''
``quality assured monitor operating hour,'' ``unit operating hour,''
and ``unit operating day,'' when SO2 emissions are
determined in accordance with Sec. 75.11(e)(1) or (e)(2).
(4) During all hours in which a unit with an SO2
continuous emission monitoring system combusts only natural gas (or
gaseous fuel with a total sulfur content no greater than the total
sulfur content of natural gas) and the owner or operator uses the
SO2 monitoring system to determine SO2 mass
emissions pursuant to Sec. 75.11(e)(3), the owner or operator shall
determine the percent monitor data availability for SO2 in
accordance with Sec. 75.32 and shall use the standard SO2
missing data procedures of Sec. 75.33.
24. Section 75.32 is amended by revising the last sentence in
paragraph (a)(3) to read as follows:
Sec. 75.32 Determination of monitor data availability for standard
missing data procedures.
(a) * * *
(3) * * * The owner or operator of a unit with an SO2
monitoring system shall, when SO2 emissions are determined
in accordance with Sec. 75.11(e)(1) or (e)(2), exclude hours in which a
unit combusts only natural gas (or gaseous fuel with a total sulfur
content no greater than the total sulfur content of natural gas) from
calculations of percent monitor data availability for SO2
pollutant concentration monitors, as provided in Sec. 75.30(d).
* * * * *
25. Section 75.33 is amended by adding a new paragraph (d) to read
as follows:
Sec. 75.33 Standard missing data procedures.
* * * * *
(d) On and after January 1, 2000, failure to maintain a monitor
data availability, as calculated pursuant to Sec. 75.32, of at least
80.0 percent for SO2, NOX, flow rate, or
CO2 shall be considered a violation of the primary
measurement requirement of Sec. 75.10(a). This paragraph (d) shall not
apply: if, for a particular unit or stack for which the monitor data
availability drops below 80.0 percent, less than 3,000 unit operating
hours have been accumulated in the previous 12 calendar quarters; or if
a data availability percentage of less than 80.0 percent results from a
sudden and reasonably unforeseeable event beyond the control of the
owner or operator, such as catastrophic monitor failure or destruction
of monitoring equipment by fire, flood, etc. If such
[[Page 28134]]
circumstances have caused (or are projected to cause) the monitor data
availability to drop below 80.0 percent, the owner or operator shall
notify the Administrator, in writing, within 7 days of the event(s).
Notification, in writing, shall also be provided to the EPA Regional
Office and to the appropriate State agency. The written notifications
shall fully explain the circumstances that have caused (or may cause)
the low monitor data availability and shall contain an action plan and
a projected time schedule for correction of the problem. Failures that
are caused in part by poor maintenance or careless operation shall not,
for the purposes of this paragraph, be considered reasonably
unforeseeable events beyond the control of the owner or operator.
26. Section 75.34 is amended by revising paragraph (a)(3) to read
as follows:
Sec. 75.34 Units with add-on emission controls.
(a) * * *
(3) The designated representative may petition the Administrator
under Sec. 75.66 for approval of site-specific parametric monitoring
procedure(s) for calculating substitute data for missing SO2
pollutant concentration and NOX emission rate data in
accordance with the requirements of paragraphs (b) and (c) of this
section and appendix C to this part. The owner or operator shall record
the data required in appendix C to this part, pursuant to Sec. 75.55(b)
or Sec. 75.58(b), as applicable.
* * * * *
27. Section 75.35 is amended by revising paragraphs (a) and (c) to
read as follows:
Sec. 75.35 Missing data procedures for CO2 data.
(a) On and after January 1, 2000, the owner or operator of a unit
with a CO2 continuous emission monitoring system (or an
O2-diluent monitor that is used to determine CO2
concentration in accordance with appendix F to this part) shall
substitute for missing CO2 concentration data using the
procedures of this section. Prior to January 1, 2000, the owner or
operator may substitute for missing CO2 or O2
concentration data using the procedures of this section.
* * * * *
(c) Upon completion of the first 720 quality assured monitor
operating hours following initial certification of the CO2
continuous emission monitoring system, the owner or operator shall
provide substitute data for CO2 concentration or
CO2 mass emissions required under this subpart, including
CO2 data calculated from O2 measurements using
the procedures in appendix F to this part, in accordance with the
procedures in Sec. 75.33(b), except that the terms ``SO2
concentration'' and ``SO2 pollutant concentration monitor''
shall be replaced, respectively, with ``CO2 concentration''
and ``CO2 pollutant concentration monitor.''
28. Section 75.36 is amended by revising paragraphs (a), (b), and
(c) to read as follows:
Sec. 75.36 Missing data procedures for heat input.
(a) When hourly heat input is determined using a flow monitoring
system and a diluent gas (O2 or CO2) monitor,
substitute data must be provided to calculate the heat input whenever
quality assured data are unavailable from the flow monitor, the diluent
gas monitor, or both. When flow rate data are unavailable, substitute
flow rate data for the heat input calculation shall be provided
according to Sec. 75.31 or Sec. 75.33, as applicable. On and after
January 1, 2000, when diluent gas data are unavailable, the owner or
operator shall provide substitute O2 or CO2 data
for the heat input calculations in accordance with this section. Prior
to January 1, 2000, the owner or operator may substitute for missing
CO2 or O2 concentration data using the procedures
in this section.
(b) During the first 720 quality assured monitor operating hours
following initial certification (i.e., following the date and time of
completion of successful certification tests of the CO2 or
O2 monitor), the owner or operator shall provide substitute
CO2 or O2 data, as applicable, for the
calculation of heat input (under section 5.2 of appendix F to this
part) according to Sec. 75.31(b).
(c) Upon completion of the first 720 quality assured monitor
operating hours following initial certification of the CO2
(or O2) monitor, the owner or operator shall provide
substitute data for CO2 or O2 concentration to
calculate heat input according to the procedures in Sec. 75.33(b),
except that the term ``SO2 concentration'' shall be replaced
with ``CO2 concentration'' or ``O2
concentration'' (as applicable) and the term ``SO2 pollutant
concentration monitor'' shall be replaced with ``CO2-diluent
monitor'' or ``O2-diluent monitor'' (as applicable).
* * * * *
29. Section 75.37 is added to subpart D to read as follows:
Sec. 75.37 Missing data procedures for moisture.
The owner or operator shall substitute for missing moisture data
(beginning no later than January 1, 2000 or the date and hour on which
the unit or stack is required to begin reporting under Sec. 75.64,
whichever date is earlier) as follows:
(a) Where no prior quality assured percent moisture data exist,
substitute 0.0 percent moisture for each unit operating hour;
(b) For the first 720 quality assured monitor operating hours,
substitute for each hour of the missing data period the average of the
percent moisture values obtained during the hour before and the hour
after the missing data period;
(c) Once 720 quality assured monitor operating hours have been
obtained, begin calculating the percent data availability of the
moisture monitoring system, in accordance with Sec. 75.32;
(d) When the percent data availability, as of the last hour in the
missing data period, is 90.0 percent, substitute for each
hour of the missing data period the average of the percent moisture
values obtained during the hour before and the hour after the missing
data period;
(e) If the percent data availability of the moisture monitor is <
90.0 percent as of the last hour in the missing data period, substitute
0.0 percent moisture for each hour of the missing data period.
Subpart E--[Amended]
30. Section 75.48 is amended by revising paragraphs (a)(3)(ii) and
(a) (3)(iii) to read as follows:
Sec. 75.48 Petition for an alternative monitoring system.
(a) * * *
(3) * * *
(ii) Hourly test data for the alternative monitoring system at each
required operating level and fuel type. The fuel type, operating level
and gross unit load shall be recorded.
(iii) Hourly test data for the continuous emissions monitoring
system at each required operating level and fuel type. The fuel type,
operating level and gross unit load shall be recorded.
* * * * *
31. Section 75.50 is removed and reserved.
Sec. 75.50 [Removed and Reserved]
32. Section 75.51 is removed and reserved.
Sec. 75.51 [Removed and Reserved]
33. Section 75.52 is removed and reserved.
Sec. 75.52 [Removed and Reserved]
34. Section 75.53 is amended by revising paragraphs (a) and (b) and
adding paragraphs (e) through (f) to read as follows:
[[Page 28135]]
Sec. 75.53 Monitoring plan.
(a) General Provisions.
(1) Compliance dates. Beginning on January 1, 2000, the owner or
operator shall comply with the provisions in paragraphs (a), (b), (e)
and (f) of this section only. Before January 1, 2000, the owner or
operator shall comply with either paragraphs (a) through (d) or
paragraphs (a), (b), (c), and (f) of this section, except that the
owner or operator shall comply with provisions in paragraphs (e) and
(f) of this section only before January 1, 2000, when those provisions
support a regulatory option provided in another section of this part 75
and the regulatory option is exercised before January 1, 2000.
(2) The owner or operator of an affected unit shall prepare and
maintain a monitoring plan. Except as provided in paragraphs (d) (or
(f), as applicable) of this section, a monitoring plan shall contain
sufficient information on the continuous emission or opacity monitoring
systems, excepted methodology under Sec. 75.19, or excepted monitoring
systems under appendix D or E to this part and the use of data derived
from these systems to demonstrate that all unit SO2
emissions, NOX emissions, CO2 emissions, and
opacity are monitored and reported.
(b) Whenever the owner or operator makes a replacement,
modification, or change in the certified continuous emission monitoring
system, continuous opacity monitoring system, excepted methodology
under Sec. 75.19, excepted monitoring system under appendix D, E, or I
to this part, or alternative monitoring system under subpart E of this
part, including a change in the automated data acquisition and handling
system or in the flue gas handling system, that affects information
reported in the monitoring plan (e.g., a change to a serial number for
a component of a monitoring system), then the owner or operator shall
update the monitoring plan.
* * * * *
(e) Contents of the monitoring plan. Each monitoring plan shall
contain the information in paragraph (e)(1) of this section in
electronic format and the information in paragraph (e)(2) of this
section in hardcopy format.
(1) Electronic. (i) ORISPL numbers developed by the Department of
Energy and used in the National Allowance Database, for all affected
units involved in the monitoring plan, with the following information
for each unit:
(A) Short name;
(B) Classification of unit as one of the following: Phase I
(including substitution or compensating units), Phase II, new, or
nonaffected;
(C) Type of boiler (or boilers for a group of units using a common
stack);
(D) Type of fuel(s) fired by boiler, fuel type start and end date,
primary/secondary fuel indicator, and, if more than one fuel, the fuel
classification of the boiler;
(E) Type(s) of emission controls for SO2,
NOX, and particulates installed or to be installed,
including specifications of whether such controls are pre-combustion,
post-combustion, or integral to the combustion process; control
equipment code, installation date, and optimization date; control
equipment retirement date (if applicable); and, an indicator for
whether the controls are an original installation;
(F) Maximum hourly heat input capacity;
(G) Date of first commercial operation;
(H) Unit retirement date (if applicable);
(I) Maximum hourly gross load (in MW, rounded to the nearest MW, or
steam load in 1000 lb/hr, rounded to the nearest 100 lb/hr);
(J) Identification of all units using a common stack;
(K) Activation date for the stack/pipe;
(L) Retirement date of the stack/pipe (if applicable); and
(M) Indicator of whether the stack is a bypass stack.
(ii) For each unit and parameter required to be monitored,
identification of monitoring methodology information, consisting of
monitoring methodology, type of fuel associated with the methodology,
missing data approach for the methodology, methodology start date, and
methodology end date (if applicable).
(iii) The following information:
(A) Program(s) for which the EDR is submitted;
(B) Unit classification;
(C) Reporting frequency;
(D) Program participation date;
(E) State regulation code (if applicable); and
(F) State or local regulatory agency code.
(iv) Identification and description of each monitoring component
(including each monitor and its identifiable components, such as
analyzer and/or probe) in the continuous emission monitoring systems
(i.e., SO2 pollutant concentration monitor, flow monitor,
moisture monitor; NOX pollutant concentration monitor and
diluent gas monitor), the continuous opacity monitoring system, or
excepted monitoring system (i.e., fuel flowmeter, data acquisition and
handling system), including:
(A) Manufacturer, model number and serial number;
(B) Component/system identification code assigned by the utility to
each identifiable monitoring component (such as the analyzer and/or
probe). Each code shall use a three-digit format, unique to each
monitoring component and unique to each monitoring system;
(C) Designation of the component type or method of operation, such
as in situ pollutant concentration monitor or thermal flow monitor;
(D) Designation of the system as a primary, redundant backup, non-
redundant backup, like kind non-redundant backup, data backup, or
reference method backup system, as provided in Sec. 75.10(e);
(E) First and last dates the system reported data; and
(F) Status of the monitoring component.
(v) Identification and description of all major hardware and
software components of the automated data acquisition and handling
system, including:
(A) For hardware components, the manufacturer and model number; and
(B) For software components, identification of the provider and
model/version number.
(vi) Explicit formulas for each measured emission parameter, using
component/system identification codes for the primary system used to
measure the parameter to link continuous emission monitoring system or
excepted monitoring system observations with reported concentrations,
mass emissions, or emission rates, according to the conversions listed
in appendix D, E, or F to this part. Formulas for backup monitoring
systems are required only if different formulas for the same parameter
are used for the primary and backup monitoring systems (e.g., if the
primary system measures pollutant concentration on a different moisture
basis from the backup system). The formulas must contain all constants
and factors required to derive mass emissions or emission rates from
component/system code observations and an indication of whether the
formula is being added, corrected, deleted, or is unchanged. Each
emissions formula is identified with a unique three digit code. The
owner or operator of a low mass emissions unit for which the owner or
operator is using the optional low mass emissions excepted methodology
in Sec. 75.19(c) is not required to report such formulas.
(vii) Inside cross-sectional area (ft2) at flue exit
(for all units) and at flow monitoring location (for units with flow
monitors, only).
[[Page 28136]]
(viii) Stack height (ft) above ground level and stack base
elevation above sea level.
(ix) Flue identification number, as reported to the Energy
Information Administration (EIA).
(x) For each parameter monitored: scale, maximum potential
concentration (and method of calculation), maximum expected
concentration (if applicable) (and method of calculation), maximum
potential flow rate (and method of calculation), maximum potential
NOX emission rate, span value, full-scale range, daily
calibration units of measure, span effective date/hour, span
inactivation date/hour, indication of whether dual spans are required,
default high range value, flow rate span, and flow rate span value and
full scale value (in scfh) for each unit or stack using SO2,
NOX, CO2, O2, or flow component
monitors.
(xi) If the monitoring system or excepted methodology provides for
the use of a constant, assumed, or default value for a parameter under
specific circumstances, then include the following information for each
such value for each parameter:
(A) Identification of the parameter;
(B) Default, maximum, minimum, or constant value, and units of
measure for the value;
(C) Purpose of the value;
(D) Indicator of use during controlled/uncontrolled hours;
(E) Type of fuel;
(F) Source of the value;
(G) Value effective date and hour;
(H) Date and hour value is no longer effective (if applicable); and
(I) For units using the excepted methodology under Sec. 75.19, the
applicable SO2 emission factor.
(2) Hardcopy. (i) Information, including (as applicable)
identification of the test strategy; protocol for the relative accuracy
test audit; other relevant test information; calibration gas levels
(percent of span) for the calibration error test and linearity check;
calculations for determining maximum potential concentration, maximum
expected concentration (if applicable), maximum potential flow rate,
maximum potential NOX emission rate, and span; and
apportionment strategies under Secs. 75.13 through 75.17.
(ii) Description of site locations for each monitoring component in
the continuous emission or opacity monitoring systems, including
schematic diagrams and engineering drawings specified in paragraphs
(e)(2)(iv) and (e)(2)(v) of this section and any other documentation
that demonstrates each monitor location meets the appropriate siting
criteria.
(iii) A data flow diagram denoting the complete information
handling path from output signals of continuous emission monitoring
system components to final reports.
(iv) For units monitored by a continuous emission or opacity
monitoring system, a schematic diagram identifying entire gas handling
system from boiler to stack for all affected units, using
identification numbers for units, monitor components, and stacks
corresponding to the identification numbers provided in paragraphs
(e)(1)(i), (e)(1)(ii), (e)(1)(vi), and (e)(1)(vii) of this section. The
schematic diagram must depict stack height and the height of any
monitor locations. Comprehensive and/or separate schematic diagrams
shall be used to describe groups of units using a common stack.
(v) For units monitored by a continuous emission or opacity
monitoring system, stack and duct engineering diagrams showing the
dimensions and location of fans, turning vanes, air preheaters, monitor
components, probes, reference method sampling ports, and other
equipment that affects the monitoring system location, performance, or
quality control checks.
(f) Contents of monitoring plan for specific situations. The
following additional information shall be included in the monitoring
plan for the specific situations described:
(1) For each gas-fired unit or oil-fired unit for which the owner
or operator uses the optional protocol in appendix D to this part for
estimating heat input and/or SO2 mass emissions or in
appendix I to this part for estimating stack flow rate, or for each
gas-fired or oil-fired peaking unit for which the owner/operator uses
the optional protocol in appendix E to this part for estimating
NOX emission rate (using a fuel flowmeter), the designated
representative shall include the following additional information in
the monitoring plan:
(i) Electronic. (A) Parameter monitored;
(B) Type of fuel measured, maximum fuel flow rate, units of
measure, and basis of maximum fuel flow rate (i.e., upper range value
or unit maximum) for each fuel flowmeter;
(C) Test method used to check the accuracy of each fuel flowmeter;
(D) Submission status of the data; and
(E) Monitoring system identification code.
(ii) Hardcopy. (A) A schematic diagram identifying the relationship
between the unit, all fuel supply lines, the fuel flowmeter(s), and the
stack(s). The schematic diagram must depict the installation location
of each fuel flowmeter and the fuel sampling location(s). Comprehensive
and/or separate schematic diagrams shall be used to describe groups of
units using a common pipe.
(B) For units using the optional protocol for gaseous fuel in
appendix D to this part, historical fuel sampling information on the
sulfur content of the gaseous fuel according to section 2.3.3 of
appendix D to this part.
(2) For each gas-fired peaking unit and oil-fired peaking unit for
which the owner or operator uses the optional procedures in appendix E
to this part for estimating NOX emission rate, the
designated representative shall include in the monitoring plan:
(i) Electronic. Unit operating and capacity factor information
demonstrating that the unit qualifies as a peaking unit or gas-fired
unit, as defined in Sec. 72.2 of this chapter.
(ii) Hardcopy. (A) A protocol containing methods used to perform
the baseline or periodic NOX emission test; and
(B) Unit operating parameters related to NOX formation
by the unit.
(3) For each gas-fired unit and diesel-fired unit or unit with a
wet flue gas pollution control system for which the designated
representative claims an opacity monitoring exemption under Sec. 75.14,
the designated representative shall include in the hardcopy monitoring
plan the information specified under Sec. 75.14(b), (c), or (d),
demonstrating that the unit qualifies for the exemption.
(4) For each monitoring system recertification, maintenance, or
other event, the designated representative shall include the following
additional information in electronic format in the monitoring plan:
(i) Component/system identification code;
(ii) Event code or code for required test;
(iii) Event begin date and hour;
(iv) Conditional data period begin date and hour (if applicable);
(v) Date and hour that last test is successfully completed; and
(vi) Indicator of whether conditionally valid data were reported at
the end of the quarter.
35. Section 75.54 is amended by adding new paragraphs (g) and (h)
to read as follows:
Sec. 75.54 General recordkeeping provisions.
* * * * *
(g) Missing data records. The owner or operator shall record the
causes of any missing data periods and the actions
[[Page 28137]]
taken by the owner or operator to cure such causes.
(h) Compliance dates. On January 1, 2000, the provisions of this
section are no longer applicable. Before January 1, 2000, the owner or
operator shall comply with either this section or Sec. 75.57. Beginning
on January 1, 2000, the owner or operator shall comply with Sec. 75.57
only.
36. Section 75.55 is amended by adding a new paragraph (g) to read
as follows:
Sec. 75.55 General recordkeeping provisions for specific situations.
* * * * *
(g) Compliance dates. On January 1, 2000, the provisions of this
section are no longer applicable. Before January 1, 2000, the owner or
operator shall comply with either this section or Sec. 75.58. Beginning
on January 1, 2000, the owner or operator shall comply with Sec. 75.58
only.
37. Section 75.56 is amended by adding new paragraphs (a)(5)(vii)
and (e) to read as follows:
Sec. 75.56 Certification, quality assurance, and quality control
record provisions.
(a) * * *
(5) * * *
(vii) For flow monitors, the flow polynomial equation used to
linearize the flow monitor and the numerical values of the polynomial
coefficients of that equation.
* * * * *
(e) Compliance dates. On January 1, 2000, the provisions of this
section are no longer applicable. Before January 1, 2000, the owner or
operator shall comply with either this section or Sec. 75.59. Beginning
on January 1, 2000, the owner or operator shall comply with Sec. 75.59
only.
38. Section 75.57 is added to Subpart F to read as follows:
Sec. 75.57 General recordkeeping provisions.
(a) Recordkeeping requirements for affected sources. The owner or
operator of any affected source subject to the requirements of this
part shall maintain for each affected unit a file of all measurements,
data, reports, and other information required by this part at the
source in a form suitable for inspection for at least three (3) years
from the date of each record. Unless otherwise provided, throughout
this subpart the phrase ``for each affected unit'' also applies to each
group of affected or nonaffected units utilizing a common stack and
common monitoring systems, pursuant to Secs. 75.13 through 75.18, or
utilizing a common pipe header and common fuel flowmeter, pursuant to
section 2.1.2 of appendix D to this part. The file shall contain the
following information:
(1) The data and information required in paragraphs (b) through (f)
of this section, beginning with the earlier of the date of provisional
certification or the deadline in Sec. 75.4(a), (b), or (c);
(2) The supporting data and information used to calculate values
required in paragraphs (b) through (f) of this section, excluding the
subhourly data points used to compute hourly averages under
Sec. 75.10(d), beginning with the earlier of the date of provisional
certification or the deadline in Sec. 75.4(a), (b), or (c);
(3) The data and information required in Sec. 75.55 or Sec. 75.58
for specific situations, as applicable, beginning with the earlier of
the date of provisional certification or the deadline in Sec. 75.4(a),
(b), or (c);
(4) The certification test data and information required in
Sec. 75.56 or Sec. 75.59 for tests required under Sec. 75.20, beginning
with the date of the first certification test performed; the quality
assurance and quality control data and information required in
Sec. 75.56 or Sec. 75.59 for tests; and the quality assurance/quality
control plan required under Sec. 75.21 and appendix B to this part,
beginning with the date of provisional certification;
(5) The current monitoring plan as specified in Sec. 75.53,
beginning with the initial submission required by Sec. 75.62; and
(6) The quality control plan as described in section 1 of appendix
B to this part, beginning with the date of provisional certification.
(b) Operating parameter record provisions. The owner or operator
shall record for each hour the following information on unit operating
time, heat input rate, and load, separately for each affected unit and
also for each group of units utilizing a common stack and a common
monitoring system or utilizing a common pipe header and common fuel
flowmeter.
(1) Date and hour;
(2) Unit operating time (rounded up to the nearest fraction of an
hour (in equal increments that can range from one hundredth to one
quarter of an hour, at the option of the owner or operator));
(3) Hourly gross unit load (rounded to nearest MWge) (or steam load
in 1000 lb/hr at stated temperature and pressure, rounded to the
nearest 1000 lb/hr, if elected in the monitoring plan);
(4) Operating load range corresponding to hourly gross load of 1 to
10, except for units using a common stack or common pipe header, which
may use up to 20 load ranges for stack or fuel flow, as specified in
the monitoring plan;
(5) Hourly heat input rate (mmBtu/hr, rounded to the nearest
tenth);
(6) Identification code for formula used for heat input, as
provided in Sec. 75.53; and
(7) For CEMS units only:
(i) F-factor for heat input calculation; and
(ii) Indication of whether the diluent cap was used for heat input
calculations for the hour.
(c) SO2 emission record provisions. The owner or
operator shall record for each hour the information required by this
paragraph for each affected unit or group of units using a common stack
and common monitoring systems, except as provided under Sec. 75.11(e)
or for a gas-fired or oil-fired unit for which the owner or operator is
using the optional protocol in appendix D to this part or for a low
mass emissions unit for which the owner or operator is using the
optional low mass emissions methodology in Sec. 75.19(c) for estimating
SO2 mass emissions:
(1) For SO2 concentration during unit operation, as
measured and reported from each certified primary monitor, certified
back-up monitor, or other approved method of emissions determination:
(i) Component-system identification code, as provided in
Sec. 75.53;
(ii) Date and hour;
(iii) Hourly average SO2 concentration (ppm, rounded to
the nearest tenth);
(iv) Hourly average SO2 concentration (ppm, rounded to
the nearest tenth), adjusted for bias if bias adjustment factor is
required, as provided in Sec. 75.24(d);
(v) Percent monitor data availability (recorded to the nearest
tenth of a percent), calculated pursuant to Sec. 75.32; and
(vi) Method of determination for hourly average SO2
concentration using Codes 1-55 in Table 4a of this section.
(2) For flow rate during unit operation, as measured and reported
from each certified primary monitor, certified back-up monitor, or
other approved method of emissions determination:
(i) Component system identification code, as provided in Sec. 75.53
(including the separate identification code for the moisture monitoring
system, if applicable);
(ii) Date and hour;
(iii) Hourly average volumetric flow rate (in scfh, rounded to the
nearest thousand);
(iv) Hourly average volumetric flow rate (in scfh, rounded to the
nearest thousand), adjusted for bias if bias
[[Page 28138]]
adjustment factor required, as provided in Sec. 75.24(d);
(v) Hourly average moisture content of flue gas (percent, rounded
to the nearest tenth), where SO2 concentration is measured
on a dry basis. If the continuous moisture monitoring system consists
of wet- and dry-basis oxygen analyzers, record both the wet- and dry-
basis oxygen hourly averages (in percent O2, rounded to the
nearest tenth);
(vi) Percent monitor data availability (recorded to the nearest
tenth of a percent), for the flow monitor, and, if applicable,
separately for the moisture monitoring system, calculated pursuant to
Sec. 75.32; and
(vii) Method of determination for hourly average flow rate using
Codes 1-55 in Table 4a of this section.
(3) For SO2 mass emission rate during unit operation, as
measured and reported from the certified primary monitoring system(s),
certified redundant or non-redundant back-up monitoring system(s), or
other approved method(s) of emissions determination:
(i) Date and hour;
(ii) Hourly SO2 mass emission rate (lb/hr, rounded to
the nearest tenth);
(iii) Hourly SO2 mass emission rate (lb/hr, rounded to
the nearest tenth), adjusted for bias if bias adjustment factor
required, as provided in Sec. 75.24(d); and
(iv) Identification code for emissions formula used to derive
hourly SO2 mass emission rate from SO2
concentration and flow data in paragraphs (c)(1) and (c)(2) of this
section, as provided in Sec. 75.53.
Table 4a.--Codes for Method of Emissions and Flow Determination
------------------------------------------------------------------------
Hourly emissions/flow measurement or estimation
Code method
------------------------------------------------------------------------
1.................... Certified primary emission/flow monitoring
system.
2.................... Certified backup emission/flow monitoring system.
3.................... Approved alternative monitoring system.
4.................... Reference method: SO2: Method 6C. Flow: Method 2.
NOX: Method 7E. CO2 or O2: Method 3A.
5.................... For units with add-on SO2 and/or NOX emission
controls: SO2 concentration or NOX emission rate
estimate from Agency preapproved parametric
monitoring method.
6.................... Average of the hourly SO2 concentrations, CO2
concentrations, flow rate, or NOX emission rate
for the hour before and the hour following a
missing data period.
7.................... Hourly average SO2 concentration, CO2
concentration, flow rate, or NOX emission rate
using initial missing data procedures.
8.................... 90th percentile hourly SO2 concentration, flow
rate, or emission rate.
9.................... 95th percentile hourly SO2 concentration, flow
rate, or NOX emission rate.
10................... Maximum hourly SO2 concentration, flow rate, or
NOX emission rate.
11................... Hourly average flow rate or NOX emission rate in
corresponding load range.
12................... Maximum potential concentration of SO2, maximum
potential concentration of CO2, maximum
potential flow rate, or maximum potential NOX
emission rate, as determined using section 2.1
of appendix A to this part.
13................... Fuel analysis data from appendix G to this part
for CO2 mass emissions. (This code is optional
through 12/31/99, and shall not be used after 1/
1/00.)
14................... Diluent cap value (if the cap is replacing a CO2
measurement, it shall be 5.0 percent for boilers
and 1.0 percent for turbines; if it is replacing
an O2 measurement, it shall be 14.0 percent for
boilers and 19.0 percent for turbines.
15................... Fuel analysis data from appendix G to this part
for CO2 mass emissions. (This code is optional
through 12/31/99, and shall not be used after 1/
1/00.)
16................... SO2 concentration value of 2 ppm during hours
when only natural gas (or fuel with equivalent
sulfur content) is combusted.
19................... 200.0 percent of the MPC; default high range
value.
20................... 200.0 percent of the full-scale range setting
(full-scale exceedance of high range).
40................... Stack volumetric flow calculated using the
procedures of appendix I.
54................... Other quality assured methodologies approved
through petition. These hours are included in
missing data lookback and are included as
unavailable hours for percent monitor
availability calculations.
55................... Other substitute data approved through petition.
These hours are not included in missing data
lookback and are included as unavailable hours
for percent monitor availability calculations.
------------------------------------------------------------------------
(d) NOX emission record provisions. The owner or
operator shall record the information required by this paragraph for
each affected unit for each hour, or partial hour during which the unit
operates, except for a gas-fired peaking unit or oil-fired peaking unit
for which the owner or operator is using the optional protocol in
appendix E to this part or a low mass emissions unit for which the
owner or operator is using the optional low mass emissions excepted
methodology in Sec. 75.19(c) for estimating NOX emission
rate. For each NOX emission rate as measured and reported
from the certified primary monitor, certified back-up monitor, or other
approved method of emissions determination:
(1) Component system identification code, as provided in Sec. 75.53
(including identification code for the moisture monitoring system, if
applicable);
(2) Date and hour;
(3) Hourly average concentration (ppm, rounded to the nearest
tenth);
(4) Hourly average diluent gas concentration (percent O2
or percent CO2, rounded to the nearest tenth) and, if
applicable, the hourly average moisture content of the stack gas
(percent H2O, rounded to the nearest tenth). If the
continuous moisture monitoring system consists of wet- and dry-basis
oxygen analyzers, also record both the hourly wet- and dry-basis oxygen
readings (in percent O2, rounded to the nearest tenth);
(5) Hourly average NOX emission rate (lb/mmBtu, rounded
either to the nearest hundredth or thousandth prior to January 1, 2000
and rounded to the nearest thousandth on and after January 1, 2000);
(6) Hourly average NOX emission rate (lb/mmBtu, rounded
either to the nearest hundredth or thousandth prior to January 1, 2000
and rounded to the nearest thousandth on and after January 1, 2000),
adjusted for bias if bias adjustment factor is required, as provided in
Sec. 75.24(d). The requirement to report hourly NOX emission
rates to the nearest thousandth shall not affect NOX
compliance determinations under part 76 of this chapter; compliance
with each applicable emission limit under part 76 shall be determined
to the nearest hundredth pound per million Btu;
(7) Percent monitoring system data availability (recorded to the
nearest tenth of a percent), for the NOX
[[Page 28139]]
monitoring system, and, if applicable, separately for the moisture
monitoring system, calculated pursuant to Sec. 75.32;
(8) Method of determination for hourly average NOX
emission rate using Codes 1-55 in Table 4a of this section;
(9) Identification code for emissions formulas used to derive
hourly average NOX emission rate and total NOX
mass, as provided in Sec. 75.53, and F-factor used to convert
NOX concentrations into emission rates;
(e) CO2 emission record provisions. Except for a low
mass emissions unit for which the owner or operator is using the
optional low mass emissions excepted methodology in Sec. 75.19(c) for
estimating CO2 mass emissions, the owner or operator shall
record or calculate CO2 emissions for each affected unit
using one of the following methods specified in this section:
(1) If the owner or operator chooses to use a CO2
continuous emission monitoring system (including an O2
monitor and flow monitor, as specified in appendix F to this part),
then the owner or operator shall record for each hour or partial hour
during which the unit operates the following information for
CO2 mass emissions, as measured and reported from the
certified primary monitor, certified back-up monitor, or other approved
method of emissions determination:
(i) Component/system identification code, as provided in
Sec. 75.53;
(ii) Date and hour;
(iii) Hourly average CO2 concentration (in percent,
rounded to the nearest tenth);
(iv) Hourly average volumetric flow rate (scfh, rounded to the
nearest thousand scfh);
(v) Hourly average moisture content of flue gas (percent, rounded
to the nearest tenth), where CO2 concentration is measured
on a dry basis. If the continuous moisture monitoring system consists
of wet- and dry-basis oxygen analyzers, also record both the hourly
wet- and dry-basis oxygen readings (in percent O2, rounded
to the nearest tenth);
(vi) Hourly average CO2 mass emission rate (tons/hr,
rounded to the nearest tenth);
(vii) Percent monitor data availability for both the CO2
monitoring system and, if applicable, the moisture monitoring system
(recorded to the nearest tenth of a percent), calculated pursuant to
Sec. 75.32;
(viii) Method of determination for hourly average CO2
mass emission rate using Codes 1-55 in Table 4a of this section;
(ix) Identification code for emissions formula used to derive
hourly average CO2 mass emission rate, as provided in
Sec. 75.53; and
(x) Indication of whether the diluent cap was used for
CO2 calculation for the hour.
(2) As an alternative to paragraph (e)(1) of this section, the
owner or operator may use the procedures in Sec. 75.13 and in appendix
G to this part, and shall record daily the following information for
CO2 mass emissions:
(i) Date;
(ii) Daily combustion-formed CO2 mass emissions (tons/
day, rounded to the nearest tenth);
(iii) For coal-fired units, flag indicating whether optional
procedure to adjust combustion-formed CO2 mass emissions for
carbon retained in flyash has been used and, if so, the adjustment;
(iv) For a unit with a wet flue gas desulfurization system or other
controls generating CO2, daily sorbent-related
CO2 mass emissions (tons/day, rounded to the nearest tenth);
and
(v) For a unit with a wet flue gas desulfurization system or other
controls generating CO2, total daily CO2 mass
emissions (tons/day, rounded to the nearest tenth) as sum of
combustion-formed emissions and sorbent-related emissions.
(f) Opacity records. The owner or operator shall record opacity
data as specified by the State or local air pollution control agency.
If the State or local air pollution control agency does not specify
recordkeeping requirements for opacity, then record the information
required by paragraphs (f) (1) through (5) of this section for each
affected unit, except as provided in Sec. 75.14 (b), (c), and (d). The
owner or operator shall also keep records of all incidents of opacity
monitor downtime during unit operation, including reason(s) for the
monitor outage(s) and any corrective action(s) taken for opacity, as
measured and reported by the continuous opacity monitoring system:
(1) Component/system identification code;
(2) Date, hour, and minute;
(3) Average opacity of emissions for each six minute averaging
period (in percent opacity);
(4) If the average opacity of emissions exceeds the applicable
standard, then a code indicating such an exceedance has occurred; and
(5) Percent monitor data availability (recorded to the nearest
tenth of a percent), calculated according to the requirements of the
procedure recommended for State Implementation Plans in appendix M to
part 51 of this chapter.
(g) O2-diluent record provisions. The owner or operator
of a unit using a flow monitor and an O2-diluent monitor to
determine heat input, in accordance with Equation F-17 or F-18 of
appendix F to this part, shall keep the following records for the
O2-diluent monitor:
(1) Component-system identification code, as provided in
Sec. 75.53;
(2) Date and hour;
(3) Hourly average O2 concentration (in percent, rounded to the
nearest tenth);
(4) Percent monitor data availability (recorded to the nearest
tenth of a percent), calculated pursuant to Sec. 75.32;
(5) Method of determination code for O2 concentration
data using Codes 1-55, substituting the words ``O2
concentrations'' and ``O2 concentration'' for the words
``CO2 concentrations'' and CO2 concentration'' in
the descriptions of Codes 6 and 7 in Table 4a of this section,
respectively.
(h) Missing data records. The owner or operator shall record the
causes of any missing data periods and the actions taken by the owner
or operator to cure such causes.
(i) Compliance dates. Beginning on January 1, 2000, the owner or
operator shall comply with the provisions in paragraphs (a), (b), (e)
and (f) of this section only. Before January 1, 2000, the owner or
operator shall comply with either paragraphs (a) through (d) or
paragraphs (a), (b), (c), and (f) of this section, except that the
owner or operator shall comply with provisions in paragraphs (e) and
(f) of this section only before January 1, 2000, when those provisions
support a regulatory option provided in another section of this part 75
and the regulatory option is exercised before January 1, 2000.
39. Section 75.58 is added to read as follows:
Sec. 75.58 General recordkeeping provisions for specific situations.
(a) Specific SO2 emission record provisions for units
with qualifying Phase I technology. In addition to the SO2
emissions information required in Sec. 75.54(c), from January 1, 1997
through December 31, 1999, the owner or operator shall record the
applicable information in this paragraph for each affected unit on
which SO2 emission controls have been installed and operated
for the purpose of meeting qualifying Phase I technology requirements
pursuant to Sec. 72.42 of this chapter and Sec. 75.15.
(1) For units with post-combustion emission controls:
(i) Component/system identification codes for each inlet and outlet
SO2-diluent continuous emission monitoring system;
(ii) Date and hour;
[[Page 28140]]
(iii) Hourly average inlet SO2 emission rate during unit
operation (lb/mmBtu, rounded to nearest hundredth);
(iv) Hourly average outlet SO2 emission rate during unit
operation (lb/mmBtu, rounded to nearest hundredth);
(v) Percent data availability for both inlet and outlet
SO2-diluent continuous emission monitoring systems (recorded
to the nearest tenth of a percent), calculated pursuant to Equation 8
of Sec. 75.32 (for the first 8,760 unit operating hours following
initial certification) and Equation 9 of Sec. 75.32, thereafter; and
(vi) Identification code for emissions formula used to derive
hourly average inlet and outlet SO2 mass emissions rates for
each affected unit or group of units using a common stack.
(2) For units with combustion and/or pre-combustion emission
controls:
(i) Component/system identification codes for each outlet
SO2-diluent continuous emission monitoring system;
(ii) Date and hour;
(iii) Hourly average outlet SO2 emission rate during
unit operation (lb/mmBtu, rounded to nearest hundredth);
(iv) For units with combustion controls, average daily inlet
SO2 emission rate (lb/mmBtu, rounded to nearest hundredth),
determined by coal sampling and analysis procedures in Sec. 75.15; and
(v) For units with pre-combustion controls (i.e., fuel
pretreatment), fuel analysis demonstrating the weight, sulfur content,
and gross calorific value of the product and raw fuel lots.
(b) Specific parametric data record provisions for calculating
substitute emissions data for units with add-on emission controls. In
accordance with Sec. 75.34, the owner or operator of an affected unit
with add-on emission controls shall either record the applicable
information in paragraph (b)(3) of this section for each hour of
missing SO2 concentration data or NOX emission
rate (in addition to other information), or shall record the
information in paragraph (b)(1) of this section for SO2 or
paragraph (b)(2) of this section for NOX through an
automated data acquisition and handling system, as appropriate to the
type of add-on emission controls:
(1) For units with add-on SO2 emission controls
petitioning to use or using the optional parametric monitoring
procedures in appendix C to this part, for each hour of missing
SO2 concentration or volumetric flow data:
(i) The information required in Sec. 75.54(b) or Sec. 75.57(b) for
SO2 concentration and volumetric flow, if either one of
these monitors is still operating;
(ii) Date and hour;
(iii) Number of operating scrubber modules;
(iv) Total feedrate of slurry to each operating scrubber module
(gal/min);
(v) Pressure differential across each operating scrubber module
(inches of water column);
(vi) For a unit with a wet flue gas desulfurization system, an in-
line measure of absorber pH for each operating scrubber module;
(vii) For a unit with a dry flue gas desulfurization system, the
inlet and outlet temperatures across each operating scrubber module;
(viii) For a unit with a wet flue gas desulfurization system, the
percent solids in slurry for each scrubber module.
(ix) For a unit with a dry flue gas desulfurization system, the
slurry feed rate (gal/min) to the atomizer nozzle;
(x) For a unit with SO2 add-on emission controls other
than wet or dry limestone, corresponding parameters approved by the
Administrator;
(xi) Method of determination of SO2 concentration and
volumetric flow using Codes 1-55 in Table 4 of Sec. 75.54 or Table 4a
of Sec. 75.57; and
(xii) Inlet and outlet SO2 concentration values,
recorded by an SO2 continuous emission monitoring system,
and the removal efficiency of the add-on emission controls.
(2) For units with add-on emission controls petitioning to use or
using the optional parametric monitoring procedures in appendix C to
this part, for each hour of missing NOX emission rate data:
(i) Date and hour;
(ii) Inlet air flow rate (scfh, rounded to the nearest thousand);
(iii) Excess O2 concentration of flue gas at stack
outlet (percent, rounded to nearest tenth of a percent);
(iv) Carbon monoxide concentration of flue gas at stack outlet
(ppm, rounded to the nearest tenth);
(v) Temperature of flue gas at furnace exit or economizer outlet
duct ( deg.F);
(vi) Other parameters specific to NOX emission controls
(e.g., average hourly reagent feedrate);
(vii) Method of determination of NOX emission rate using
Codes 1-55 in Table 4 of Sec. 75.54 or Table 4a of Sec. 75.57; and
(viii) Inlet and outlet NOX emission rate values
recorded by a NOX continuous emission monitoring system and
the removal efficiency of the add-on emission controls.
(3) For units with add-on SO2 or NOX emission
controls following the provisions of Sec. 75.34(a)(1) or (a)(2), the
owner or operator shall, for each hour of missing SO2 or
NOX emission data, record:
(i) Parametric data which demonstrate the proper operation of the
add-on emission controls, as described in the quality assurance/quality
control program for the unit. The parametric data shall be maintained
on site and shall be submitted, upon request, to the Administrator, EPA
Regional office, State, or local agency;
(ii) A flag indicating either that the add-on emission controls are
operating properly, as evidenced by all parameters being within the
ranges specified in the quality assurance/quality control program, or
that the add-on emission controls are not operating properly;
(iii) For units petitioning under Sec. 75.66 for substituting a
representative SO2 concentration during missing data
periods, any available inlet and outlet SO2 concentration
values recorded by an SO2 continuous emission monitoring
system; and
(iv) For units petitioning under Sec. 75.66 for substituting a
representative NOX emission rate during missing data
periods, any available inlet and outlet NOX emission rate
values recorded by a continuous emission monitoring system.
(c) Specific SO2 emission record provisions for gas-
fired or oil-fired units using optional protocol in appendix D to this
part. In lieu of recording the information in Sec. 75.54(c) or
Sec. 75.57(c), the owner or operator shall record the applicable
information in this paragraph for each affected gas-fired or oil-fired
unit for which the owner or operator is using the optional protocol in
appendix D to this part for estimating SO2 mass emissions.
(1) For each hour when the unit is combusting oil:
(i) Date and hour;
(ii) Hourly average flow rate of oil, while the unit combusts oil,
with the units in which oil flow is recorded (gal/hr, lb/hr,
m3/hr, or bbl/hr, rounded to the nearest tenth) (flag value
if derived from missing data procedures);
(iii) Sulfur content of oil sample used to determine SO2
mass emission rate (rounded to nearest hundredth for diesel fuel or to
the nearest tenth of a percent for other fuel oil) (flag value if
derived from missing data procedures);
(iv) Method of oil sampling (flow proportional, continuous drip, as
delivered, manual from storage tank, or daily manual);
(v) Mass rate of oil combusted each hour (lb/hr, rounded to the
nearest tenth) (flag value if derived from missing data procedures);
(vi) SO2 mass emission rate from oil (lb/hr, rounded to
the nearest tenth);
(vii) For units using volumetric oil flowmeters, density of oil
with the units in which oil density is recorded (flag
[[Page 28141]]
value if derived from missing data procedures);
(viii) Gross calorific value (heat content) of oil used to
determine heat input (Btu/mass unit) (flag value if derived from
missing data procedures);
(ix) Hourly heat input rate from oil, according to procedures in
appendix F to this part (mmBtu/hr, to the nearest tenth);
(x) Fuel usage time for combustion of oil during the hour (rounded
up to the nearest fraction of an hour (in equal increments that can
range from one hundredth to one quarter of an hour, at the option of
the owner or operator)) (flag to indicate multiple/single fuel types
combusted); and
(xi) Monitoring system identification code.
(2) For gas-fired units or oil-fired units using the optional
protocol in appendix D to this part for daily manual oil sampling, when
the unit is combusting oil, the highest sulfur content recorded from
the most recent 30 daily oil samples (rounded to nearest tenth of a
percent).
(3) For gas-fired units or oil-fired units, using the optional
protocol in appendix D to this part for using an assumed sulfur content
or density, or for as-delivered fuel sampled from each delivery:
(i) Record the measured sulfur content, GCV and, if applicable,
density from each fuel sample; and
(ii) Record and report the assumed sulfur content, GCV and, if
applicable, density used to calculate SO2 mass emission rate
or heat input rate.
(4) For each hour when the unit is combusting gaseous fuel:
(i) Date and hour;
(ii) Hourly heat input rate from gaseous fuel, according to
procedures in appendix F to this part (mmBtu/hr, rounded to the nearest
tenth);
(iii) Sulfur content or SO2 emission rate, in one of the
following formats, in accordance with the appropriate procedure from
appendix D to this part:
(A) Sulfur content of gas sample (rounded to the nearest 0.1
grains/100 scf) (flag value if derived from missing data procedures);
or
(B) SO2 emission rate from NADB or default
SO2 emission rate of 0.0006 lb/mmBtu for pipeline natural
gas;
(iv) Hourly flow rate of gaseous fuel, while the unit combusts gas
(100 scfh) (flag value if derived from missing data procedures);
(v) Gross calorific value (heat content) of gaseous fuel used to
determine heat input rate (Btu/100 scf) (flag value if derived from
missing data procedures);
(vi) Heat input rate from gaseous fuel, while the unit combusts gas
(mmBtu/hr, rounded to the nearest tenth);
(vii) SO2 mass emission rate due to the combustion of
gaseous fuels (lb/hr);
(viii) Fuel usage time for combustion of gaseous fuel during the
hour (rounded up to the nearest fraction of an hour (in equal
increments that can range from one hundredth to one quarter of an hour,
at the option of the owner or operator)) (flag to indicate multiple/
single fuel types combusted); and
(ix) Monitoring system identification code.
(5) For each oil sample or sample of diesel fuel:
(i) Date of sampling;
(ii) Sulfur content (percent, rounded to the nearest hundredth for
diesel fuel and to the nearest tenth for other fuel oil) (flag value if
derived from missing data procedures);
(iii) Gross calorific value or heat content (Btu/lb) (flag value if
derived from missing data procedures); and
(iv) Density or specific gravity, if required to convert volume to
mass (flag value if derived from missing data procedures).
(6) For each sample of gaseous fuel for sulfur content:
(i) Date of sampling;
(ii) Sulfur content (grains/100 scf, rounded to the nearest tenth)
(flag value if derived from missing data procedures);
(7) For each sample of gaseous fuel for gross calorific value:
(i) Date of sampling; and
(ii) Gross calorific value or heat content (Btu/100 scf) (flag
value if derived from missing data procedures).
(8) For each oil sample or sample of gaseous fuel:
(i) Type of oil or gas; and
(ii) Type of sulfur sampling and value used in calculations.
(d) Specific NOX emission record provisions for gas-
fired peaking units or oil-fired peaking units using optional protocol
in appendix E to this part. In lieu of recording the information in
paragraph Sec. 75.54(d) or Sec. 75.57(d), the owner or operator shall
record the applicable information in this paragraph for each affected
gas-fired peaking unit or oil-fired peaking unit for which the owner or
operator is using the optional protocol in appendix E to this part for
estimating NOX emission rate. The owner or operator shall
meet the requirements of this section, except that the requirements
under paragraphs (d)(1)(vii), (d)(2)(vii), and (d)(3)(vi) of this
section shall become applicable on the date on which the owner or
operator is required to monitor, record, and report NOX mass
emissions under an applicable State or federal NOX mass
emission reduction program, if the provisions of subpart H of this part
are adopted as requirements under such a program.
(1) For each hour when the unit is combusting oil:
(i) Date and hour;
(ii) Hourly average fuel flow rate of oil while the unit combusts
oil with the units in which oil flow is recorded (gal/hour, lb/hr, or
bbl/hour) (flag value if derived from missing data procedures);
(iii) Gross calorific value (heat content) of oil used to determine
heat input (Btu/lb) (flag value if derived from missing data
procedures);
(iv) Hourly average NOX emission rate from combustion of
oil (lb/mmBtu);
(v) Heat input rate of oil (mmBtu/hr, rounded to the nearest tenth;
(vi) Fuel usage time for combustion of oil during the hour (rounded
up to the nearest fraction of an hour (in equal increments that can
range from one hundredth to one quarter of an hour, at the option of
the owner or operator)); and
(vii) NOX mass emissions, calculated in accordance with
section 8.1 of appendix F to this part.
(2) For each hour when the unit is combusting gaseous fuel:
(i) Date and hour;
(ii) Hourly average fuel flow rate of gaseous fuel, while the unit
combusts gas (100 scfh) (flag value if derived from missing data
procedures);
(iii) Gross calorific value (heat content) of gaseous fuel used to
determine heat input (Btu/100 scf) (flag value if derived from missing
data procedures);
(iv) Hourly average NOX emission rate from combustion of
gaseous fuel (lb/mmBtu, rounded to nearest hundredth);
(v) Heat input rate from gaseous fuel, while the unit combusts gas
(mmBtu/hr, rounded to the nearest tenth);
(vi) Fuel usage time for combustion of gaseous fuel during the hour
(rounded up to the nearest fraction of an hour (in equal increments
that can range from one hundredth to one quarter of an hour, at the
option of the owner or operator)); and
(vii) NOX mass emissions, calculated in accordance with
section 8.1 of appendix F to this part.
(3) For each hour when the unit combusts any fuel:
(i) Date and hour;
(ii) Hourly average heat input rate from all fuels (mmBtu/hr,
rounded to the nearest tenth);
(iii) Hourly average NOX emission rate for the unit for
all fuels;
(iv) For stationary gas turbines and diesel or dual-fuel
reciprocating engines, hourly averages of operating parameters under
section 2.3 of appendix E to this part (flag if value is
[[Page 28142]]
outside of manufacturer's recommended range);
(v) For boilers, hourly average boiler O2 reading
(percent, rounded to the nearest tenth) (flag if value exceeds by more
than 2 percentage points the O2 level recorded at the same
heat input during the previous NOX emission rate test);
(vi) NOX mass emissions, calculated in accordance with
section 8.1 of appendix F to this part;
(vii) Segment ID of the correlation curve; and
(viii) Monitoring system identification code.
(4) For each fuel sample:
(i) Date of sampling;
(ii) Gross calorific value (heat content) (Btu/lb for oil, Btu/100
scf for gaseous fuel); and
(iii) Density or specific gravity, if required to convert volume to
mass.
(e) Specific SO2 emission record provisions during the
combustion of gaseous fuel. (1) If SO2 emissions are
determined in accordance with the provisions in Sec. 75.11(e)(2) during
hours in which only natural gas (or gaseous fuel with a total sulfur
content no greater than the total sulfur content of natural gas) is
combusted in a unit with an SO2 continuous emission
monitoring system, the owner or operator shall record the information
in paragraph (c)(3) of this section in lieu of the information in
Secs. 75.54(c)(1) and (c)(3) or Secs. 75.57(c)(1) and (c)(3), for those
hours.
(2) The provisions of this paragraph apply to a unit which, in
accordance with the provisions of Sec. 75.11(e)(3), uses an
SO2 continuous emission monitoring system to determine
SO2 emissions during hours in which only natural gas or
gaseous fuel with a total sulfur content no greater than the total
sulfur content of natural gas is combusted in the unit. If the unit
sometimes burns only natural gas (or gaseous fuel with total sulfur
content no greater than the total sulfur content of natural gas) as a
primary and/or backup fuel and at other times combusts higher-sulfur
fuels, such as coal or oil, as primary and/or backup fuel(s), then the
owner or operator shall keep records on-site, suitable for inspection,
of the type(s) of fuel(s) burned during each period of missing
SO2 data and the number of hours that each types of fuel was
combusted in the unit during each missing data period. This
recordkeeping requirement does not apply to an affected unit that burns
natural gas (or gaseous fuel with a total sulfur content no greater
than the total sulfur content of natural gas) exclusively, nor does it
apply to a unit that burns such gaseous fuel(s) only during unit
startup.
(f) Specific SO2, NOX, and CO2
record provisions for gas-fired or oil-fired units using the optional
low mass emissions excepted methodology in Sec. 75.19. In lieu of
recording the information in Secs. 75.54(b) through (e) or
Sec. 75.57(b) through (e), the owner or operator shall record, for each
hour when the unit is operating for any portion of the hour, the
following information for each affected low mass emissions unit for
which the owner or operator is using the optional low mass emissions
excepted methodology in Sec. 75.19(c):
(1) Date and hour;
(2) Fuel type (pipeline natural gas, natural gas, residual oil, or
diesel fuel) (note: if more than one type of fuel is combusted in the
hour, indicate the fuel type which results in the highest emission
factors for SO2, CO2, and NOX);
(3) Average hourly NOX emission rate (lb/mmBtu, rounded
to the nearest thousandth);
(4) Hourly NOX mass emissions (lbs, rounded to the
nearest tenth);
(5) Hourly SO2 mass emissions (lbs, rounded to the
nearest tenth); and
(6) Hourly CO2 mass emissions (tons, rounded to the
nearest tenth).
(g) Specific provisions for gas-fired units or oil-fired units
using optional protocol in appendix I to this part. In addition to
recording the information in Sec. 75.54(c) or Sec. 75.57(c), as
applicable, the owner or operator shall record the applicable
information in this paragraph for each affected unit for which the
owner or operator is using the optional protocol in appendix I to this
part. This includes:
(1) For each hour when the unit is combusting oil:
(i) Date and hour;
(ii) Hourly average flow rate of oil with the units in which oil
flow is recorded (gal/hr, lb/hr, m3/hr, or bbl/hr, rounded
to the nearest tenth) (flag value if derived from missing data
procedures);
(iii) Method of oil sampling (flow proportional, continuous drip,
as delivered, or manual);
(iv) Mass of oil combusted each hour (lb/hr, rounded to the nearest
tenth);
(v) For units using volumetric oil flowmeters, density of oil (flag
value if derived from missing data procedures);
(vi) Gross calorific value (heat content) of oil used to determine
heat input (Btu/mass unit) (flag value if derived from missing data
procedures);
(vii) Hourly heat input rate from oil, according to procedures in
appendix F to this part (mmBtu/hr, to the nearest tenth); and
(viii) Fuel usage time for combustion of oil during the hour
(rounded up to the nearest 15 minutes).
(2) For each hour when the unit is combusting gaseous fuel:
(i) Date and hour;
(ii) Hourly heat input rate from gaseous fuel according to
procedures in appendix F to this part (mmBtu/hr, rounded to the nearest
tenth);
(iii) Hourly flow rate of gaseous fuel (100 scfh) (flag value if
derived from missing data procedures);
(iv) Gross calorific value (heat content) of gaseous fuel used to
determine heat input (Btu/100 scf) (flag value if derived from missing
data procedures);
(v) Heat input rate from gaseous fuel (mmBtu/hr, rounded to the
nearest tenth);
(vi) Fuel usage time for combustion of gaseous fuel during the hour
(rounded up to the nearest 15 minutes); and
(vii) F-factor (Fc=Carbon-based F-factor of 1040 scf
CO2/mmBtu for natural gas, or Fd=Dry basis,
O2-based F-factor of 8,710 dscf/mmBtu for natural gas).
(3) For each oil sample or sample of diesel fuel:
(i) Date of sampling;
(ii) Gross calorific value or heat content (Btu/lb) (flag value if
derived from missing data procedures);
(iii) Density or specific gravity, if required to convert volume to
mass (flag value if derived from missing data procedures); and
(iv) Percent carbon by weight.
(4) For each monthly sample of gaseous fuel:
(i) Date of sampling; and
(ii) Gross calorific value or heat content (Btu/100 scf) (flag
value if derived from missing data procedures).
(5) Hourly average diluent gas concentration (percent O2
or percent CO2, rounded to the nearest tenth).
(h) Compliance dates. Beginning on January 1, 2000, the owner or
operator shall comply with this section only. Before January 1, 2000,
the owner or operator shall comply with either this section or
Sec. 75.55; except that if a regulatory option provided in another
section of this part 75 is exercised prior to January 1, 2000, then the
owner or operator shall comply with any provisions of this section that
support the regulatory option beginning with the date on which the
option is exercised.
40. Section 75.59 is added to read as follows:
Sec. 75.59 Certification, quality assurance, and quality control
record provisions.
(a) Continuous emission or opacity monitoring systems. The owner or
[[Page 28143]]
operator shall record the applicable information in this section for
each certified monitor or certified monitoring system (including
certified backup monitors) measuring and recording emissions or flow
from an affected unit.
(1) For each SO2 or NOX pollutant
concentration monitor, flow monitor, CO2 monitor (including
O2 monitors used to determine CO2 emissions),
moisture sensor, or diluent gas monitor (including wet-and dry-basis
O2 monitors used to determine percent moisture), the owner
or operator shall record the following for all daily and 7-day
calibration error tests, including any follow-up tests after corrective
(i) Component/system identification code;
(ii) Instrument span and span scale;
(iii) Date and hour;
(iv) Reference value (i.e., calibration gas concentration or
reference signal value, in ppm or other appropriate units);
(v) Observed value (monitor response during calibration, in ppm or
other appropriate units);
(vi) Percent calibration error (rounded to the nearest tenth of a
percent) (flag if using alternative performance specification for low
emitters or differential pressure flow monitors);
(vii) Calibration gas level;
(viii) Test number and reason for test;
(ix) For 7-day calibration tests for certification or
recertification, a certification from the cylinder gas vendor or CEMS
vendor that calibration gas, as defined in Sec. 72.2 of this chapter
and appendix A to this part, was used to conduct calibration error
testing;
(x) Description of any adjustments, corrective actions, or
maintenance following test; and
(xi) For the qualifying test for off-line calibration, the owner or
operator shall indicate whether the unit is off-line or on-line.
(2) For each flow monitor, the owner or operator shall record the
following for all daily interference checks, including any follow-up
tests after corrective action:
(i) Code indicating whether monitor passes or fails the
interference check; and
(ii) Description of any adjustments, corrective actions, or
maintenance following test.
(3) For each SO2 or NOX pollutant
concentration monitor, CO2 monitor (including O2
monitors used to determine CO2 emissions), or diluent gas
monitor (including wet-and dry-basis O2 monitors used to
determine percent moisture), the owner or operator shall record the
following for the initial and all subsequent linearity check(s),
including any follow-up tests after corrective action:
(i) Component/system identification code;
(ii) Instrument span and span scale;
(iii) Date and hour;
(iv) Reference value (i.e., reference gas concentration, in ppm or
other appropriate units);
(v) Observed value (average monitor response at each reference gas
concentration, in ppm or other appropriate units);
(vi) Percent error at each of three reference gas concentrations
(rounded to nearest tenth of a percent) (flag if using alternative
performance specification);
(vii) Calibration gas level;
(viii) Mean of reference values and mean of measured values;
(ix) Test number and reason for test (flag if aborted test); and
(x) Description of any adjustments, corrective action, or
maintenance following test.
(4) For each flow monitor (where applicable) the owner or operator
shall record items in paragraphs (a)(4)(i) through (v) of this section,
for all quarterly leak checks, including any follow-up tests after
corrective action, and items in paragraphs (a)(4)(vi) and (vii) of this
section, for all flow-to-load ratio and gross heat rate tests:
(i) Component/system identification code;
(ii) Date and hour;
(iii) Reason for test;
(iv) Code indicating whether monitor passes or fails the quarterly
leak check;
(v) Description of any adjustments, corrective actions, or
maintenance following test;
(vi) Test data from the flow-to-load ratio or gross heat rate
evaluation, including:
(A) Component/system identification code;
(B) Calendar year and quarter;
(C) Indication of whether the test is a flow-to-load ratio or gross
heat rate evaluation;
(D) Indication of whether bias adjusted flow rates were used;
(E) Average absolute percent difference between reference ratio (or
BHR) and hourly ratios (or GHE values);
(F) Test result;
(G) Number of hours used in final quarterly average;
(H) Number of hours exempted for use of a different fuel type;
(I) Number of hours exempted for load ramping up or down;
(J) Number of hours exempted for scrubber bypass;
(K) Number of hours exempted for hours preceding a normal-load flow
RATA; and
(L) Number of hours exempted for hours preceding a successful
diagnostic test, following a documented monitor repair or major
component replacement; and
(vii) Reference data for the flow-to-load ratio or gross heat rate
evaluation, including:
(A) Reference flow RATA end date and time;
(B) Test number;
(C) Reference RATA load and load level;
(D) Average reference method flow rate during reference flow RATA;
(E) Reference flow/load ratio;
(F) Average reference method diluent gas concentration during flow
RATA and diluent gas units of measure;
(G) Fuel specific Fd- or Fc-factor during
flow RATA and F-factor units of measure; and
(H) Reference gross heat rate value.
(5) For each SO2 pollutant concentration monitor, flow
monitor, CO2 pollutant concentration monitor (including any
O2 concentration monitor used to determine CO2
mass emissions or heat input), NOX continuous emission
monitoring system, SO2-diluent continuous emission
monitoring system, moisture monitoring system, and approved alternative
monitoring system, the owner or operator shall record the following
information for the initial and all subsequent relative accuracy test
audits:
(i) Reference method(s) used;
(ii) Individual test run data from the relative accuracy test audit
for the SO2 concentration monitor, flow monitor,
CO2 pollutant concentration monitor, NOX
continuous emission monitoring system, SO2-diluent
continuous emission monitoring system, moisture monitoring system, or
approved alternative monitoring systems, including:
(A) Date, hour, and minute of beginning of test run;
(B) Date, hour, and minute of end of test run;
(C) System identification code;
(D) Test number and reason for test;
(E) Operating load level (low, mid, high, or normal, as
appropriate) and number of load levels comprising test;
(F) Run number;
(G) Run data for monitor, in the appropriate units of measure;
(H) Run data for reference method, in the appropriate units of
measure;
(I) Flag value (0, 1, or 9, as appropriate) indicating whether run
has been used in calculating relative accuracy and bias values or
whether the test was aborted prior to completion;
(J) Average gross unit load; and
[[Page 28144]]
(K) Flag to indicate whether an alternative performance
specification has been used.
(iii) Calculations and tabulated results, as follows:
(A) Arithmetic mean of the monitoring system measurement values, of
the reference method values, and of their differences, as specified in
Equation A-7 in appendix A to this part.
(B) Standard deviation, as specified in Equation A-8 in appendix A
to this part.
(C) Confidence coefficient, as specified in Equation A-9 in
appendix A to this part.
(D) Relative accuracy test results, as specified in Equation A-10
in appendix A to this part. (For multi-level flow monitor tests the
relative accuracy test results shall be recorded at each load level
tested. Each load level shall be expressed as a total gross unit load,
rounded to the nearest MWe, or as steam load, rounded to the nearest
thousand lb/hr.)
(E) Bias test results as specified in section 7.6.4 in appendix A
to this part.
(F) Bias adjustment factor from Equations A-11 and A-12 in appendix
A to this part for any monitoring system that failed the bias test
(except as provided in section 7.6.5 of appendix A to this part) and
1.000 for any monitoring system that passed the bias test. (For multi-
load RATAs of flow monitors only, when the bias test is passed at the
load level(s) designated as normal in section 6.5.2.1 of appendix A to
this part, the system BAF shall be recorded as 1.000. When the bias
test is failed at any load level designated as normal in section
6.5.2.1 of appendix A to this part, bias adjustment factors shall be
recorded at the two most frequently used load levels, as defined in
section 6.5.2.1 of appendix A to this part.)
(iv) Description of any adjustment, corrective action, or
maintenance following test.
(v) F-factor value(s) used to convert NOX pollutant
concentration and diluent gas (O2 or CO2)
concentration measurements into NOX emission rates (in lb/
mmBtu), heat input or CO2 emissions.
(vi) For flow monitors, the flow polynomial equation used to
linearize the flow monitor and the numerical values of the polynomial
coefficients of that equation.
(6) For each SO2, NOX, CO2, or
O2 pollutant concentration monitor, NOX-diluent
continuous emission monitoring system, or SO2-diluent
continuous emission monitoring system, the owner or operator shall
record the following information for the cycle time test:
(i) Component/system identification code;
(ii) Date;
(iii) Start and end times;
(iv) Upscale and downscale cycle times for each component;
(v) Stable start monitor value;
(vi) Stable end monitor value;
(vii) Reference value of calibration gas(es);
(viii) Calibration gas level; and
(ix) Cycle time result for the entire system.
(x) Reason for test.
(7) The owner or operator shall also record, for each relative
accuracy test audit, supporting information sufficient to substantiate
compliance with all applicable sections and appendices in this part.
This RATA supporting information shall include, but shall not be
limited to, the following data elements:
(i) For each RATA using Reference Method 2 (or its allowable
alternatives) in appendix A to part 60 of this chapter to determine
volumetric flow rate:
(A) Information indicating whether or not the location meets
requirements of Method 1 in appendix A to part 60 of this chapter; and
(B) Information indicating whether or not the equipment passed the
required leak checks.
(ii) For each run of each RATA using Reference Method 2 (or its
allowable alternatives) in appendix A to part 60 of this chapter to
determine volumetric flow rate, record the following data elements (as
applicable to the measurement method used):
(A) Operating load level (low, mid, high, or normal, as
appropriate);
(B) Number of reference method traverse points;
(C) Average absolute stack gas temperature ( deg. F);
(D) Barometric pressure at test port (inches of mercury);
(E) Stack static pressure (inches of H2O);
(F) Absolute stack gas pressure (inches of mercury);
(G) Percent CO2 and O2 in the stack gas, dry
basis;
(H) CO2 and O2 reference method used;
(I) Moisture content of stack gas (percent H2O);
(J) Molecular weight of stack gas, dry basis (lb/lb-mole);
(K) Molecular weight of stack gas, wet basis (lb/lb-mole);
(L) Stack diameter (or equivalent diameter) at the test port (ft);
(M) Average square root of velocity head of stack gas (inches of
H2O) for the run;
(N) Stack or duct cross-sectional area at test port (ft
2);
(O) Average axial velocity (ft/sec); and
(P) Total volumetric flow rate (scfh, wet basis).
(iii) For each traverse point of each run of each RATA using
Reference Method 2 (or its allowable alternatives) in appendix A to
part 60 of this chapter to determine volumetric flow rate, record the
following data elements (as applicable to the measurement method used):
(A) Reference method probe type;
(B) Pressure measurement device type;
(C) Traverse point ID;
(D) Probe or pitot tube calibration coefficient;
(E) Date of latest probe or pitot tube calibration;
(F) P at traverse point (inches of H2O);
(G) Ts, stack temperature at the traverse point ( deg.
F);
(H) Calculated impact (total) velocity at the traverse point (ft/
sec);
(I) Composite (wall effects) traverse point identifier;
(J) Number of points included in composite traverse point;
(K) Yaw angle of flow at traverse point (degrees);
(L) Pitch angle of flow at traverse point (degrees); and
(M) Calculated axial velocity at traverse point (ft/sec).
(iv) For each RATA using Method 6C, 7E, or 3A in appendix A to part
60 of this chapter to determine SO2, NOX,
CO2, or O2 concentration:
(A) Pollutant or diluent gas being measured;
(B) Span of reference method analyzer;
(C) Type of reference method system (e.g., extractive or dilution
type);
(D) Reference method dilution factor (dilution type systems, only);
(E) Reference gas concentrations (zero, mid, and high gas levels)
used for the 3-point pre-test analyzer calibration error test (or for
dilution type reference method systems, for the 3-point pre-test system
calibration error test) and for any subsequent recalibrations;
(F) Analyzer responses to the zero-, mid-, and high-level
calibration gases during the 3-point pre-test analyzer (or system)
calibration error test and during any subsequent recalibration(s);
(G) Analyzer calibration error at each gas level (zero, mid, and
high) for the 3-point pre-test analyzer (or system) calibration error
test and for any subsequent recalibration(s) (percent of span value);
(H) Reference gas concentration (zero, mid, or high gas levels)
used for each pre-run or post-run system bias check or (for dilution
type reference method
[[Page 28145]]
systems) for each pre-run or post-run system calibration error check;
(I) Analyzer response to the calibration gas for each pre-run or
post-run system bias (or system calibration error) check;
(J) The arithmetic average of the analyzer responses to the zero-
level gas, for each pair of pre- and post-run system bias (or system
calibration error) checks;
(K) The arithmetic average of the analyzer responses to the upscale
calibration gas, for each pair of pre-and post-run system bias (or
system calibration error) checks;
(L) The results of each pre-run and each post-run system bias (or
system calibration error) check using the zero-level gas (percentage of
span value);
(M) The results of each pre-run and each post-run system bias (or
system calibration error) check using the upscale calibration gas
(percentage of span value);
(N) Calibration drift and zero drift of analyzer during each RATA
run (percentage of span value);
(O) Moisture basis of the reference method analysis;
(P) Moisture content of stack gas, in percent, during each test run
(if needed to convert to moisture basis of CEMS being tested);
(Q) Unadjusted (raw) average pollutant or diluent gas concentration
for each run;
(R) Average pollutant or diluent gas concentration for each run,
corrected for calibration bias (or calibration error) and, if
applicable, corrected for moisture;
(S) The F-factor used to convert reference method data to units of
lb/mmBtu (if applicable);
(T) The code for the formula used to convert reference method data
to units of lb/mmBtu (if applicable);
(U) Date(s) of the latest analyzer interference test(s);
(V) Results of the latest analyzer interference test(s);
(W) Date of the latest NO2 to NO conversion test (Method
7E only);
(X) Results of the latest NO2 to NO conversion test
(Method 7E only); and
(Y) For each calibration gas cylinder during each RATA, record the
cylinder gas vendor, cylinder number, expiration date, pollutant(s) in
the cylinder, and certified gas concentration(s).
(v) For each test run of each moisture determination using Method 4
in appendix A to part 60 of this chapter (or its allowable
alternatives), whether the determination is made to support a gas RATA,
to support a flow RATA, or to quality assure the data from a continuous
moisture monitoring system, record the following data elements (as
applicable to the moisture measurement method used):
(A) Parameter (SO2, NOX, flow,
CO2, or H2O), to indicate whether the moisture
determination is used to support a gas or flow rate RATA or whether the
determination is used to quality assure a moisture monitoring system;
(B) Test number;
(C) Run number;
(D) The beginning date, hour, and minute of the run;
(E) The ending date, hour, and minute or the run;
(F) Unit operating level (low, mid, high, or normal, as
appropriate);
(G) Moisture measurement method;
(H) Volume of H2O collected in the impingers (ml);
(I) Mass of H2O collected in the silica gel (g);
(J) Dry gas meter calibration factor;
(K) Average dry gas meter temperature ( deg.F);
(L) Barometric pressure (inches of mercury);
(M) Differential pressure across the orifice meter (inches of
H2O);
(N) Initial and final dry gas meter readings (ft\3\);
(O) Total sample gas volume, corrected to standard conditions
(dscf); and
(P) Percentage of moisture in the stack gas (percent
H2O).
(vi) The upper and lower boundaries of the range of operation (as
defined in section 6.5.2.1 of appendix A to this part) for the unit or
common stack on which the continuous emission monitor(s) are installed,
expressed in megawatts or thousands of lb/hr of steam;
(vii) The load level(s) designated as normal in section 6.5.2.1 of
appendix A to this part for the unit or common stack on which the
continuous emission monitor(s) are installed, expressed in megawatts or
thousands of lb/hr of steam;
(viii) Except for peaking units, the two load levels (i.e., low,
mid, or high) identified in section 6.5.2.1 of appendix A to this part
as the most frequently used;
(ix) Except for peaking units, the relative frequency (percentage)
of historical usage of each load level (low, mid, and high) in the
previous four QA operating quarters, as determined in section 6.5.2.1
of appendix A to this part, to the nearest 0.1 percent. The beginning
and ending calendar quarters in the historical look-back period shall
also be recorded. A summary of the data used to determine the most
frequently and second most frequently used load levels and the
percentage of time that each load level has been used historically
shall be kept on-site in a format suitable for inspection;
(x) Indication of whether the unit/stack qualifies for single load
flow RATA testing (operation for 85.0 percent of operating
hours is at a single load level); and
(xi) Date of the load analysis described in paragraphs (a)(7)(vi)
through (a)(7)(x) of this section.
(8) For each certified continuous emission monitoring system,
continuous opacity monitoring system, or alternative monitoring system,
the date and description of each event which requires recertification
of the system and the date and type of each test performed to recertify
the system in accordance with Sec. 75.20(b).
(9) Hardcopy quality assurance relative accuracy test reports,
certification reports, or recertification reports for pollutant
concentration or stack flow CEMS shall include, as a minimum, the
following elements (as applicable to the type(s) of test(s) performed):
(i) Summarized test results near the front of the report;
(ii) DAHS printouts of the CEMS data generated during the
calibration error, linearity, cycle time, and relative accuracy tests;
(iii) For pollutant concentration monitor relative accuracy tests
at normal operating load:
(A) The raw reference method data from each run (usually in the
form of a computerized printout, showing a series of one-minute
readings and the run average);
(B) The raw data and results for all required pre-test and post-
test quality assurance checks (i.e., calibration gas injections) of the
reference method analyzers;
(C) The raw data and results for any moisture measurements made
during the relative accuracy testing;
(D) Tabulated, final, corrected reference method run data (i.e.,
the actual values used in the relative accuracy calculations), along
with the equations used to convert the raw data to the final values and
example calculations to demonstrate how the test data were reduced;
(iv) For flow monitor relative accuracy tests:
(A) The raw Reference Method 2 data, including auxiliary moisture
data (often in the form of handwritten data sheets);
(B) The tabulated, final volumetric flow rate values used in the
relative accuracy calculations (determined from the Method 2 data and
other necessary measurements, e.g., moisture, stack temperature and
pressure, etc.), along
[[Page 28146]]
with the equations used to convert the raw data to the final values and
example calculations to demonstrate how the test data were reduced;
(v) Calibration gas certificates for the gases used in the
linearity, calibration error, and cycle time tests and for the
calibration gases used to quality assure the gas monitor reference
method data during the relative accuracy test audit;
(vi) Laboratory calibrations of the source sampling equipment;
(vii) A copy of the test protocol used for the CEMS certifications
or recertifications, including narrative that explains any testing
abnormalities, problematic sampling, and analytical conditions that
required a change to the test protocol, and/or solutions to technical
problems encountered during the testing program;
(viii) Diagrams illustrating test locations and sample point
locations (to verify that locations are consistent with presented
information in the monitoring plan). Include a discussion of any
special traversing or measurement scheme. The discussion shall also
confirm that sample points satisfied applicable acceptance criteria;
and
(ix) Names of key personnel involved in the test program, including
test team members, plant contacts, agency representatives or test
observers on site, etc.
(10) Whenever reference methods are used as backup monitoring
systems pursuant to Sec. 75.20(d)(3), the owner or operator shall
record the following information:
(i) For each test run using Reference Method 2 (or its allowable
alternatives) in appendix A to part 60 of this chapter to determine
volumetric flow rate, record the following data elements (as applicable
to the measurement method used):
(A) Unit or stack identification number;
(B) Reference method system and component identification numbers;
(C) Run date and hour;
(D) The data elements in paragraph (a)(7)(ii) of this section,
except for paragraphs (a)(7)(ii) (A), (F), (H), and (L);
(E) Data element in paragraph (a)(7)(iii)(A) of this section.
(ii) For each reference method test run using Method 6C, 7E, or 3A
in appendix A to part 60 of this chapter to determine SO2,
NOX, CO2, or O2 concentration:
(A) Unit or stack identification number;
(B) The reference method system and component identification
numbers;
(C) Run number;
(D) Run start date and hour;
(E) Run end date and hour;
(F) Data elements in paragraph (a)(7)(iv) (B) through (I) and (L)
through (O) of this section; and
(G) Stack gas density adjustment factor (if applicable).
(iii) For each hour of each reference method test run using Method
6C, 7E, or 3A in appendix A to part 60 of this chapter to determine
SO2, NOX, CO2, or O2
concentration:
(A) Unit or stack identification number;
(B) The reference method system and component identification
numbers;
(C) Run number;
(D) Run date and hour;
(E) Pollutant or diluent gas being measured;
(F) Unadjusted (raw) average pollutant or diluent gas concentration
for the hour; and
(G) Average pollutant or diluent gas concentration for the hour,
adjusted as appropriate for moisture, calibration bias (or calibration
error) and stack gas density.
(11) For each other quality-assurance test or other quality
assurance activity, the owner or operator shall record the following:
(i) Component/system identification code;
(ii) Parameter;
(iii) Test or activity completion date and hour;
(iv) Test or activity description;
(v) Test result;
(vi) Reason for test;
(vii) Test code.
(12) For each quality assurance test extension or exemption
request, the owner or operator shall record the following:
(i) For a RATA deadline extension or exemption request:
(A) Monitoring system identification code;
(B) Date of last RATA;
(C) RATA expiration date without extension;
(D) RATA expiration date with extension;
(E) Type of RATA extension of exemption claimed or lost;
(F) Year to date hours of fuel usage with a sulfur content >0.05
percent by weight; and
(G) Year to date hours of non-redundant back-up CEMS use at the
unit/stack.
(ii) For a linearity test quarterly exemption:
(A) Component/system identification code; and
(B) Basis for exemption.
(iii) For a quality assurance test extension claim based on a grace
period:
(A) Component/system identification code;
(B) Type of test;
(C) Beginning of grace period;
(D) Date and hour of completion of required quality assurance test
or maximum allowable grace period if no quality assurance test was
completed during the grace period; and
(E) Number of unit/stack operating hours from the beginning of the
grace period to the completion of the quality assurance test or the
maximum allowable grace period.
(13) An indication of which data have been excluded from the
quarterly span and range evaluations of the SO2 and
NOX monitors and the reasons for excluding the data, as
required in sections 2.1.1.5 and 2.1.2.5 of appendix A to this part.
For purposes of reporting under Sec. 75.64(a)(1), this information
shall be reported with the quarterly report as descriptive text
consistent with Sec. 75.64(g).
(b) Excepted monitoring systems for gas-fired and oil-fired units.
The owner or operator shall record the applicable information in this
section for each excepted monitoring system following the requirements
of appendix D to this part or appendix E to this part for determining
and recording emissions from an affected unit.
(1) For each oil-fired unit or gas-fired unit using the optional
procedures of appendix D to this part for determining SO2
mass emissions and/or heat input or the optional procedures of appendix
E to this part for determining NOX emission rate, for
certification and quality assurance testing of fuel flowmeters tested
against a reference fuel flow rate (i.e., flow rate another fuel
flowmeter under section 2.1.5.2 of appendix D to this part or flow rate
from a procedure according to a standard incorporated by reference
under section 2.1.5.1 of appendix D to this part):
(i) Date and hour of test completion;
(ii) Upper range value of the fuel flowmeter;
(iii) Flowmeter measurements during accuracy test (and mean of
values), including units of measure;
(iv) Reference flow rates during accuracy test (and mean of
values), including units of measure;
(v) Average flowmeter accuracy as a percent of upper range value
for low, mid, and high fuel flowrates;
(vi) Indicator of whether test method was a lab comparison to
reference meter or an in-line comparison against a master meter;
(vii) Test result (aborted, pass, or fail);
(viii) Component and system identification numbers of the fuel
flowmeter being tested;
[[Page 28147]]
(ix) Date and hour fuel flowmeter was reinstalled ( only for tests
not performed inline); and
(x) Description of fuel flowmeter calibration specification or
procedure (in the certification application, or periodically if a
different method is used for annual quality assurance testing).
(2) For each transmitter or transducer accuracy test for an
orifice-, nozzle-, or venturi-type flowmeter used under section 2.1.6
of appendix D to this part:
(i) Date of test;
(ii) Full-scale value of the transmitter or transducer;
(iii) Transmitter input (pre-calibration) prior to accuracy test,
including units of measure;
(iv) Expected transmitter output during accuracy test (reference
value from NIST-traceable equipment), including units of measure;
(v) Actual transmitter output during accuracy test, including units
of measure;
(vi) Transmitter or transducer accuracy as a percent of the full-
scale value;
(vii) Transmitter output level as a percent of the full-scale
value);
(viii) Transmitter or transducer accuracy, as a percent of full-
scale value, and overall accuracy (if applicable), as a percent of
upper range value;
(ix) Test and run number;
(x) Time of run (only for tests against another flowmeter inline);
(xi) Component and system identification numbers of the fuel
flowmeter being tested;
(xii) Transmitter or transducer type (differential pressure, static
pressure, or temperature); and
(xiii) Test result.
(3) For each visual inspection of the primary element or
transmitter or transducer accuracy test for an orifice-, nozzle-, or
venturi-type flowmeter under sections 2.1.6.1 through 2.1.6.6 of
appendix D to this part:
(i) Date of inspection/test;
(ii) Hour of completion of inspection/test;
(iii) Component and system identification numbers of the fuel
flowmeter being inspected/tested; and
(iv) Results of inspection/test (pass or fail).
(4) For fuel flowmeters that are tested using the flow-to-load
ratio procedures of section 2.1.7 of appendix D to this part:
(i) Test data for the fuel flowmeter flow-to-load ratio or gross
heat rate check, including:
(A) Component/system identification code;
(B) Calendar year and quarter;
(C) Indication of whether the test is for flow-to-load ratio or
gross heat rate;
(D) Test result;
(E) Number of hours excluded due to co-firing;
(F) Number of hours excluded due to ramping;
(G) Number of hours excluded for lower 10.0 percent range of
operation; and
(H) Quarterly average absolute percent difference between baseline
ratio (or baseline GHR) and hourly quarterly ratios (or GHR value).
(ii) Reference data for the fuel flowmeter flow-to-load ratio or
gross heat rate evaluation, including:
(A) Completion date and hour of most recent primary element
inspection;
(B) Completion date and hour of most recent flowmeter or
transmitter accuracy test;
(C) Beginning and hour of baseline period;
(D) Completion date and hour of baseline period;
(E) Average fuel flow rate;
(F) Average load;
(G) Baseline fuel flow-to-load ratio and fuel flow-to-load units of
measure;
(H) Baseline GHR and GHR units;
(I) Number of hours excluded due to ramping; and
(J) Number of hours excluded in lower 10.0 percent of range of
operation.
(5) For gas-fired peaking units or oil-fired peaking units using
the optional procedures of appendix E to this part, for each initial
performance, periodic, or quality assurance/quality control-related
test:
(i) For each run of emission data;
(A) Run start date and time;
(B) Run end date and time;
(C) Fuel flow rate (lb/hr, gal/hr, scf/hr, bbl/hr, or m\3\/hr);
(D) Gross calorific value (heat content) of fuel (Btu/lb or Btu/
scf);
(E) Density of fuel, and units of measure for fuel density (if
needed to convert mass to volume);
(F) Total heat input during the run (mmBtu);
(G) Hourly heat input rate for run (mmBtu/hr);
(H) Response time of the O2 and NOX reference method
analyzers;
(I) NOX concentration (ppm);
(J) O2 concentration (percent O2);
(K) NOX emission rate (lb/mmBtu);
(L) Fuel or fuel combination (by heat input fraction) combusted;
(M) Run number;
(N) Operating level;
(O) Elapsed time;
(P) Test number;
(Q) Monitoring system identification code for appendix E system,
and oil or fuel flow system;
(R) Heat input from oil and/or gas during the run;
(S) Volumetric flow of oil and/or gas during the run, and units of
measure for volumetric flow; and
(T) Mass fuel flow during the run.
(ii) For each unit load and heat input:
(A) Average NOX emission rate (lb/mmBtu);
(B) F-factor used in calculations;
(C) Average heat input rate (mmBtu/hr);
(D) Unit operating parametric data related to NOX
formation for that unit type (e.g., excess O2 level, water/
fuel ratio);
(E) Fuel or fuel combination (by heat input fraction) combusted;
(F) Completion date and time of last run in level; and
(G) Arithmetic mean of reference method values at this level.
(c) For units with add-on SO2 and NOX
emission controls following the provisions of Sec. 75.34(a)(1) or
(a)(2), the owner or operator shall keep the following records on-site
in the quality assurance/quality control plan required by section 1 in
appendix B to this part:
(1) A list of operating parameters for the add-on emission
controls, including parameters in Sec. 75.55(b), appropriate to the
particular installation of add-on emission controls; and
(2) The range of each operating parameter in the list that
indicates the add-on emission controls are properly operating.
(d) Excepted flow monitoring systems under appendix I. The owner or
operator shall record the applicable information in this section for
each certified excepted flow monitoring system under appendix I to this
part measuring and recording flow from an affected unit.
(1) Certification test records. Record the results of the following
tests:
(i) For each CO2 or O2 component monitor:
(A) 7-day calibration error tests, as specified in paragraph (a)(1)
of this section;
(B) Cycle time test, as specified in paragraph (a)(6) of this
section; and
(C) Linearity checks, as specified in paragraph (a)(3) of this
section.
(ii) For each appendix I flow monitoring system tested in a
component by component assessment:
(A) Flowmeter accuracy test data (or a statement of calibration, if
the flowmeter meets the accuracy standard by design), as specified in
paragraph (b)(1) of this section;
(B) Relative accuracy test and bias data for the CO2 (or
O2) monitor, as specified in paragraphs (a)(5) and (a)(7) of
this section; and
[[Page 28148]]
(C) Fuel sampling and analysis data, as specified in section 2.3 of
appendix I to this part.
(iii) For each appendix I flow monitoring system tested in a system
relative accuracy assessment:
(A) Relative accuracy test and bias data for the appendix I flow
monitoring system, as specified for a flow monitoring system in
paragraphs (a)(5) and (a)(7) of this section; and
(B) Fuel sampling and analysis data, as specified in section 2.3 of
appendix I to this part.
(2) Quality assurance/quality control test records. Record the
results of the following tests:
(i) For CO2 or O2 monitors:
(A) Daily calibration error tests, as specified in paragraph (a)(1)
of this section; and
(B) Quarterly linearity checks, as specified in paragraph (a)(3) of
this section.
(ii) For each appendix I flow monitoring system tested in a
component-by-component assessment:
(A) Flowmeter accuracy test data, as specified in paragraph (b)(1)
or (b)(2) of this section and paragraph (b)(3) or (b)(4) of this
section;
(B) Relative accuracy test and bias data for the CO2 (or
O2) monitor, as specified in paragraphs (a)(5) and (a)(7) of
this section; and
(C) Fuel sampling and analysis data, as specified in section 2.3 of
appendix I to this part.
(iii) For each appendix I flow monitoring system tested in a system
relative accuracy assessment:
(A) Relative accuracy test and bias data for the appendix I flow
monitoring system, as specified for a flow monitoring system in
paragraphs (a)(5) and (a)(7) of this section; and
(B) Fuel sampling and analysis data, as specified in section 2.3 of
appendix I to this part.
(e) Compliance dates. Beginning on January 1, 2000, the owner or
operator shall comply with this section only. Before January 1, 2000,
the owner or operator shall comply with either this section or
Sec. 75.56; except that if a regulatory option provided in another
section of this part 75 is exercised prior to January 1, 2000, then the
owner or operator shall comply with any provisions of this section that
support the regulatory option beginning with the date on which the
option is exercised.
41. Section 75.60 is amended by revising paragraphs (a), (b)(1),
and (b)(2) and by adding new paragraphs (b)(3), (b)(4), (b)(5) and
(b)(6) to read as follows:
Sec. 75.60 General provisions.
(a) The designated representative for any affected unit subject to
the requirements of this part shall comply with all reporting
requirements in this section and with the requirements of Sec. 72.21 of
this chapter for all submissions.
(b) * * *
(1) Initial certifications. The designated representative shall
submit initial certification applications according to Sec. 75.63.
(2) Recertifications. The designated representative shall submit
recertification applications according to Sec. 75.63.
(3) Monitoring plans. The designated representative shall submit
monitoring plans according to Sec. 75.62.
(4) Electronic quarterly reports. The designated representative
shall submit electronic quarterly reports according to Sec. 75.64.
(5) Other petitions and communications. The designated
representative shall submit petitions, correspondence, application
forms, designated representative signature, and petition-related test
results in hardcopy to the Administrator. Additional petition
requirements are specified in Secs. 75.66 and 75.67.
(6) Quality assurance RATA reports. If requested by the applicable
EPA Regional Office, appropriate State, and/or appropriate local air
pollution control agency, the designated representative shall submit
the quality assurance RATA report within 45 days after completing a
quality assurance RATA according to section 2.3.1 of appendix B to this
part, or within 15 days of receiving the request, whichever is later.
The designated representative shall report the hardcopy information
required by Sec. 75.59(a)(10) to the applicable EPA Regional Office,
appropriate State, and/or appropriate local air pollution control
agency that requested the RATA report.
* * * * *
42. Section 75.61 is amended by revising paragraphs (a)
introductory text, (a)(1) introductory text, and (b) and by adding a
new paragraph (a)(1)(iv) to read as follows:
Sec. 75.61 Notifications.
(a) Submission. The designated representative for an affected unit
(or owner or operator, as specified) shall submit notice to the
Administrator, to the appropriate EPA Regional Office, and to the
applicable State and local air pollution control agencies for the
following purposes, as required by this part.
(1) Initial certification and recertification test notifications.
The owner or operator or designated representative for an affected unit
shall submit written notification of initial certification tests,
recertification tests, and revised test dates as specified in
Sec. 75.20 for continuous emission monitoring systems, for alternative
monitoring systems under subpart E of this part, or for excepted
monitoring systems under appendix E or I to this part, except as
provided in paragraphs (a)(1)(iv) and (a)(4) of this section and except
for testing only of the data acquisition and handling system.
* * * * *
(iv) Waiver from notification requirements. The Administrator, the
appropriate EPA Regional Office, or the applicable State or local air
pollution control agency may issue a waiver from the requirement of
paragraph (a)(1) of this section to provide it for a unit or a group of
units for one or more recertification tests. The Administrator, the
appropriate EPA Regional Office, or the applicable State or local air
pollution control agency may also discontinue the waiver and enforce
the requirement of paragraph (a)(1) of this section to provide it
notice of recertification testing for future tests for a unit or a
group of units.
* * * * *
(b) The owner or operator or designated representative shall submit
notification of certification tests and recertification tests for
continuous opacity monitoring systems as specified in Sec. 75.20(c)(8)
to the State or local air pollution control agency.
* * * * *
43. Section 75.62 is amended by revising paragraphs (a) and (c) to
read as follows:
Sec. 75.62 Monitoring plan.
(a) Submission.--(1) Electronic. Using the format specified in
paragraph (c) of this section, the designated representative for an
affected unit shall submit a complete, electronic, up-to-date
monitoring plan file (except for hardcopy portions identified in
paragraph (a)(2) of this section) to the Administrator: No later than
45 days prior to the initial certification test; at the time of
recertification application submission; and in each electronic
quarterly report.
(2) Hardcopy. The designated representative shall submit all of the
hardcopy information required under Sec. 75.53 to the appropriate EPA
Regional Office and the appropriate State and/or local air pollution
control agency prior to initial certification. Thereafter, the
[[Page 28149]]
designated representative shall submit hardcopy information only if
that portion of the monitoring plan is revised. The designated
representative shall submit the required hardcopy information: no later
than 45 days prior to the initial certification test; with any
recertification application, if a hardcopy monitoring plan change is
associated with the recertification event; and within 30 days of any
other event with which a hardcopy monitoring plan change is associated,
pursuant to Sec. 75.53(b).
* * * * *
(c) Format. Each monitoring plan shall be submitted in a format
specified by the Administrator.
44. Section 75.63 is revised to read as follows:
Sec. 75.63 Initial certification or recertification application.
(a) Submission. The designated representative for an affected unit
or a combustion source shall submit applications and reports as
follows:
(1) Initial certifications. (i) Within 45 days after completing all
initial certification tests, submit to the Administrator the electronic
information required by paragraph (b)(1) of this section and a hardcopy
certification application form (EPA form 7610-14). Except for subpart E
applications or unless specifically requested by the Administrator, do
not submit a hardcopy of the test data and results to the
Administrator.
(ii) Within 45 days after completing all initial certification
tests, submit the hardcopy information required by paragraph (b)(2) of
this section to the applicable EPA Regional Office and the appropriate
State and/or local air pollution control agency.
(iii) For units for which the owner or operator is applying for
certification approval of the optional excepted methodology under
Sec. 75.19 for low mass emissions units, submit:
(A) To the Administrator, the electronic information required by
paragraph (b)(1)(i) of this section, the hardcopy information required
by paragraph (b)(3) of this section, and a hardcopy certification
application form (EPA form 7610-14) signed by the designated
representative.
(B) To the applicable EPA Regional Office and appropriate State
and/or local air pollution control agency, the hardcopy information
required by paragraphs (b)(2)(i), (iii), and (iv) of this section and
by paragraph (b)(3) of this section.
(2) Recertifications. (i) Within 45 days after completing all
recertification tests, submit to the Administrator the electronic
information required by (b)(1) of this section and a hardcopy
certification application form (EPA form 7610-14). Except for subpart E
applications or unless specifically requested by the Administrator, do
not submit a hardcopy of the test data and results to the
Administrator.
(ii) Within 45 days after completing all recertification tests,
submit the hardcopy information required by paragraph (b)(2) of this
section to the applicable EPA Regional Office and the appropriate State
and/or local air pollution control agency. The applicable EPA Regional
Office or appropriate State or local air pollution control agency may
waive the requirement for submission to it of a hardcopy
recertification. The applicable EPA Regional Office or the appropriate
State or local air pollution control agency may also discontinue the
waiver and enforce the requirement of this paragraph (a)(2)(ii) to
provide a hardcopy report of the recertification test data and results.
(iii) Notwithstanding the requirements of paragraphs (a)(2)(i) and
(a)(2)(ii) of this section, for an event for which the Administrator
determines that only diagnostic tests (see Sec. 75.20(b)) are required
rather than a RATA, an accuracy test of the fuel flowmeter, or a retest
of the appendix E NOX correlation curve, no hardcopy
submittal of any kind is required; however, the results of all
diagnostic test(s) shall be submitted in the electronic quarterly
report required under Sec. 75.64. For DAHS (missing data and formula)
verifications, neither a hardcopy nor an electronic submittal of any
kind is required; these test results shall be kept on-site, suitable
for inspection.
(b) Contents. Each application for initial certification or
recertification shall contain the following information, as applicable:
(1) Electronic. (i) A complete, up-to-date version of the
electronic portion of the monitoring plan, according to Sec. 75.53(c)
and (d), or Sec. 75.53(e) and (f), as applicable, in the format
specified in Sec. 75.62(c).
(ii) The results of the test(s) required by Sec. 75.20, including
the type of test conducted, testing date, information required by
Sec. 75.56 or Sec. 75.59, as applicable, and the results of any failed
tests that affect data validation.
(2) Hardcopy. (i) Any changed portions of the hardcopy monitoring
plan information required under Sec. 75.53(c) and (d), or Sec. 75.53(e)
and (f), as applicable.
(ii) The results of the test(s) required by Sec. 75.20, including
the type of test conducted, testing date, information required by
Sec. 75.59(a)(10), and the results of any failed tests that affect data
validation.
(iii) Certification or recertification application form (EPA form
7610-14).
(iv) Designated representative signature.
(3) If the owner or operator is applying to use the optional low
mass emissions excepted methodology in Sec. 75.19(c) in lieu of a
certified monitoring system,
(i) A statement that the unit burns only natural gas or fuel oil
and a list of the fuels that are burned or a statement that the unit is
projected to burn only natural gas or fuel oil and a list of the fuels
that are projected to be burned;
(ii) A statement that the unit meets the applicability requirements
in Sec. 75.19(a) and (b); and
(iii) Any unit historical actual and projected emissions data and
calculated emissions data demonstrating that the affected unit
qualifies as a low mass emissions unit under Sec. 75.19(a) and (b).
(c) Format. The electronic portion of each certification or
recertification application shall be submitted in a format to be
specified by the Administrator. The hardcopy test results shall be
submitted in a format suitable for review and shall include the
information in Sec. 75.59(a)(10).
45. Section 75.64 is amended by revising paragraphs (a)
introductory text, (d), and (e); by redesignating existing paragraphs
(a)(1), (a)(2), (a)(3), (a)(4), (a)(5), and (a)(6) as paragraphs
(a)(2), (a)(3), (a)(4), (a)(5),(a)(6) and (a)(8), respectively; by
revising newly designated paragraphs (a)(2), and (a)(4); by adding new
paragraphs (a)(1), (a)(7), (a)(9), (f), and (g); and by removing the
third sentence in paragraph (c), to read as follows:
Sec. 75.64 Quarterly reports.
(a) Electronic submission. The designated representative for an
affected unit shall electronically report the data and information in
paragraphs (a), (b), and (c) of this section to the Administrator
quarterly, beginning with the data from the later of: the last
(partial) calendar quarter of 1993 (where the calendar quarter data
begins at November 15, 1993), the calendar quarter corresponding to the
date of provisional certification, or the calendar quarter
corresponding to the relevant deadline for initial certification in
Sec. 75.4(a), (b), or (c), whichever quarter is earlier (where the
report contains hourly data beginning with the hour of provisional
certification or the hour corresponding to the relevant certification
deadline, whichever is earlier). For an affected unit subject to
[[Page 28150]]
Sec. 75.4(d) that is shutdown on the relevant compliance date in
Sec. 75.4(a), the owner or operator shall submit quarterly reports for
the unit beginning with the data from the quarter in which the owner or
operator recommences commercial operation of the unit (where the report
contains hourly data beginning with the first hour of recommenced
commercial operation of the unit). For any provisionally-certified
monitoring system, Sec. 75.20(a)(3) shall apply for initial
certifications, and Sec. 75.20(b)(5) shall apply for recertifications.
Each electronic report must be submitted to the Administrator within 30
days following the end of each calendar quarter. Each electronic report
shall include the date of report generation, for the information
provided in paragraphs (a)(2) through (a)(9) of this section, and shall
also include for each affected unit (or group of units using a common
stack):
(1) Facility information:
(i) Identification, including:
(A) Facility/ORISPL number;
(B) Calendar quarter and year data contained in the report; and
(C) EDR version used for the report.
(ii) Location, including:
(A) Plant name and facility ID;
(B) EPA AIRS facility system ID;
(C) State facility ID;
(D) Source category/type;
(E) Primary SIC code;
(F) State postal abbreviation;
(G) County code; and
(H) Latitude and longitude.
(2) The information and hourly data required in Secs. 75.53 through
75.59, excluding:
(i) Descriptions of adjustments, corrective action, and
maintenance;
(ii) Information which is incompatible with electronic reporting
(e.g., field data sheets, lab analyses, quality control plan);
(iii) Opacity data listed in Sec. 75.54(f) or Sec. 75.57(f), and in
Sec. 75.59(a)(9);
(iv) For units with SO2 or NOX add-on
emission controls that do not elect to use the approved site-specific
parametric monitoring procedures for calculation of substitute data,
the information in Sec. 75.55(b)(3) or Sec. 75.58(b)(3);
(v) The information recorded under Sec. 75.56(a)(7) for the period
prior to January 1, 2000;
(vi) Information required by Sec. 75.54(g) or Sec. 75.57(h)
concerning the causes of any missing data periods and the actions taken
to cure such causes; and
(vii) Hardcopy monitoring plan information required by Sec. 75.53
and hardcopy test data and results required by Sec. 75.56 or
Sec. 75.59;
(viii) Records of flow polynomial equations and numerical values
required by Sec. 75.56(a)(5)(vii) or Sec. 75.59(a)(5)(vi);
(ix) Daily fuel sampling information required by
Sec. 75.58(c)(3)(i) for units using assumed values under appendix D;
(x) Information required by Secs. 75.59(b)(1)(ii), (iii), (iv), and
(x), and (b)(2) concerning fuel flowmeter accuracy tests and
transmitter/transducer accuracy tests;
(xi) Stratification test results required as part of the RATA
supplementary records under Secs. 75.56(a)(7) or 75.59(a)(7);
(xii) Data and results of RATAs that are aborted or invalidated due
to problems with the reference method or operational problems with the
unit and data and results of linearity checks that are aborted or
invalidated due to operational problems with the unit; and
(xiii) The summary of data used to determine the percentage of
historical usage of each load level as required under
Sec. 75.59(a)(8)(iv).
(xiv) Supplementary RATA information required under
Secs. 75.59(a)(7)(iv)(A), (U), (V), (W), (X), and (Y).
* * * * *
(4) Average NOX emission rate (lb/mmBtu, rounded to the
nearest hundredth prior to January 1, 2000 and to the nearest
thousandth on and after January 1, 2000) during the quarter and
cumulative NOX emission rate for the calendar year.
* * * * *
(7) Unit/stack/pipe operating hours for quarter and cumulative
unit/stack/pipe operating hours for calendar year.
* * * * *
(9) For low mass emissions units for which the owner or operator is
using the optional low mass emissions methodology in Sec. 75.19(c) to
calculate NOX mass emissions, the designated representative
must also report tons (rounded to the nearest tenth) of NOX
emitted during the quarter and cumulative NOX mass emissions
for the calendar year.
* * * * *
(d) Electronic format. Each quarterly report shall be submitted in
a format to be specified by the Administrator, including both
electronic submission of data and electronic or hardcopy submission of
compliance certifications.
(e) Phase I qualifying technology reports. In addition to reporting
the information in paragraphs (a), (b), and (c) of this section, the
designated representative for an affected unit on which SO2
emission controls have been installed and operated for the purpose of
meeting qualifying Phase I technology requirements pursuant to
Sec. 72.42 of this chapter shall also submit reports documenting the
measured percent SO2 emissions removal to the Administrator
on a quarterly basis, beginning the first quarter of 1997 and
continuing through the fourth quarter of 1999. Each report shall
include all measurements and calculations necessary to substantiate
that the qualifying technology achieves the required percent reduction
in SO2 emissions.
(f) Method of submission. Beginning with the quarterly report for
the first quarter of the year 2000, all quarterly reports shall be
submitted to EPA by direct computer-to-computer electronic transfer via
modem and EPA-provided software, unless otherwise approved by the
Administrator.
(g) Any cover letter text accompanying a quarterly report shall
either be submitted in hardcopy to the Agency or be provided in
electronic format compatible with the other data required to be
reported under this section.
46. Section 75.65 is revised to read as follows:
Sec. 75.65 Opacity reports.
The owner or operator or designated representative shall report
excess emissions of opacity recorded under Sec. 75.54(f) or
Sec. 75.57(f), as applicable, to the applicable State or local air
pollution control agency.
47. Section 75.66 is amended by revising paragraphs (a) and the
first sentence of (e) introductory text; by redesignating paragraph (i)
as paragraph (m) and revising it; and by adding paragraphs (i) through
(l), to read as follows:
Sec. 75.66 Petitions to the Administrator.
(a) General. The designated representative for an affected unit
subject to the requirements of this part may submit a petition to the
Administrator requesting that the Administrator exercise his or her
discretion to approve an alternative to any requirement prescribed in
this part or incorporated by reference in this part. Any such petition
shall be submitted in accordance with the requirements of this section.
The designated representative shall comply with the signatory
requirements of Sec. 72.21 of this chapter for each submission.
* * * * *
(e) Parametric monitoring procedure petitions. The designated
representative for an affected unit may submit a petition to the
Administrator, where each petition shall contain the information
specified in Sec. 75.55(b) or
[[Page 28151]]
Sec. 75.58(b), as applicable, for the use of a parametric monitoring
method. * * *
* * * * *
(i) Emergency fuel petition. The designated representative for an
affected unit may submit a petition to the Administrator to use the
emergency fuel provisions in Section 2.1.4 of Appendix E of this part.
The designated representative shall include the following information
in the petition:
(1) Identification of the affected unit(s);
(2) A procedure for determining the NOX emission rate
for the unit when the emergency fuel is combusted; and
(3) A demonstration that the permit restricts use of the fuel to
emergencies only.
(j) Petition for alternative method of accounting for emissions
prior to completion of certification tests. The designated
representative for an affected unit may submit a petition to the
Administrator to use an alternative to the procedures in Sec. 75.4
(d)(3), (e)(3), (f)(3) and/or (g)(3) to account for emissions during
the period between the compliance date for a unit and the completion of
certification testing for that unit. The designated representative
shall include:
(1) Identification of the affected unit(s);
(2) A detailed explanation of the alternative method to account for
emissions of the following parameters, as applicable: SO2
mass emissions (in lbs), NOX emission rate (in lbs/mmbtu),
CO2 mass emissions (in lbs) and, if the unit is subject to
the requirements of subpart H of this part, NOX mass
emissions (in lbs); and
(3) A demonstration that the proposed alternative does not
underestimate emissions.
(k) Petition for an alternative to the stabilization criteria for
the cycle time test in section 6.4 of Appendix A of this part. The
designated representative for an affected unit may submit a petition to
the Administrator to use an alternative stabilization criteria for the
cycle time test in section 6.4 of Appendix A of this part, if the
installed monitoring system does not record data in 1-minute or 3-
minute intervals. The designated representative shall provide a
description of the alternative criteria.
(l) Petition for an alternative to the maximum rated hourly heat
input used to determine emissions under the low mass emissions excepted
methodology in Sec. 75.19. The designated representative for an
affected unit may submit a petition to the Administrator to use an
alternative to the maximum rated hourly heat input to determine
emissions under the low mass emissions excepted methodology set forth
in Sec. 75.19. The designated representative shall provide the
following information:
(1) Identification of the affected unit(s);
(2) Information demonstrating that the maximum rated hourly heat
input, as defined in Sec. 72.2 of this chapter, is not representative
of the unit's current capabilities because modifications have been made
to the unit, limiting its capacity permanently; and
(3) Information documenting that the proposed alternative maximum
heat input is representative of the unit's highest potential heat
input.
(m) Any other petitions to the Administrator under this part.
Except for petitions addressed in paragraphs (b) through (l) of this
section, any petition submitted under this paragraph shall include
sufficient information for the evaluation of the petition, including,
at a minimum, the following information:
(1) Identification of the affected unit(s);
(2) A detailed explanation of why the proposed alternative is being
suggested in lieu of the requirement;
(3) A description and diagram of any equipment and procedures used
in the proposed alternative, if applicable;
(4) A demonstration that the proposed alternative is consistent
with the purposes of the requirement for which the alternative is
proposed and is consistent with the purposes of this part and of
section 412 of the Act and that any adverse effect of approving such
alternative will be de minimis; and
(5) Any other relevant information that the Administrator may
require.
48. Subpart H is added to read as follows:
Subpart H--NOX Mass Emissions Provisions
Sec.
75.70 NOX mass emissions provisions.
75.71 Specific provisions for monitoring NOX emission
rate and heat input for the purpose of calculating NOX
mass emissions.
75.72 Determination of NOX mass emissions.
75.73 Recordkeeping and reporting.
Subpart H--NOX Mass Emissions Provisions
Sec. 75.70 NOX mass emissions provisions.
(a) The owner or operator of a unit shall comply with the
requirements of this subpart only if such compliance is required by an
applicable state or federal NOX mass emission reduction
program that incorporates by reference, or otherwise adopts the
requirements of, this subpart. For purposes of this subpart, the term
``affected unit'' shall mean any unit that is subject to a state or
federal NOX mass emission reduction program requiring
compliance with this subpart, the term ``nonaffected unit'' shall mean
any unit that is not subject to such a program, the term ``permitting
authority'' shall mean the permitting authority under an applicable
state or federal NOX mass emission reduction program that
adopts the requirements of this subpart, and the term ``designated
representative'' shall mean the responsible party under the applicable
state or federal NOX mass emission reduction program that
adopts the requirements of this subpart. In addition, as set forth in
this subpart, the provisions of subparts A, C, D, E, F, and G and
appendices A through G applicable to NOX emission rate and
heat input shall apply to the owner or operator of a unit required to
meet the requirements of this subpart by a state or federal
NOX mass emission reduction program, except that the term
``affected unit'' shall mean any unit that is subject to a state or
federal NOX mass emission reduction program requiring
compliance with this subpart, the term ``permitting authority'' shall
mean the permitting authority under an applicable state or federal
NOX mass emission reduction program that adopts the
requirements of this subpart, and the term ``designated
representative'' shall mean the responsible party under the applicable
state or federal NOX mass emission reduction program that
adopts the requirements of this subpart.
(b) Compliance dates. The owner or operator of an affected unit
shall meet the compliance deadlines established by an applicable state
or federal NOX mass emission reduction program that adopts
the requirements of this subpart.
(c) Prohibitions. (1) No owner or operator of an affected unit or a
non-affected unit under Sec. 75.72(b)(2)(ii) shall use any alternative
monitoring system, alternative reference method, or any other
alternative for the required continuous emission monitoring system
without having obtained prior written approval in accordance with
paragraph (g) of this section.
(2) No owner or operator of an affected unit or a non-affected unit
under Sec. 75.72(b)(2)(ii) shall operate the unit so as to discharge,
or allow to be discharged emissions of NOX to the atmosphere
without accounting for all such emissions in accordance with the
applicable provisions of this part.
(3) No owner or operator of an affected unit or a non-affected unit
under Sec. 75.72(b)(2)(ii) shall disrupt the continuous emission
monitoring system, any portion thereof, or any other
[[Page 28152]]
approved emission monitoring method, and thereby avoid monitoring and
recording NOX mass emissions discharged into the atmosphere,
except for periods of recertification or periods when calibration,
quality assurance testing, or maintenance is performed in accordance
with the applicable provisions of this part.
(4) No owner or operator of an affected unit or a non-affected unit
under Sec. 75.72(b)(2)(ii) shall retire or permanently discontinue use
of the continuous emission monitoring system, any component thereof, or
any other approved emission monitoring system under this part, except
under any one of the following circumstances:
(i) During the period that the unit is covered by a retired unit
exemption under Sec. 96.5 that is in effect;
(ii) The owner or operator is monitoring NOX mass
emissions from the affected unit with another certified monitoring
system approved, in accordance with the provisions of paragraph (d) of
this section; or
(iii) The designated representative submits notification of the
date of certification testing of a replacement monitoring system in
accordance with Sec. 75.73(d)(5).
(d) Initial certification and recertification procedures. (1) The
owner or operator of an affected unit that is subject to an Acid Rain
emissions limitation shall comply with the initial certification and
recertification procedures of this part except that:
(i) The owner or operator shall meet any additional requirements
set forth in an applicable state or federal NOX mass
emission reduction program that adopts the requirements of this
subpart.
(ii) For any additional NOX emission rate CEMS required
under the common stack provisions in Sec. 75.72, the owner or operator
shall meet the requirements of paragraph (d)(2) of this section.
(2) The owner or operator of an affected unit that is not subject
to an Acid Rain emissions limitation shall comply with the initial
certification and recertification procedures established by an
applicable state or federal NOX mass emission reduction
program that adopts the requirements of this subpart. The owner or
operator of an affected unit that is subject to an Acid Rain emissions
limitation shall, for any additional NOX emission rate CEMS
required under the common stack provisions in Sec. 75.72, comply with
the initial certification and recertification procedures established by
an applicable state or federal NOX mass emission reduction
program that adopts the requirements of this subpart.
(e) Quality assurance and quality control requirements. The owner
or operator shall meet the quality assurance and quality control
requirements in Sec. 75.21.
(f) Missing data procedures. Except as provided in Sec. 75.34, the
owner or operator shall provide substitute data for each affected unit
and each non-affected unit under Sec. 75.72(b)(2)(ii) using a
continuous emissions monitoring system in accordance with the missing
data procedures in subpart D of this part whenever the unit combusts
fuel and:
(1) A valid quality assured hour of NOX emission rate
data (in lb/mmBtu) has not been measured and recorded for an affected
unit or non-affected unit under Sec. 75.72(b)(2)(ii) by a certified
NOX continuous emission monitoring system or by an approved
monitoring system under subpart E of this part;
(2) A valid quality assured hour of flow data (in scfh) has not
been measured and recorded for an affected unit or non-affected unit
under Sec. 75.72(b)(2)(ii) from a certified flow monitor or by an
approved alternative monitoring system under subpart E of this part; or
(3) A valid quality assured hour of heat input data (in mmBtu) has
not been measured and recorded for an affected unit from a certified
flow monitor and a certified diluent (CO2 or O2)
monitor or by an approved alternative monitoring system under subpart E
of this part or by an accepted monitoring system under appendix D to
this part.
(g) Petitions. (1) The owner or operator of an affected unit that
is subject to an Acid Rain emissions limitation may submit a petition
to the Administrator requesting an alternative to any requirement of
this subpart. Such a petition shall meet the requirements of Sec. 75.66
and any additional requirements established by an applicable state or
federal NOX mass emission reduction program that adopts the
requirements of this subpart. Use of an alternative to any requirement
of this subpart is in accordance with this subpart and with such state
or federal NOX mass emission reduction program only to the
extent that the petition is approved by the Administrator, in
consultation with the permitting authority.
(2) Notwithstanding paragraph (g)(1) of this section, petitions
requesting an alternative to a requirement concerning any additional
CEMS required solely to meet the common stack provisions of Sec. 75.72,
shall be submitted to the permitting authority and the Administrator
and shall be governed by paragraph (g)(3)(ii) of this section. Such a
petition shall meet the requirements of Sec. 75.66 and any additional
requirements established by an applicable state or federal
NOX mass emission reduction program that adopts the
requirements of this subpart.
(3)(i) The owner or operator of an affected unit that is not
subject to an Acid Rain emissions limitation may submit a petition to
the permitting authority and the Administrator requesting an
alternative to any requirement of this subpart. Such a petition shall
meet the requirements of Sec. 75.66 and any additional requirements
established by an applicable state or federal NOX mass
emission reduction program that adopts the requirements of this
subpart.
(ii) Use of an alternative to any requirement of this subpart is in
accordance with this subpart only to the extent that it is approved by
both the permitting authority and the Administrator.
Sec. 75.71 Specific provisions for monitoring NOX emission
rate and heat input for the purpose of calculating NOX mass
emissions.
(a) Coal-fired units. The owner or operator of an affected unit
shall meet the general operating requirements in Sec. 75.10 for a
NOX continuous emission monitoring system (including a
NOX pollutant concentration monitor and an O2- or
CO2-diluent gas monitor) to measure NOX emission
rate and for a continuous flow monitoring system and an O2-
or CO2-diluent gas monitor to measure heat input, except as
provided by the Administrator in accordance with subpart E of this
part.
(b) Moisture correction. If a correction for the stack gas moisture
content is needed to properly calculate the NOX emission
rate in lb/mmBtu (i.e., if the NOX pollutant concentration
monitor measures on a different moisture basis from the diluent
monitor), the owner or operator of an affected unit shall install,
operate, maintain, and quality assure a continuous moisture monitoring
system, as defined in Sec. 75.11(b).
(c) Gas-fired nonpeaking units or oil-fired non-peaking units. The
owner or operator of an affected unit that qualifies as a gas-fired or
oil-fired unit but not as a peaking unit, as defined in Sec. 72.2 of
this chapter, based on information submitted by the designated
representative in the monitoring plan shall either:
(1) Meet the requirements of paragraph (a) of this section and, if
applicable, paragraph (b) of this section; or
(2) Meet the general operating requirements in Sec. 75.10 for a
NOX continuous emission monitoring system, except as
provided, where applicable, in paragraph (e)(2) of this section or by
the
[[Page 28153]]
Administrator in accordance with subpart E of this part, and use the
procedures specified in appendix D to this part for determining hourly
heat input. However, the heat input apportionment provisions in section
2.1.2 of appendix D to this part shall not be used to meet the
NOX mass reporting provisions of this subpart.
(d) Peaking units that combust natural gas or fuel oil. The owner
or operator of an affected unit that combusts only natural gas or fuel
oil and that qualifies as a peaking unit, as defined in Sec. 72.2 of
this chapter, based on information submitted by the designated
representative in the monitoring plan shall either:
(1) Meet the requirements of paragraph (c) of this section; or
(2) Use the procedures in appendix D to this part for determining
hourly heat input and the procedure specified in appendix E to this
part for estimating hourly NOX emission rate. However, the
heat input apportionment provisions in section 2.1.2 of appendix D to
this part shall not be used to meet the NOX mass reporting
provisions of this subpart. In addition, if after certification of an
excepted monitoring system under appendix E to this part, a unit's
operations exceed a capacity factor of 20.0 percent in any calender
year or exceed a capacity factor of 10.0 percent averaged over three
years, the owner or operator shall meet the requirements of paragraph
(c) of this section or, if applicable, paragraph (e) of this section by
no later than December 31 of the following calender year.
(e) Low mass emissions units. Notwithstanding the requirements of
paragraphs (c) and (d) of this section, the owner or operator of an
affected unit that qualifies as a low mass emissions unit under
Sec. 75.19(a) shall comply with one of the following:
(1) Meet the applicable requirements specified in paragraph (c) or
(d) of this section for monitoring NOX emission rate and
heat input; or
(2) Use the low mass emissions excepted methodology in
Sec. 75.19(c) for estimating hourly emission rate, hourly heat input,
and hourly NOX mass emissions.
(f) Other units. The owner or operator of an affected unit that
combusts wood, refuse, or other materials shall comply with the
monitoring provisions specified in paragraph (a) of this section and,
where applicable, paragraph (b) of this section.
Sec. 75.72 Determination of NOX mass emissions.
The owner or operator of an affected unit shall calculate hourly
NOX mass emissions (in lbs) by multiplying the hourly
NOX emission rate (in lbs/mmBtu) by the hourly heat input
(in mmBtu/hr) and the hourly operating time (in hr). The owner or
operator shall also calculate quarterly and cumulative year-to-date
NOX mass emissions and cumulative NOX mass
emissions for the ozone season (in tons) by summing the hourly
NOX mass emissions according to the procedures in section 8
of appendix F to this part.
(a) Unit utilizing common stack with other affected unit(s). When
an affected unit utilizes a common stack with one or more affected
units, but no nonaffected units, the owner or operator shall either:
(1) Record the combined NOX mass emissions for the units
exhausting to the common stack, install, certify, operate, and maintain
a NOX continuous emissions monitoring system in the common
stack and:
(i) Install, certify, operate, and maintain a continuous flow
monitoring system at the common stack; or
(ii) If all of the units using the common stack are eligible to use
the procedures in appendix D to this part, use the procedures in
appendix D to this part to determine heat input for each affected unit
and use the combined heat input of all of the units exhausting to the
common stack for calculating NOX mass emissions; however,
the heat input apportionment provisions in section 2.1.2 of appendix D
to this part shall not be used to meet the NOX mass
reporting provisions of this subpart; or
(2) Install, certify, operate, and maintain a NOX
continuous emissions monitoring system in the duct to the common stack
from each affected unit and:
(i) Install, certify, operate, and maintain a flow monitor in the
duct to the common stack from each affected unit; or
(ii)(A) For any unit using the common stack and eligible to use the
procedures in appendix D to this part, use the procedures in appendix D
to determine heat input for that affected unit. However, the heat input
apportionment provisions in section 2.1.2 of appendix D to this part
shall not be used to meet the mass reporting provisions of this
subpart; and
(B) Install, certify, operate, and maintain a flow monitor in the
duct to the common stack for each remaining affected unit.
(b) Unit utilizing common stack with nonaffected unit(s). When one
or more affected units utilizes a common stack with one or more
nonaffected units, the owner or operator shall either:
(1) Install, certify, operate, and maintain a NOX
continuous emission monitoring system in the duct to the common stack
from each affected unit; and
(i) Install, certify, operate, and maintain a continuous flow
monitoring system in the duct to the common stack from each affected
unit; or
(ii)(A) For any unit using the common stack and eligible to use the
procedures in appendix D to this part, use the procedures in appendix D
to determine heat input for that affected unit; however, the heat input
apportionment provisions in section 2.1.2 of appendix D to this part
shall not be used to meet the mass reporting provisions of this
subpart; and
(B) Install, certify, operate, and maintain a flow monitor in the
duct to the common stack for each remaining affected unit that exhausts
to the common stack; or
(2) Install, certify, operate, and maintain a NOX
continuous emission monitoring system in the common stack; and
(i) Designate the nonaffected units as affected units in accordance
with the applicable state or federal NOX mass emissions
reduction program and meet the requirements of paragraph (a)(1) of this
section; or
(ii)(A) Install, certify, operate, and maintain a continuous flow
monitoring system in the common stack and a NOX continuous
emission monitoring system in the duct to the common stack from each
nonaffected unit and either install, certify, operate, and maintain a
continuous flow monitoring system in the duct from each nonaffected
unit or, for any nonaffected unit exhausting to the common stack and
otherwise eligible to use the procedures in appendix D to this part,
determine heat input using the procedures in appendix D for that
nonaffected unit (however, the heat input apportionment provisions in
section 2.1.2 of appendix D to this part shall not be used to meet the
NOX mass reporting provisions of this subpart), and for any
remaining nonaffected unit that exhausts to the common stack, install,
certify, operate, and maintain a flow monitor in the duct to the common
stack; and
(B) Submit a petition to the permitting authority and the
Administrator to allow a method of calculating and reporting the
NOX mass emissions from the affected units as the difference
between NOX mass emissions measured in the common stack and
NOX mass emissions measured in the ducts of the nonaffected
units, not to be reported as an hourly value less than zero. The
permitting authority and the
[[Page 28154]]
Administrator may approve such a method whenever the designated
representative demonstrates, to the satisfaction of the permitting
authority and the Administrator, that the method ensures that the
NOX mass emissions from the affected units are not
underestimated; or
(iii) Install a continuous flow monitoring system in the common
stack and record the combined emissions from all units as the combined
NOX mass emissions for the affected units for recordkeeping
and compliance purposes; or
(iv) Submit a petition to the permitting authority and the
Administrator to allow use of a method for apportioning NOX
mass emissions measured in the common stack to each of the units using
the common stack and for reporting the NOX mass emissions.
The permitting authority and the Administrator may approve such a
method whenever the designated representative demonstrates, to the
satisfaction of the permitting authority and the Administrator, that
the method ensures that the NOX mass emissions from the
affected units are not underestimated.
(c) Unit with bypass stack. Whenever any portion of the flue gases
from an affected unit can be routed to avoid the installed
NOX continuous emissions monitoring system, the owner and
operator shall either:
(1) Install, certify, operate, and maintain a NOX
continuous emissions monitoring system and a continuous flow monitoring
system on the bypass flue, duct, or stack gas stream and calculate
NOX mass emissions for the unit as the sum of the emissions
recorded by all required monitoring systems; or
(2) Monitor NOX mass emissions on the bypass flue, duct,
or stack gas stream using the reference methods in Sec. 75.22(b) for
NOX concentration, flow, and diluent and calculate
NOX mass emissions for the unit as the sum of the emissions
recorded by the installed monitoring systems on the main stack and the
emissions measured by the reference method monitoring systems.
(d) Unit with multiple stacks. Notwithstanding Sec. 75.17(c), when
the flue gases from an affected unit utilize two or more ducts feeding
into two or more stacks (which may include flue gases from other
affected or nonaffected unit(s)), or when the flue gases from an
affected unit utilize two or more ducts feeding into a single stack and
the owner or operator chooses to monitor in the ducts rather than in
the stack, the owner or operator shall either:
(1) Install, certify, operate, and maintain a NOX
continuous emission monitoring system and a continuous flow monitoring
system in each duct feeding into the stack or stacks and determine
NOX mass emissions from each affected unit using the stack
or stacks as the sum of the NOX mass emissions recorded for
each duct; or
(2) Install, certify, operate, and maintain a NOX
continuous emissions monitoring system and a continuous flow monitoring
system in each stack, and determine NOX mass emissions from
the affected unit using the sum of the NOX mass emissions
recorded for each stack, except that where another unit also exhausts
flue gases to one or more of the stacks, the owner or operator shall
also comply with the applicable requirements of paragraphs (a) and (b)
of this section to determine and record NOX mass emissions
from the units using that stack; or
(3) If the unit is eligible to use the procedures in appendix D to
this part, install, certify, operate, and maintain a NOX
continuous emissions monitoring system in one of the ducts feeding into
the stack or stacks and use the procedures in appendix D to this part
to determine heat input for the unit, provided that:
(i) There are no add-on NOX controls at the unit;
(ii) The unit is not capable of emitting solely through an
unmonitored stack (i.e., has no dampers); and
(iii) The owner or operator of the unit demonstrates to the
satisfaction of the permitting authority and the Administrator that the
NOX emission rate in the monitored duct or stack is
representative of the NOX emission rate in each duct or
stack.
Sec. 75.73 Recordkeeping and reporting.
(a) General recordkeeping provisions. The owner or operator of any
affected unit shall maintain for each affected unit and each non-
affected unit under Sec. 75.72(b)(2)(ii) a file of all measurements,
data, reports, and other information required by this part at the
source in a form suitable for inspection for at least three (3) years
from the date of each record. Except for the certification data
required in Sec. 75.57(a)(4) and the initial submission of the
monitoring plan required in Sec. 75.57(a)(5), the data shall be
collected beginning with the earlier of the date of provisional
certification or the deadline in Sec. 75.70. The certification data
required in Sec. 75.57(a)(4) shall be collected beginning with the date
of the first certification test performed.
The file shall contain the following information:
(1) The information required in Secs. 75.57(a)(2), (a)(4), (a)(5),
(a)(6), (b), (c)(2), (d), (g), and (h);
(2) The information required in Secs. 75.58 (b), (d), and (g);
(3) For each hour when the unit is operating, NOX mass
emissions, calculated in accordance with section 8.1 of appendix F to
this part;
(4) During the second and third calendar quarters, cumulative ozone
season heat input and cumulative ozone season operating hours;
(5) Heat input and NOX methodologies for the hour;
(6) Specific heat input record provisions for gas-fired or oil-
fired units using the procedures in appendix D to this part. In lieu of
the information required in Sec. 75.57(c)(2), the owner or operator
shall record the following information in this paragraph for each
affected gas-fired or oil-fired unit and each non-affected gas-or oil-
fired unit under Sec. 75.72(b)(2)(ii) for which the owner or operator
is using the procedures in appendix D to this part for estimating heat
input:
(i) For each hour when the unit is combusting oil:
(A) Date and hour;
(B) Hourly average flow rate of oil, while the unit combusts oil
(in gal/hr, lb/hr, m3/hr, or bbl/hr, rounded to the nearest
tenth) (flag value if derived from missing data procedures);
(C) Method of oil sampling (flow proportional, continuous drip, as
delivered, manual from storage tank, or daily manual);
(D) Mass rate of oil combusted each hour (in lb/hr, rounded to the
nearest tenth) (flag value if derived from missing data procedures);
(E) For units using volumetric oil flowmeters, density of oil (flag
value if derived from missing data procedures);
(F) Gross calorific value (heat content) of oil used to determine
heat input (in Btu/mass unit) (flag value if derived from missing data
procedures);
(G) Hourly heat input rate from oil, according to procedures in
appendix F to this part (in mmBtu/hr, to the nearest tenth);
(H) Fuel usage time for combustion of oil during the hour (rounded
up to the nearest fraction of an hour (in equal increments that can
range from one hundredth to one quarter of an hour, at the option of
the owner or operator)) (flag to indicate multiple/single fuel types
combusted); and
(I) Monitoring system identification code;
(ii) For gas-fired units or oil-fired units, using the procedures
in appendix D to this part with an assumed density or for as-delivered
fuel sampled from each delivery:
[[Page 28155]]
(A) Measured GCV and, if applicable, density from each fuel sample;
and
(B) Assumed GCV and, if applicable, density used to calculate heat
input rate;
(iii) For each hour when the unit is combusting gaseous fuel:
(A) Date and hour;
(B) Hourly heat input rate from gaseous fuel, according to
procedures in appendix F to this part (in mmBtu/hr, rounded to the
nearest tenth);
(C) Hourly flow rate of gaseous fuel, while the unit combusts gas
(in 100 scfh) (flag value if derived from missing data procedures);
(D) Gross calorific value (heat content) of gaseous fuel used to
determine heat input rate (in Btu/100 scf) (flag value if derived from
missing data procedures);
(E) Heat input rate from gaseous fuel, while the unit combusts gas
(in mmBtu/hr, rounded to the nearest tenth);
(F) Fuel usage time for combustion of gaseous fuel during the hour
(rounded up to the nearest fraction of an hour (in equal increments
that can range from one hundredth to one quarter of an hour, at the
option of the owner or operator)) (flag to indicate multiple/single
fuel types combusted); and
(G) Monitoring system identification code;
(iv) For each oil sample or sample of diesel fuel:
(A) Date of sampling;
(B) Gross calorific value or heat content (in Btu/lb) (flag value
if derived from missing data procedures); and
(C) Density or specific gravity, if required to convert volume to
mass (flag value if derived from missing data procedures);
(v) For each sample of gaseous fuel:
(A) Date of sampling; and
(B) Gross calorific value or heat content (in Btu/100 scf) (flag
value if derived from missing data procedures);
(vi) For each oil sample or sample of gaseous fuel:
(A) Type of oil or gas; and
(B) Percent carbon or F-factor of fuel;
(7) Specific NOX, record provisions for gas-fired or
oil-fired units using the optional low mass emissions excepted
methodology in Sec. 75.19. In lieu of recording the information in
Sec. 75.57(b), (c)(2), (d), and (g), the owner or operator shall
record, for each hour when the unit is operating for any portion of the
hour, the following information for each affected low mass emissions
unit for which the owner or operator is using the low mass emissions
excepted methodology in Sec. 75.19(c):
(i) Date and hour;
(ii) If one type of fuel is combusted in the hour, fuel type
(pipeline natural gas, natural gas, residual oil, or diesel fuel) or,
if more than one type of fuel is combusted in the hour, the fuel type
which results in the highest emission factors for NOX;
(iii) Average hourly NOX emission rate (in lb/mmBtu,
rounded to the nearest thousandth); and
(iv) Hourly NOX mass emissions (in lbs, rounded to the
nearest tenth).
(b) Certification, quality assurance and quality control record
provisions. The owner or operator of any affected unit shall record the
applicable information in Sec. 75.59 for each affected unit or group of
units monitored at a common stack and each non-affected unit under
Sec. 75.72(b)(2)(ii).
(c) Monitoring plan record provisions. (1) General provisions. The
owner or operator of an affected unit shall prepare and maintain a
monitoring plan for each affected unit or group of units monitored at a
common stack and each non-affected unit under Sec. 75.72(b)(2)(ii).
Except as provided in paragraph (d) or (f) of this section, a
monitoring plan shall contain sufficient information on the continuous
emission monitoring systems, excepted methodology under Sec. 75.19, or
excepted monitoring systems under appendix D or E to this part and the
use of data derived from these systems to demonstrate that all the
unit's NOX emissions are monitored and reported.
(2) Whenever the owner or operator makes a replacement,
modification, or change in the certified continuous emission monitoring
system, excepted methodology under Sec. 75.19, excepted monitoring
system under appendix D or E to this part, or alternative monitoring
system under subpart E of this part, including a change in the
automated data acquisition and handling system or in the flue gas
handling system, that affects information reported in the monitoring
plan (e.g., a change to a serial number for a component of a monitoring
system), then the owner or operator shall update the monitoring plan.
(3) Contents of the monitoring plan for units not subject to an
Acid Rain emissions limitation. Each monitoring plan shall contain the
information in Sec. 75.53(e)(1) in electronic format and the
information in Sec. 75.53(e)(2) in hardcopy format. In addition, to the
extent applicable, each monitoring plan shall contain the information
in Sec. 75.53(f)(1)(i), (f)(2)(i), and (f)(4) in electronic format and
the information in Sec. 75.53(f)(1)(ii) and (f)(2)(ii) in hardcopy
format.
(d) General reporting provisions. (1) The designated representative
for an affected unit shall comply with all reporting requirements in
this section and with any additional requirements set forth in an
applicable state or Federal NOX mass emission reduction
program that adopts the requirements of this subpart.
(2) The designated representative for an affected unit shall submit
the following for each affected unit or group of units monitored at a
common stack and each non-affected unit under Sec. 75.72(b)(2)(ii);
(i) Initial certification applications in accordance with
Sec. 75.70(d);
(ii) Monitoring plans in accordance with paragraph (e) of this
section; and
(iii) Quarterly reports in accordance with paragraph (f) of this
section.
(3) Other petitions and communications. The designated
representative for an affected unit shall submit petitions,
correspondence, application forms, and petition-related test results in
accordance with the provisions in Sec. 75.70(g).
(4) Quality assurance RATA reports. If requested by the permitting
authority, the designated representative of an affected unit shall
submit the quality assurance RATA report for each affected unit or
group of units monitored at a common stack and each non-affected unit
under Sec. 75.72(b)(2)(ii) by the later of 45 days after completing a
quality assurance RATA according to section 2.3 of appendix B to this
part or 15 days of receiving the request. The designated representative
shall report the hardcopy information required by Sec. 75.59(a)(10) to
the permitting authority.
(5) Notifications. The designated representative for an affected
unit shall submit written notice to the permitting authority according
to the provisions in Sec. 75.61 for each affected unit or group of
units monitored at a common stack and each non-affected unit under
Sec. 75.72(b)(2)(ii).
(e) Monitoring plans. (1) Submission.
(i) Electronic. The designated representative for an affected unit
shall submit a complete, electronic, up-to-date monitoring plan file
(except for hardcopy portions identified in paragraph (e)(1)(ii) of
this section) for each affected unit or group of units monitored at a
common stack and each non-affected unit under Sec. 75.72(b)(2)(ii) as
follows:
(A) To the permitting authority, no later than 45 days prior to the
initial certification test and at the time of recertification
application submission; and
(B) To the Administrator, no later than 45 days prior to the
initial certification test, at the time of recertification application
submission, and in each electronic quarterly report.
(ii) Hardcopy. The designated representative of an affected unit
shall
[[Page 28156]]
submit all of the hardcopy information required under Sec. 75.53, for
each affected unit or group of units monitored at a common stack and
each non-affected unit under Sec. 75.72(b)(2)(ii), to the permitting
authority prior to initial certification. Thereafter, the designated
representative shall submit hardcopy information only if that portion
of the monitoring plan is revised. The designated representative shall
submit the required hardcopy information: no later than 45 days prior
to the initial certification test; with any recertification
application, if a hardcopy monitoring plan change is associated with
the recertification event; and within 30 days of any other event with
which a hardcopy monitoring plan change is associated, pursuant to
Sec. 75.53(b).
(2) [Reserved]
(f) Quarterly reports. (1) Electronic submission. The designated
representative for an affected unit shall electronically report the
data and information in this paragraph (f)(1) and in paragraphs (f)(2)
and (3) of this section to the Administrator quarterly. Each electronic
report shall include the date of report generation, for the information
provided in paragraphs (f)(1)(ii) through (f)(1)(vi) of this section,
and shall also include for each affected unit or group of units
monitored at a common stack:
(i) Facility information:
(A) Identification, including:
(1) Facility/ORISPL number;
(2) Calendar quarter and year data contained in the report; and
(3) EDR version used for the report;
(B) Location, including:
(1) Plant name and facility ID;
(2) EPA AIRS facility system ID;
(3) State facility ID;
(4) Source category/type;
(5) Primary SIC code;
(6) State postal abbreviation;
(7) County code; and
(8) Latitude and longitude;
(ii) The information and hourly data required in paragraph (a) of
this section, except for:
(A) Descriptions of adjustments, corrective action, and
maintenance;
(B) Information which is incompatible with electronic reporting
(e.g., field data sheets, lab analyses, quality control plan);
(C) For units with NOX add-on emission controls that do
not elect to use the approved site-specific parametric monitoring
procedures for calculation of substitute data, the information in
Sec. 75.58(b)(3);
(D) Information required by Sec. 75.57(h) concerning the causes of
any missing data periods and the actions taken to cure such causes;
(E) Hardcopy monitoring plan information required by Sec. 75.53 and
hardcopy test data and results required by Sec. 75.59;
(F) Records of flow polynomial equations and numerical values
required by Sec. 75.59(a)(5)(vi);
(G) Daily fuel sampling information required by Sec. 75.58(c)(3)(i)
for units using assumed values under appendix D;
(H) Information required by Sec. 75.59(b)(2) concerning
transmitter/transducer accuracy tests;
(I) Stratification test results required as part of the RATA
supplementary records under Sec. 75.56(a)(7) or Sec. 75.59(a)(7);
(J) Data and results of RATAs that are aborted or invalidated due
to problems with the reference method or operational problems with the
unit and data and results of linearity checks that are aborted or
invalidated due to operational problems with the unit; and
(K) The summary of data used to determine the percentage of
historical usage of each load level as required under
Sec. 75.59(a)(8)(iv);
(iii) Average NOX emission rate (lb/mmBtu, rounded to
the nearest thousandth) during the quarter and cumulative
NOX emission rate for the calendar year;
(iv) Tons of NOX emitted during quarter, cumulative tons
of NOX emitted during the year, and, during the second and
third calender quarters, cumulative tons of NOX emitted
during the ozone season;
(v) During the second and third calender quarters, cummulative heat
input for the ozone season; and
(vi) Unit/stack/pipe operating hours for quarter, cumulative unit/
stack/pipe operating hours for calendar year, and, during the second
and third calender quarters, cumulative operating hours during the
ozone season.
(2) The designated representative shall affirm that the component/
system identification codes and formulas in the quarterly electronic
reports submitted to the Administrator pursuant to paragraph (e) of
this section represent current operating conditions.
(3) Compliance certification. The designated representative shall
submit and sign a compliance certification in support of each quarterly
emissions monitoring report based on reasonable inquiry of those
persons with primary responsibility for ensuring that all of the unit's
emissions are correctly and fully monitored. The certification shall
state that:
(i) The monitoring data submitted were recorded in accordance with
the applicable requirements of this part, including the quality
assurance procedures and specifications; and
(ii) With regard to a unit with add-on emission controls and for
all hours where data are substituted in accordance with
Sec. 75.34(a)(1), the add-on emission controls were operating within
the range of parameters listed in the monitoring plan and the
substitute values do not systematically underestimate NOX
emissions.
(4) The designated representative shall comply with all of the
quarterly reporting requirements in Secs. 75.64(d), (f), and (g).
Appendix A to Part 75--Specifications and Test Procedures
Appendix A--[Amended]
49.-53. Appendix A to part 75 is amended by revising section 2.1 to
read as follows:
* * * * *
2. Equipment Specifications
2.1 Instrument Span and Range
In implementing sections 2.1.1 through 2.1.5 of this appendix,
set the measurement range for each parameter (SO2,
NOX, CO2, O2, or flow rate) high
enough to prevent full-scale exceedances from occurring, yet low
enough to ensure good measurement accuracy and to maintain a high
signal-to-noise ratio. To meet these objectives, it is recommended
that the range be selected such that the readings obtained during
typical unit operation are kept, to the extent practicable, between
20.0 and 80.0 percent of full-scale range of the instrument. Note
that this guideline does not apply to: (1) SO2 readings
obtained during the combustion of natural gas or fuel with a total
sulfur content no greater than the total sulfur content of natural
gas; (2) SO2 or NOX readings recorded on the
high measurement range, for units with SO2 or
NOX emission controls and two span values; or (3)
SO2 or NOX readings less than 20.0 percent of
full-scale on the low measurement range for a dual span unit with
SO2 or NOX emission controls, provided that
the readings occur during periods of high control device efficiency.
2.1.1 SO2 Pollutant Concentration Monitors
Determine, as indicated below, the span value(s) and range(s)
for an SO2 pollutant concentration monitor so that all
potential and expected concentrations can be accurately measured and
recorded. Note that if a unit exclusively combusts fuel(s) with a
total sulfur content no greater than the total sulfur content of
natural gas (i.e., 0.05 percent sulfur by weight), the
SO2 monitor span requirements in Sec. 75.11(e)(3)(iv)
apply in lieu of the requirements of this section.
2.1.1.1 Maximum Potential Concentration
Make an initial determination of the maximum potential
concentration (MPC) of SO2 by using Equation A-1a or A-
1b. Base the MPC calculation on the maximum percent sulfur and the
minimum gross calorific value (GCV) for the highest-sulfur
[[Page 28157]]
fuel to be burned. The maximum sulfur content and minimum GCV shall
be determined from all available fuel sampling and analysis data for
that fuel from the previous 12 months (minimum), excluding clearly
anomalous fuel sampling results. If the designated representative
certifies that the highest-sulfur fuel is never burned alone in the
unit during normal operation but is always blended or co-fired with
other fuel(s), the MPC may be calculated using a best estimate of
the highest sulfur content and lowest gross calorific value expected
for the blend or fuel mixture and inserting these values into
Equation A-1a or A-1b. Derive the best estimate of the highest
percent sulfur and lowest GCV for a blend or fuel mixture from
weighted-average values based upon the historical composition of the
blend or mixture in the previous 12 (or more) months. If
insufficient representative fuel sampling data are available to
determine the maximum sulfur content and minimum GCV, use values
from contract(s) for the fuel(s) that will be combusted by the unit
in the MPC calculation.
Alternatively, if a certified SO2 CEMS is already
installed, the owner or operator may make the initial MPC
determination based upon quality assured historical data recorded by
the CEMS. If this option is chosen, the MPC shall be the maximum
SO2 concentration observed during the previous 720 (or
more) quality assured monitor operating hours when combusting the
highest-sulfur fuel (or highest-sulfur blend if fuels are always
blended or co-fired) that is to be combusted in the unit or units
monitored by the SO2 monitor. For units with
SO2 emission controls, the certified SO2
monitor used to determine the MPC must be located at or before the
control device inlet. Report the MPC and the method of determination
in the monitoring plan required under Sec. 75.53.
When performing fuel sampling to determine the MPC, use ASTM
Methods: ASTM D3177-89, ``Standard Test Methods for Total Sulfur in
the Analysis Sample of Coal and Coke''; ASTM D4239-85, ``Standard
Test Methods for Sulfur in the Analysis Sample of Coal and Coke
Using High Temperature Tube Furnace Combustion Methods''; ASTM
D4294-90, ``Standard Test Method for Sulfur in Petroleum Products by
Energy-Dispersive X-Ray Fluorescence Spectroscopy''; ASTM D1552-90,
``Standard Test Method for Sulfur in Petroleum Products (High
Temperature Method)''; ASTM D129-91, ``Standard Test Method for
Sulfur in Petroleum Products (General Bomb Method)''; ASTM D2622-92,
``Standard Test Method for Sulfur in Petroleum Products by X-Ray
Spectrometry'' for sulfur content of solid or liquid fuels; ASTM
D3176-89, ``Standard Practice for Ultimate Analysis of Coal and
Coke''; ASTM D240-87 (Reapproved 1991), ``Standard Test Method for
Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb
Calorimeter''; or ASTM D2015-91, ``Standard Test Method for Gross
Calorific Value of Coal and Coke by the Adiabatic Bomb Calorimeter''
for GCV (incorporated by reference under Sec. 75.6).
[GRAPHIC] [TIFF OMITTED] TP21MY98.002
(Eq. A-1a)
or
[GRAPHIC] [TIFF OMITTED] TP21MY98.003
(Eq. A-1b)
Where:
MPC=Maximum potential concentration (ppm, wet basis). To convert to
dry basis, divide the MPC by 0.9).
MEC=Maximum expected concentration (ppm, wet basis). To convert to
dry basis, divide the MEC by 0.9).
%S=Maximum sulfur content of the fuel to be fired, wet basis, weight
percent, as determined by ASTM D3177-89, ASTM D4239-85, ASTM D4294-
90, ASTM D1552-90, ASTM D129-91, or ASTM D2622-92 for solid or
liquid fuels (incorporated by reference under Sec. 75.6).
%O2w=Minimum oxygen concentration, percent wet basis,
under typical operating conditions.
%CO2w=Maximum carbon dioxide concentration, percent wet
basis, under typical operating conditions.
11.32 x 106=Oxygen-based conversion factor in (Btu/
lb)(ppm)/%.
66.93 x 106=Carbon dioxide-based conversion factor in
(Btu/lb)(ppm)/%.
Note: All percentage values to be inserted in the equations of
this section are to be expressed as a percentage, not a fractional
value (e.g., 3, not .03).
2.1.1.2 Maximum Expected Concentration
Make an initial determination of the maximum expected
concentration (MEC) of SO2 whenever: (a) SO2
emission controls are used; or (b) both high-sulfur and low-sulfur
fuels (e.g., high-sulfur coal and low-sulfur coal or different
grades of fuel oil) or high-sulfur and low-sulfur fuel blends are
combusted as primary or backup fuels in a unit without
SO2 emission controls. For units with SO2
emission controls, use Equation A-2 to make the initial MEC
determination. When high-sulfur and low-sulfur fuels or blends are
burned as primary or backup fuels in a unit without SO2
controls, use Equation A-1a or A-1b to calculate the initial MEC
value for each fuel or blend, except for: (1) the highest-sulfur
fuel or blend (for which the MPC was previously calculated in
section 2.1.1.1 of this appendix); (2) fuels or blends with a total
sulfur content no greater than the total sulfur content of natural
gas, i.e., 0.05 percent sulfur by weight; or (3) fuels
or blends that are used only for unit startup.
For each MEC determination, substitute into Equation A-1a or A-
1b the highest sulfur content and minimum GCV value for that fuel or
blend, based upon all available fuel sampling and analysis results
from the previous 12 months (or more), or, if fuel sampling data are
unavailable, based upon fuel contract(s).
Alternatively, if a certified SO2 CEMS is already
installed, the owner or operator may make the initial MEC
determination(s) based upon historical monitoring data. If this
option is chosen for a unit with SO2 emission controls,
the MEC shall be the maximum SO2 concentration measured
downstream of the control device outlet by the CEMS over the
previous 720 (or more) quality assured monitor operating hours with
the unit and the control device both operating normally. For units
that burn high- and low-sulfur fuels or blends as primary and backup
fuels and have no SO2 emission controls, the MEC for each
fuel shall be the maximum SO2 concentration measured by
the CEMS over the previous 720 (or more) quality assured monitor
operating hours in which that fuel or blend was the only fuel being
burned in the unit.
[GRAPHIC] [TIFF OMITTED] TP21MY98.004
(Eq. A-2)
where:
MEC=Maximum expected concentration (ppm).
MPC=Maximum potential concentration (ppm), as determined by Eq. A-1a
or A-1b.
RE=Expected average design removal efficiency of control equipment
(percent).
2.1.1.3 Span Value(s) and Range(s)
Determine the high span value and the high full-scale range of
the SO2 monitor as follows. (Note: For purposes of this
part, the high span and range refer, respectively, either to the
span and range of a single span unit or to the high span and range
of a dual span unit.) The high span value shall be obtained by
multiplying the MPC by a factor no less than 1.00 and no greater
than 1.25. Round the
[[Page 28158]]
span value upward to the next highest multiple of 100 ppm. If the
SO2 span concentration is 500 ppm, the span
value may be rounded upward to the next highest multiple of 10 ppm,
instead of the nearest 100 ppm. The high span value shall be used to
determine concentrations of the calibration gases required for daily
calibration error checks and linearity tests. Select the full-scale
range of the instrument to be consistent with section 2.1 of this
appendix and to be greater than or equal to the span value. Report
the full-scale range setting and calculations of the MPC and span in
the monitoring plan for the unit. Note that for certain
applications, a second (low) SO2 span value may be
required (see section 2.1.1.4 of this appendix). If an existing
state, local, or federal requirement for span of an SO2
pollutant concentration monitor requires a span lower than that
required by this section or by section 2.1.1.4 of this appendix, the
state, local, or federal span value may be used if a satisfactory
explanation is included in the monitoring plan, unless span and/or
range adjustments become necessary in accordance with section
2.1.1.5 of this appendix. Span values higher than those required by
either this section or section 2.1.1.4 of this appendix must be
approved by the Administrator.
2.1.1.4 Dual Span and Range Requirements
For most units, the high span value based on the MPC, as
determined under section 2.1.1.3 of this appendix will suffice to
measure and record SO2 concentrations (unless span and/or
range adjustments become necessary in accordance with section
2.1.1.5 of this appendix). In some instances, however, a second
(low) span value based on the MEC may be required to ensure accurate
measurement of all possible or expected SO2
concentrations. To determine whether two SO2 span values
are required, proceed as follows:
(a) For units with SO2 emission controls, compare the
MEC from section 2.1.1.2 of this appendix to the MPC value from
section 2.1.1.1 of this appendix. If the MEC is 20.0
percent of the MPC, then the high span value and range determined
under section 2.1.1.3 of this appendix are sufficient. If the MEC is
< 20.0 percent of the MPC, however, a second (low) span value is
required.
(b) For units that combust high- and low-sulfur primary and
backup fuels (or blends) and have no SO2 controls,
compare the MPC value from section 2.1.1.1 of this appendix (for the
highest-sulfur fuel or blend) to the MEC value for each of the other
fuels or blends, as determined under section 2.1.1.2 of this
appendix. If all of the MEC values are 20.0 percent of
the MPC, the high span and range determined under section 2.1.1.3 of
this appendix are sufficient, regardless of which fuel or blend is
burned in the unit. If any MEC value is <20.0 percent of the MPC,
however, a second (low) span value must be used when that fuel or
blend is combusted.
(c) When two SO2 spans are required, the owner or
operator may either use a single SO2 analyzer with a dual
range (i.e., low- and high-scales) or two separate SO2
analyzers connected to a common sample probe and sample interface.
For units with SO2 emission controls, the owner or
operator may use a low range analyzer and a default high range
value, as described in paragraph (f) of this section, in lieu of
maintaining and quality assuring a high-scale range. Other monitor
configurations are subject to the approval of the Administrator.
(d) The owner or operator shall designate the monitoring systems
and components as follows: (1) designate the low and high monitor
ranges as separate components of a single, primary monitoring
system; or (2) designate the low and high monitor ranges as
separate, primary monitoring systems; or (3) designate the normal
monitor range as a primary monitoring system and the other monitor
range as a non-redundant backup monitoring system; or (4) for units
with SO2 controls, if the default high range value is
used, designate the low range analyzer as the primary monitoring
system.
(e) Each monitoring system designated as primary shall meet the
initial certification and quality assurance requirements for primary
monitoring systems in Sec. 75.20(c) and appendices A and B to this
part, with one exception: relative accuracy test audits (RATAs) are
required only on the normal range (for units with SO2
emission controls, the low range is considered normal). Each
monitoring system designated as a non-redundant backup shall meet
the applicable quality assurance requirements in Sec. 75.20(d).
(f) For dual span units with SO2 emission controls,
the owner or operator may, as an alternative to maintaining and
quality assuring a high monitor range, use a default high range
value. If this option is chosen, the owner or operator shall report
a default SO2 concentration of 200.0 percent of the MPC
for each unit operating hour in which the full-scale of the low
range SO2 analyzer is exceeded.
(g) The high span value and range shall be determined in
accordance with section 2.1.1.3 of this appendix. The low span value
shall be obtained by multiplying the MEC by a factor no less than
1.00 and no greater than 1.25, and rounding the result upward to the
next highest multiple of 10 ppm (or 100 ppm, as appropriate). For
units that burn high- and low-sulfur primary and backup fuels or
blends and have no SO2 emission controls, select, as the
basis for calculating the appropriate low span value and range, the
fuel-specific MEC value closest to 20.0 percent of the MPC (from
paragraph (b) of this section). The low range must be greater than
or equal to the low span value, and the required calibration gases
must be selected based on the low span value. For units with two
SO2 spans, use the low range whenever the SO2
concentrations are expected to be consistently below 20.0 percent of
the MPC, i.e., when the MEC of the fuel or blend being combusted is
less than 20.0 percent of the MPC. When the full-scale of the low
range is exceeded, the high range shall be used to measure and
record the SO2 concentrations; or, if applicable, the
default high range value in paragraph (f) of this section shall be
reported for each hour of the full-scale exceedance.
2.1.1.5 Adjustment of Span and Range
For each affected unit or common stack, the owner or operator
shall make a quarterly evaluation of the MPC, MEC, span, and range
values for each SO2 monitor and shall make any necessary
span and range adjustments, with corresponding monitoring plan
updates, as described in paragraphs (a) through (e), below. Span and
range adjustments may be required as a result of changes in the fuel
supply, changes in the manner of operation of the unit, installation
or removal of emission controls, etc. In implementing the provisions
in paragraphs (a) through (e), below, note that SO2 data
recorded during short-term, non-representative process operating
conditions (e.g., a trial burn of a different type of fuel) shall be
excluded from the analysis; however, if the high range is exceeded,
200.0 percent of the high range must still be reported as the hourly
SO2 concentration for each hour of the full-scale
exceedance, as required by paragraph (c)(1) of this section. The
owner or operator shall document all such unrepresentative operating
conditions in the quarterly report required under Sec. 75.64 and
shall indicate which data (dates and hours) have been excluded from
the quarterly span and range evaluation.
Make each required span or range adjustment no later than 45
days after the end of the quarter in which the need to adjust the
span or range is identified, except that up to 90 days after the end
of that quarter may be taken to implement a span adjustment if the
calibration gases currently being used for daily calibration error
tests and linearity checks are unsuitable for use with the new span
value.
(a) No span or range adjustment is required if, during a
calendar quarter, the hourly SO2 concentration exceeds
the MPC but does not exceed the high span value. However, for
missing data purposes, if any of the hourly SO2
concentrations exceed the current MPC by 5.0 percent, a
new MPC equal to the highest quality assured hourly SO2
concentration recorded during the quarter must be defined in the
monitoring plan. Update the monitoring plan to reflect the new MPC
value.
(b) A span adjustment is required if any of the on-scale,
quality assured hourly SO2 concentrations exceed the high
span value by 10.0 percent during a quarter, but do not
exceed the high range. Define a new MPC value (as applicable) equal
to the highest quality assured on-scale SO2 concentration
recorded during the quarter, and set the new span value according to
section 2.1.1.3 of this appendix, using the new MPC value. If the
new span value exceeds the current full-scale range, adjust the
range setting also. Update the monitoring plan to reflect the new
MPC, the new span value, and (if applicable) the new full-scale
range. Where separate ranges are used to measure emissions from the
combustion of different types of fuel, the low span and MEC shall be
increased in the manner described in this paragraph if any on-scale
hourly value exceeds the low span value by 10.0 percent or more.
(c) Whenever a full-scale range is exceeded during a quarter and
the exceedance is not caused by a monitor out-of-control period,
proceed as follows:
(1) For exceedances of the high range, report 200.0 percent of
the current full-scale range as the hourly SO2
concentration for
[[Page 28159]]
each hour of the full-scale exceedance and make adjustments to the
MPC, span, and range to prevent future full-scale exceedances.
(2) For units with two SO2 spans and ranges, if the
low range is exceeded, no further action is required, provided that
the high range is available and is not out-of-control or out-of-
service for any reason. However, if the high range is not able to
provide quality assured data at the time of the low range exceedance
or at any time during the continuation of the exceedance, report the
MPC as the SO2 concentration until the readings return to
the low range or until the high range is able to provide quality
assured data (unless the reason that the high-scale range is not
able to provide quality assured data is because the high-scale range
has been exceeded; if the high-scale range is exceeded follow the
procedures in paragraph (c)(1) of this section).
(d) If the fuel supply, the composition of the fuel blend(s),
the emission controls, or the manner of operation change such that
the maximum expected or potential concentration changes
significantly, adjust the span and range setting to assure the
continued accuracy of the monitoring system. The owner or operator
should evaluate whether any planned changes in operation of the unit
may affect the concentration of emissions being emitted from the
unit or stack and should plan any necessary span and range changes
needed to account for these changes, so that they are made in as
timely a manner as practicable to coordinate with the operational
changes. Determine the adjusted span(s) using the procedures in
sections 2.1.1.3 and 2.1.1.4 of this appendix (as applicable).
Select the full-scale range(s) of the instrument to be greater than
or equal to the new span value(s) and to be consistent with the
guidelines of section 2.1 of this appendix.
(e) Whenever changes are made to the MPC, MEC, full-scale range,
or span value of the SO2 monitor, as described in
paragraphs (a) through (d) of this section, record and report (as
applicable) the new full-scale range setting, the new MPC or MEC and
calculations of the adjusted span value in an updated monitoring
plan. The monitoring plan update shall be made in the quarter in
which the changes become effective. In addition, record and report
the adjusted span as part of the records for the daily calibration
error test and linearity check specified by appendix B to this part.
Whenever the span value is adjusted, use calibration gas
concentrations that meet the requirements of section 5.1 of this
appendix, based on the adjusted span value. When a span adjustment
is so significant that the calibration gases currently being used
for daily calibration error tests and linearity checks are
unsuitable for use with the new span value, then a diagnostic
linearity test using the new calibration gases must be performed and
passed. Data from the monitor are considered invalid from the hour
in which the span is adjusted until the required linearity check is
passed in accordance with section 6.2 of this appendix.
2.1.2 NOX Pollutant Concentration Monitors
Determine, as indicated below, the span and range value(s) for
the NOX pollutant concentration monitor so that all
expected NOX concentrations can be determined and
recorded accurately.
2.1.2.1 Maximum Potential Concentration
The maximum potential concentration (MPC) of NOX for
each affected unit shall be based upon whichever fuel or blend
combusted in the unit produces the highest level of NOX
emissions. Make an initial determination of the MPC using the
appropriate option below. Note that an initial MPC value determined
for a unit that is not equipped with low-NOX burners must
be re-evaluated if a low-NOX burner system is
subsequently installed.
Option 1: Use 800 ppm for coal-fired and 400 ppm for oil-or gas-
fired units as the maximum potential concentration of NOX
(if an MPC of 1600 ppm for coal-fired units or 480 ppm for oil-or
gas-fired units was previously selected under this part, that value
may still be used, provided that the guidelines of section 2.1 of
this appendix are met);
Option 2: Use the specific values based on boiler type and fuel
combusted, listed in Table 2-1 or Table 2-2;
Option 3: Use NOX emission test results; or
Option 4: Use historical CEM data over the previous 720 (or
more) unit operating hours when combusting the fuel or blend with
the highest NOX emission rate.
For the purpose of providing substitute data during
NOX missing data periods in accordance with Secs. 75.31
and 75.33 and as required elsewhere under this part, the owner or
operator shall also calculate the maximum potential NOX
emission rate (MER), in lb/mmBtu, by substituting the MPC for
NOX in conjunction with the minimum CO2 or
maximum O2 concentration (under all unit operating
conditions except for unit startup, shutdown, and upsets) and the
appropriate F-factor into the applicable equation in appendix F to
this part. The diluent cap value of 5.0 percent CO2 (or
14.0 percent O2) for boilers or 1.0 percent
CO2 (or 19.0 percent O2) for combustion
turbines may be used in the NOX MER calculation.
Report the method of determining the initial MPC and the
calculation of the maximum potential NOX emission rate in
the monitoring plan for the unit.
For units with add-on NOX controls, NOX
emission testing may only be used to determine the MPC if testing
can be performed on uncontrolled emissions (e.g., measured at or
before the control device inlet). If NOX emission testing
is performed, use the following guidelines. Use Method 7E from
appendix A to part 60 of this chapter to measure total
NOX concentration. (Note: Method 20 from appendix A to
Part 60 may be used for gas turbines, instead of Method 7E.) Operate
the unit, or group of units sharing a common stack, at the minimum
safe and stable load, the normal load, and the maximum load. If the
normal load and maximum load are identical, an intermediate level
need not be tested. Operate at the highest excess O2
level expected under normal operating conditions. Make at least
three runs of 20 minutes (minimum) duration with three traverse
points per run at each operating condition. Select the highest point
NOX concentration (e.g., the highest one-minute average)
from all test runs as the MPC for NOX.
If historical CEM data are used to determine the MPC, the data
must represent a minimum of 720 quality assured monitor operating
hours, obtained under various operating conditions, including the
minimum safe and stable load, normal load (including periods of high
excess air at normal load), and maximum load. For units with add-on
NOX controls, historical CEM data may only be used to
determine the MPC if there are 720 quality assured monitor operating
hours of CEM data measuring uncontrolled emissions (e.g., the CEM
data are collected at or before the control device inlet). The
highest hourly NOX concentration in ppm shall be the MPC.
2.1.2.2 Maximum Expected Concentration
Make an initial determination of the maximum expected
concentration (MEC) of NOX during normal operation for
affected units with add-on NOX controls of any kind
(i.e., steam injection, water injection, SCR, or SNCR). Determine a
separate MEC value for each type of fuel (or blend) combusted in the
unit, except for fuels that are only used for unit startup and/or
flame stabilization. Calculate the MEC of NOX using
Equation A-2, if applicable, inserting the maximum potential
concentration, as determined using the procedures in section 2.1.2.1
of this appendix. Where Equation A-2 is not applicable, set the MEC
either by: (1) measuring the NOX concentration using the
testing procedures in this section; or (2) using historical CEM data
over the previous 720 (or more) quality assured monitor operating
hours. Include in the monitoring plan for the unit each MEC value
and the method by which the MEC was determined.
If NOX emission testing is used to determine the MEC
value(s), the MEC for each type of fuel (or blend) shall be based
upon testing at minimum load, normal load, and maximum load. At
least three tests of 20 minutes (minimum) duration, using at least 3
traverse points, shall be performed at each load, using Method 7E
from appendix A to part 60 of this chapter (Note: Method 20 from
appendix A to part 60 may be used for gas turbines instead of Method
7E). The test must be performed at a time when all NOX
control devices and methods used to reduce NOX emissions
are operating properly. The testing shall be conducted downstream of
all NOX controls. The highest point NOX
concentration (e.g., the highest one-minute average) recorded during
any of the test runs shall be the MEC.
If historical CEM data are used to determine the MEC value(s),
the MEC for each type of fuel shall be based upon 720 (or more)
hours of quality assured data representing the entire load range
under stable operating conditions. The data base for the MEC shall
not include any CEM data recorded during unit startup, shutdown, or
malfunction or during any NOX control device malfunctions
or outages. All NOX control devices and methods used to
reduce
[[Page 28160]]
NOX emissions must be operating properly during each
hour. The CEM data shall be collected downstream of all
NOX controls. For each type of fuel, the highest of the
720 (or more) quality assured hourly average NOX
concentrations recorded by the CEMS shall be the MEC.
2.1.2.3 Span Value(s) and Range(s)
Determine the high span value of the NOX monitor as
follows. The high span value shall be obtained by multiplying the
MPC by a factor no less than 1.00 and no greater than 1.25. Round
the span value upward to the next highest multiple of 100 ppm. If
the NOX span concentration is 500 ppm, the
span value may be rounded upward to the next highest multiple of 10
ppm, rather than 100 ppm. The high span value shall be used to
determine the concentrations of the calibration gases required for
daily calibration error checks and linearity tests. Note that for
certain applications, a second (low) NOX span value may
be required (see section 2.1.2.4 of this appendix).
If an existing state, local, or federal requirement for span of
an NOX pollutant concentration monitor requires a span
lower than that required by this section or by section 2.1.2.4 of
this appendix, the state, local, or federal span value may be used,
where a satisfactory explanation is included in the monitoring plan,
unless span and/or range adjustments become necessary in accordance
with section 2.1.2.5 of this appendix. Span values higher than
required by this section or by section 2.1.2.4 of this appendix must
be approved by the Administrator.
Select the full-scale range of the instrument to be consistent
with section 2.1 of this appendix and to be greater than or equal to
the high span value. Include the full-scale range setting and
calculations of the MPC and span in the monitoring plan for the
unit.
2.1.2.4 Dual Span and Range Requirements
For most units, the high span value based on the MPC, as
determined under section 2.1.2.3 of this appendix will suffice to
measure and record NOX concentrations (unless span and/or
range adjustments must be made in accordance with section 2.1.2.5 of
this appendix). In some instances, however, a second (low) span
value based on the MEC may be required to ensure accurate
measurement of all expected and potential NOX
concentrations. To determine whether two NOX spans are
required, proceed as follows:
(a) Compare the MEC value(s) determined in section 2.1.2.2 of
this appendix to the MPC value determined in section 2.1.2.1 of this
appendix. If the MEC values for all fuels (or blends) are
20.0 percent of the MPC, the high span and range values
determined under section 2.1.2.3 of this appendix are sufficient,
irrespective of which fuel or blend is combusted in the unit. If any
of the MEC values is < 20.0 percent of the MPC, two spans (low and
high) are required, one based upon the MPC and the other based on
the MEC.
(b) When two NOX spans are required, the owner or
operator may either use a single NOX analyzer with a dual
range (low-and high-scales) or two separate NOX analyzers
connected to a common sample probe and sample interface. For units
with add-on NOX emission controls (i.e., steam injection,
water injection, SCR, or SNCR), the owner or operator may use a low
range analyzer and a ``default high range value,'' as described in
paragraph 2.1.2.4(e) of this section, in lieu of maintaining and
quality assuring a high-scale range. Other monitor configurations
are subject to the approval of the Administrator.
(c) The owner or operator shall designate the monitoring systems
and components as follows: (1) designate the low and high ranges as
separate components of a single, primary monitoring system; or (2)
designate the low and high ranges as separate, primary monitoring
systems; or (3) designate the normal range as a primary monitoring
system and the other range as a non-redundant backup monitoring
system; or (4) for units with add-on NOX controls, if the
default high range value is used, designate the low range analyzer
as the primary monitoring system.
(d) Each monitoring system designated as primary shall meet the
initial certification and quality assurance requirements for primary
monitoring systems in Sec. 75.20(c) and appendices A and B to this
part, with one exception: relative accuracy test audits (RATAs) are
required only on the normal range (for dual span units with add-on
NOX emission controls, the low range is considered
normal). Each monitoring system designated as non-redundant backup
shall meet the applicable quality assurance requirements in
Sec. 75.20(d).
(e) For dual span units with add-on NOX emission
controls (i.e., steam injection, water injection, SCR, or SNCR), the
owner or operator may, as an alternative to maintaining and quality
assuring a high monitor range, use a default high range value. If
this option is chosen, the owner or operator shall report a default
value of 200.0 percent of the MPC for each unit operating hour in
which the full-scale of the low range NOX analyzer is
exceeded.
(f) The high span and range shall be determined in accordance
with section 2.1.2.3 of this appendix. The low span value shall be
100.0 to 125.0 percent of the MEC, rounded up to the next highest
multiple of 10 ppm (or 100 ppm, if appropriate). If more than one
MEC value (as determined in section 2.1.2.2 of this appendix) is
<20.0 percent of the MPC, the low span value shall be based upon
whichever MEC value is closest to 20.0 percent of the MPC. The low
range must be greater than or equal to the low span value, and the
required calibration gases for the low range must be selected based
on the low span value. For units with two NOX spans, use
the low range whenever NOX concentrations are expected to
be consistently <20.0 percent of the MPC, i.e., when the MEC of the
fuel being combusted is <20.0 percent of the MPC. When the full-
scale of the low range is exceeded, the high range shall be used to
measure and record the NOX concentrations; or, if
applicable, the default high range value in paragraph (e) of this
section shall be reported for each hour of the full-scale
exceedance.
2.1.2.5 Adjustment of Span and Range
For each affected unit or common stack, the owner or operator
shall make a quarterly evaluation of the MPC, MEC, span, and range
values for each NOX monitor and shall make any necessary
span and range adjustments, with corresponding monitoring plan
updates, as described in paragraphs (a) through (e), below. Span and
range adjustments may be required as a result of changes in the fuel
supply, changes in the manner of operation of the unit, installation
or removal of emission controls, etc. In implementing the provisions
in paragraphs (a) through (e), below, note that NOX data
recorded during short-term, non-representative operating conditions
(e.g., a trial burn of a different type of fuel) shall be excluded
from the analysis; however, if the high range is exceeded, 200.0
percent of the high range must still be reported as the hourly
NOX concentration for each hour of the full-scale
exceedance, in accordance with paragraph (c)(1) of this section. The
owner or operator shall document all such unrepresentative operating
conditions in the quarterly report required under Sec. 75.64 and
shall indicate which data have been excluded from the quarterly span
and range evaluation.
Make each required span or range adjustment no later than 45
days after the end of the quarter in which the need to adjust the
span or range is identified, except that up to 90 days after the end
of that quarter may be taken to implement a span adjustment if the
calibration gases currently being used for daily calibration error
tests and linearity checks are unsuitable for use with the new span
value.
(a) No span or range adjustment is required if, during a
calendar quarter, the hourly NOX concentration exceeds
the MPC but does not exceed the high span value. However, for
missing data purposes, if any of the hourly NOX
concentrations exceed the current MPC by 5.0 percent, a
new MPC equal to the highest quality assured hourly NOX
concentration recorded during the quarter must be defined in the
monitoring plan. Update the monitoring plan to reflect the new MPC
value.
(b) A span adjustment is required whenever any of the on-scale,
quality assured, hourly NOX concentrations exceed the
high span value by 10.0 percent during a quarter but do
not exceed the high range. Define a new MPC value (as applicable)
equal to the highest quality assured on-scale NOX
concentration recorded during the quarter, and set the new span
value according to section 2.1.2.3 or 2.1.2.4 of this appendix (as
applicable), using the new MPC value. If the new span value exceeds
the current full-scale range, adjust the range setting also. Update
the monitoring plan to reflect the new MPC, the new span value, and
(if applicable) the new full-scale range. Where separate ranges are
used to measure emissions from different fuels or in different
seasons (i.e. where seasonal controls are used), the low span and
MEC shall be increased in the manner described in this paragraph if
any on-scale hourly value exceeds the low span value by 10.0 percent
or more.
(c) Whenever a full-scale range is exceeded during a quarter and
the exceedance is not caused by a monitor out-of-control period,
proceed as follows:
(1) For exceedances of the high range, report 200.0 percent of
the current full-scale
[[Page 28161]]
range as the hourly NOX concentration for each hour of
the full-scale exceedance and make adjustments to the MPC, span, and
range to prevent future full-scale exceedances.
(2) For units with two NOX spans and ranges, if the
low range is exceeded, no further action is required, provided that
the high range is available and is not out-of-control or out-of-
service for any reason. However, if the high range is not able to
provide quality assured data at the time of the low range exceedance
or at any time during the continuation of the exceedance, report the
MPC as the NOX concentration until the readings return to
the low range or until the high range is able to provide quality
assured data (unless the reason that the high-scale range is not
able to provide quality assured data is because the high-scale range
has been exceeded; if the high-scale range is exceeded follow the
procedures in paragraph (c)(1) of this section).
(d) If the fuel supply, emission controls, or other process
parameters change such that the maximum expected concentration or
the maximum potential concentration changes significantly, adjust
the NOX pollutant concentration span(s) and (if
necessary) monitor range(s) to assure the continued accuracy of the
monitoring system. The owner or operator should evaluate whether any
planned changes in operation of the unit or stack may affect the
concentration of emissions being emitted from the unit and should
plan any necessary span and ranges changes needed to account for
these changes, so that they are made in as timely a manner as
practicable to coordinate with the operational changes. Determine
the adjusted span(s) using the procedures in section 2.1.2.3 or
2.1.2.4 of this appendix (as applicable). Select the full-scale
range(s) of the instrument to be greater than or equal to the
adjusted span value(s) and to be consistent with the guidelines of
section 2.1 of this appendix.
(e) Whenever changes are made to the MPC, MEC, full-scale range,
or span value of the NOX monitor as described in
paragraphs (a) through (d) of this section, record and report (as
applicable) the new full-scale range setting, the new MPC or MEC,
maximum potential NOX emission rate, and the adjusted
span value in an updated monitoring plan for the unit. The
monitoring plan update shall be made in the quarter in which the
changes become effective. In addition, record and report the
adjusted span as part of the records for the daily calibration error
test and linearity check required by appendix B to this part.
Whenever the span value is adjusted, use calibration gas
concentrations that meet the requirements of section 5.1 of this
appendix, based on the adjusted span value. When a span adjustment
is significant enough that the calibration gases currently being
used for daily calibration error tests and linearity checks are
unsuitable for use with the new span value, a linearity test using
the new calibration gases must be performed and passed. Data from
the monitor are considered invalid from the hour in which the span
is adjusted until the required linearity check is passed in
accordance with section 6.2 of this appendix.
2.1.3 CO2 and O2 Monitors
For an O2 monitor (including O2 monitors
used to measure CO2 emissions or percentage moisture),
select a span value between 15.0 and 25.0 percent O2. For
a CO2 monitor installed on a boiler, select a span value
between 14.0 and 20.0 percent CO2. For a CO2
monitor installed on a combustion turbine, an alternative span value
between 6.0 and 14.0 percent CO2 may be used. An
alternative O2 span value below 15.0 percent
O2 may be used if an appropriate technical justification
is included in the monitoring plan. Select the full-scale range of
the instrument to be consistent with section 2.1 of this appendix
and to be greater than or equal to the span value. Select the
calibration gas concentrations for the daily calibration error tests
and linearity checks in accordance with section 5.1 of this
appendix, as percentages of the span value. For O2
monitors with span values 21.0 percent O2,
purified instrument air containing 20.9 percent O2 may be
used as the high-level calibration material.
2.1.3.1 Maximum Potential Concentration of CO2
For CO2 pollutant concentration monitors, the maximum
potential concentration shall be 14.0 percent CO2 for
boilers and 6.0 percent CO2 for combustion turbines.
Alternatively, the owner or operator may determine the MPC based on
a minimum of 720 hours of quality assured historical CEM data
representing the full operating load range of the unit(s).
2.1.3.2 Adjustment of Span and Range
Adjust the span value and range of a CO2 or
O2 monitor according to the general guidelines in section
2.1.1.5 of this appendix (insofar as those provisions are
applicable), replacing the term ``SO2'' with
``CO2 or O2.'' Set the new span and range in
accordance with section 2.1.3 of this appendix and provide a
rationale for the new span value in the monitoring plan.
2.1.4 Flow Monitors
Select the full-scale range of the flow monitor so that it is
consistent with section 2.1 of this appendix and can accurately
measure all potential volumetric flow rates at the flow monitor
installation site.
2.1.4.1 Maximum Potential Velocity and Flow Rate
Make an initial determination of the maximum potential velocity
(MPV) using Equation A-3a or A-3b, or determine the MPV (wet basis)
from velocity traverse testing using Reference Method 2 (or its
allowable alternatives) in appendix A to part 60 of this chapter. If
using test values, use the highest average velocity (determined from
the Method 2 traverses) measured at or near the maximum unit
operating load. Express the MPV in units of wet standard feet per
minute (fpm). For the purpose of providing substitute data during
periods of missing flow rate data in accordance with Secs. 75.31 and
75.33 and as required elsewhere in this part, calculate the maximum
potential stack gas flow rate (MPF) in units of standard cubic feet
per hour (scfh), as the product of the MPV (in units of wet,
standard fpm) times 60, times the cross-sectional area of the stack
or duct (in ft2) at the flow monitor location.
2.1.4.2 Span Values and Range
Determine the span and range of the flow monitor as follows.
Convert the MPV, as determined in section 2.1.4.1 of this appendix,
to the same units of flow rate that are used for daily calibration
error tests (e.g., scfh, kscfh, kacfm, or differential pressure
(inches of water)). Next, determine the ``calibration span value''
by multiplying the MPV (converted to equivalent daily calibration
error units) by a factor no less than 1.00 and no greater than 1.25,
and rounding up the result to at least 2 significant figures. For
calibration span values in inches of water, retain at least 2
decimal places. Select appropriate reference signals for the daily
calibration error tests as percentages of the calibration span
value. Finally, calculate the ``flow rate span value'' (in scfh) as
the product of the MPF, as determined in section 2.1.4.1 of this
appendix, times the same factor (between 1.00 and 1.25) that was
used to calculate the calibration span value. Round off the flow
rate span value to the nearest 1000 scfh. Select the full-scale
range of the flow monitor so that it is greater than or equal to the
span value and is consistent with section 2.1 of this appendix.
Include in the monitoring plan for the unit: calculations of the
MPV, MPF, calibration span value, flow rate span value, and full-
scale range (expressed both in units of scfh and, if different, in
the units of calibration).
[GRAPHIC] [TIFF OMITTED] TP21MY98.005
(Eq. A-3a)
or
[GRAPHIC] [TIFF OMITTED] TP21MY98.006
[[Page 28162]]
(Eq. A-3b)
Where:
MPV=maximum potential velocity (fpm, standard wet basis),
Fd=dry-basis F factor (dscf/mmBtu) from Table 1, Appendix
F of this part,
Fc=carbon-based F factor (scfCO2/mmBtu) from
Table 1, Appendix F this part,
HF=maximum heat input (mmBtu/minute) for all units, combined,
exhausting to the stack or duct where the flow monitor is located,
A=inside cross sectional area (ft2) of the flue at the flow monitor
location,
%O2d=maximum oxygen concentration, percent dry basis,
under normal operating conditions,
%CO2d=minimum carbon dioxide concentration, percent dry
basis, under normal operating conditions,
%H2O=maximum percent flue gas moisture content under
normal operating conditions.
2.1.4.3 Adjustment of Span and Range
For each affected unit or common stack, the owner or operator
shall make a quarterly evaluation of the MPV, MPF, span, and range
values for each flow rate monitor and shall make any necessary span
and range adjustments with corresponding monitoring plan updates, as
described in paragraphs (a) through (e), below. Span and range
adjustments may be required as a result of changes in the fuel
supply, changes in the stack or ductwork configuration, changes in
the manner of operation of the unit, installation or removal of
emission controls, etc. In implementing the provisions in paragraphs
(a) through (e), below, note that flow rate data recorded during
short-term, non-representative operating conditions (e.g., a trial
burn of a different type of fuel) shall be excluded from the
analysis; however, if the high range is exceeded, 200.0 percent of
the full-scale range must still be reported as the hourly flow rate
for each hour of the full-scale exceedance, in accordance with
paragraph (c) of this section. The owner or operator shall document
all such unrepresentative operating conditions in the quarterly
report required under Sec. 75.64 and shall indicate which data have
been excluded from the quarterly span and range evaluation. Make
each required span or range adjustment no later than 45 days after
the end of the quarter in which the need to adjust the span or range
is identified.
(a) No span or range adjustment is required if, during a
calendar quarter, the hourly flow rate exceeds the MPF but does not
exceed the flow rate span value. However, for missing data purposes,
if any of the hourly flow rates exceed the current MPF by
5.0 percent, a new MPF equal to the highest quality
assured hourly flow rate recorded during the quarter must be defined
in the monitoring plan. Update the monitoring plan to reflect the
new MPF value.
(b) A span adjustment is required whenever any of the on-scale,
quality assured, hourly flow rates exceed the flow rate span value
by 10.0 percent during a quarter. Define a new MPF equal
to the highest on-scale flow rate recorded during the quarter, and
set the new flow rate span value according to section 2.1.4.2 of
this appendix. Then, calculate the new calibration span value by
converting the new flow rate span value from units of scfh to units
of daily calibration. If the new flow rate span value exceeds the
current full-scale range, adjust the range setting also. Update the
monitoring plan to reflect the new span and (if applicable) range
values.
(c) Whenever the full-scale range is exceeded during a quarter,
provided that the exceedance is not caused by a monitor out-of-
control period, report 200.0 percent of the current full-scale range
as the hourly flow rate for each hour of the full-scale exceedance.
If the range is exceeded, make adjustments to the MPF, flow rate
span, and range to prevent future full-scale exceedances. Calculate
the new calibration span value by converting the new flow rate span
value from units of scfh to units of daily calibration. A
calibration error test must be performed and passed to validate data
on the new range.
(d) If the fuel supply, stack or ductwork configuration,
operating parameters, or other conditions change such that the
maximum potential flow rate changes significantly, adjust the span
and range to assure the continued accuracy of the flow monitor. The
owner or operator should evaluate whether any planned changes in
operation of the unit may affect the flow of the unit or stack and
should plan any necessary span and range changes needed to account
for these changes, so that they are made in as timely a manner as
practicable to coordinate with the operational changes. Calculate
the adjusted calibration span and flow rate span values using the
procedures in section 2.1.4.2 of this appendix.
(e) Whenever changes are made to the MPV, MPF, full-scale range,
or span value of the flow monitor, as described in paragraphs (a)
through (d) of this section, record and report (as applicable) the
new full-scale range setting, calculations of the flow rate span
value, calibration span value, MPV, and MPF in an updated monitoring
plan for the unit. The monitoring plan update shall be made in the
quarter in which the changes become effective. Record and report the
adjusted calibration span and reference values as parts of the
records for the calibration error test required by appendix B to
this part. Whenever the calibration span value is adjusted, use
reference values for the calibration error test that meet the
requirements of section 2.2.2.1 of this appendix, based on the most
recent adjusted calibration span value. Perform a calibration error
test according to section 2.1.1 of appendix B to this part whenever
making a change to the flow monitor span or range, unless the range
change also triggers a recertification under Sec. 75.20(b).
2.1.5 Moisture Sensors
The span value of a continuous moisture sensor shall be equal to
the full-scale range of the instrument. The range shall be selected
in accordance with the requirements of section 2.1 of this appendix.
* * * * *
54. Section 3 of appendix A to part 75 is amended by revising
section 3.1 and the last sentence in the first paragraph of section
3.2; by adding a new section 3.3.6; and by revising section 3.5, to
read as follows:
3. Performance Specifications
3.1 Calibration Error
The initial calibration error of SO2 and
NOX pollutant concentration monitors shall not deviate
from the reference value of either the zero or upscale calibration
gas by more than 2.5 percent of the span of the instrument, as
calculated using Equation A-5 of this appendix. Alternatively, where
the span value is less than 200 ppm, calibration error test results
are also acceptable if the absolute value of the difference between
the monitor response value and the reference value, |R-A| in
Equation A-5 of this appendix, is 5 ppm. The calibration
error of CO2 or O2 monitors (including
O2 monitors used to measure CO2 emissions or
percent moisture) shall not deviate from the reference value of the
zero or upscale calibration gas by >0.5 percent O2 or
CO2, as calculated using the term |R-A| in the numerator
of Equation A-5 of this appendix. The calibration error of flow
monitors shall not exceed 3.0 percent of the calibration span value
of the instrument, as calculated using Equation A-6 of this
appendix. For differential pressure-type flow monitors, the
calibration error test results are also acceptable if |R--A|, the
absolute value of the difference between the monitor response and
the reference value in Equation A-6, does not exceed 0.01 inches of
water. The calibration error of a continuous moisture sensor shall
not exceed 3.0 percent of the span value, as calculated using
Equation A-5 of this appendix.
3.2 Linearity Check
* * * For CO2 or O2 monitors (including
O2 monitors used to measure CO2 emissions or
percent moisture):
* * * * *
3.3 * * *
3.3.6 Relative Accuracy for Moisture Monitoring Systems
The relative accuracy of a moisture monitoring system shall not
exceed 10.0 percent. The relative accuracy test results are also
acceptable if the mean difference of the reference method
measurements (in percent H2O) and the corresponding
moisture monitoring system measurements (in percent H2O)
are within 1.0 percent H2O.
* * * * *
3.5 Cycle Time
The cycle time for pollutant concentration monitors, oxygen
monitors used to determine percent moisture, and any other
continuous emission monitoring system(s) required to perform a cycle
time test shall not exceed 15 minutes.
55. Section 4 of appendix A to part 75 is amended by revising the
introductory paragraph and paragraph (6) to read as follows:
[[Page 28163]]
4. Data Acquisition and Handling Systems
Automated data acquisition and handling systems shall: (1) Read
and record the full range of pollutant concentrations and volumetric
flow from zero through span; and (2) provide a continuous, permanent
record of all measurements and required information as an ASCII flat
file capable of transmission both by direct computer-to-computer
electronic transfer via modem and EPA-provided software and by an
IBM-compatible personal computer diskette.
* * * * *
(6) Provide a continuous, permanent record of all measurements
and required information as an ASCII flat file capable of
transmission both by direct computer-to-computer electronic transfer
via modem and EPA-provided software and by an IBM-compatible
personal computer diskette.
56. Section 5 of appendix A to part 75 is amended by revising
sections 5.1, 5.2.1, 5.2.2, 5.2.3, and 5.2.4 to read as follows:
5. Calibration Gas
5.1 Reference Gases
For the purposes of part 75, calibration gases include the
following:
5.1.1 Standard Reference Materials (SRM)
These calibration gases may be obtained from the National
Institute of Standards and Technology (NIST) at the following
address: Quince Orchard and Cloppers Road, Gaithersburg, MD 20899-
0001.
5.1.2 SRM-Equivalent Compressed Gas Primary Reference Material (PRM)
Contact the Gas Metrology Team, Analytical Chemistry Division,
Chemical Science and Technology Laboratory of NIST, at the above
address, for a list of vendors and cylinder gases.
5.1.3 NIST Traceable Reference Materials
Contact the Gas Metrology Team, Analytical Chemistry Division,
Chemical Science and Technology Laboratory of NIST, at the above
address, for a list of vendors and cylinder gases.
5.1.4 EPA Protocol Gases
EPA Protocol gases must be vendor-certified to be within 2.0
percent of the concentration specified on the cylinder label (tag
value), using the uncertainty calculation procedure in section 2.1.8
of the ``EPA Traceability Protocol for Assay and Certification of
Gaseous Calibration Standards,'' September 1997, EPA-600/R-97/121.
A copy of EPA-600/R-97/121 is available from the National
Technical Information Service, 5285 Port Royal Road, Springfield, VA
703-487-4650 and from the Office of Research and Development, (MD-
77B), U.S. Environmental Protection Agency, Research Triangle Park,
NC 27711, Attn: Berne Bennett, 919-541-2366.
5.1.5 Research Gas Mixtures
Research gas mixtures must be vendor-certified to be within 2.0
percent of the concentration specified on the cylinder label (tag
value), using the uncertainty calculation procedure in section 2.1.8
of the ``EPA Traceability Protocol for Assay and Certification of
Gaseous Calibration Standards,'' September 1997, EPA-600/R-97/121.
Inquiries about the RGM program should be directed to: National
Institute of Standards and Technology, Analytical Chemistry
Division, Chemical Science and Technology Laboratory, B-324
Chemistry, Gaithersburg, MD 20899.
5.1.6 Zero Air Material
Zero air material is defined in Sec. 72.2 of this chapter.
5.1.7 NIST/EPA-Approved Certified Reference Materials
Existing certified reference materials (CRMs) that are still
within their certification period may be used as calibration gas.
5.1.8 Gas Manufacturer's Intermediate Standards
Gas manufacturer's intermediate standards is defined in
Sec. 72.2 of this chapter.
* * * * *
5.2.1 Zero-level Concentration
0.0 to 20.0 percent of span, including span for high-scale or
both low-and high-scale for SO2, NOX,
CO2, and O2 monitors, as appropriate.
5.2.2 Low-level Concentration
20.0 to 30.0 percent of span, including span for high-scale or
both low-and high-scale for SO2, NOX,
CO2, and O2 monitors, as appropriate.
5.2.3 Mid-level Concentration
50.0 to 60.0 percent of span, including span for high-scale or
both low-and high-scale for SO2, NOX,
CO2, and O2 monitors, as appropriate.
5.2.4 High-level Concentration
80.0 to 100.0 percent of span, including span for high-scale or
both low-and high-scale for SO2, NOX,
CO2, and O2 monitors, as appropriate.
57. Section 6 of appendix A to part 75 is amended by revising
sections 6.2, 6.3.1, 6.5, 6.5.1, 6.5.2, 6.5.6, 6.5.7, and 6.5.9 to read
as follows:
6. Certification Tests and Procedures
* * * * *
6.2 Linearity Check
For the purposes of initial certification, recertification, and
quality assurance, check the linearity of each SO2,
NOX, CO2, and O2 monitor while the
unit, or group of units for a common stack, is combusting fuel at
conditions of typical stack temperature and pressure; it is not
necessary for the unit to be generating electricity during this
test. Notwithstanding these requirements, if the SO2 or
NOX span value for a particular monitor range is
30 ppm, that range is exempted from the linearity test
requirements of this part.
Challenge each monitor with calibration gas, as defined in
section 5.1 of this appendix, at the low-, mid-, and high-range
concentrations specified in section 5.2 of this appendix. For units
using emission controls and other units using both a high and a low
span, perform a linearity check on both the low-and high-scales for
initial certification. For on-going quality assurance of the CEMS,
perform linearity tests on the range(s) and at the frequency
specified in section 2.2.1 of appendix B to this part.
Introduce the calibration gas at the gas injection port, as
specified in section 2.2.1 of this appendix. Operate each monitor at
its normal operating temperature and conditions. For extractive and
dilution type monitors, pass the calibration gas through all
filters, scrubbers, conditioners, and other monitor components used
during normal sampling and through as much of the sampling probe as
is practical. For in-situ type monitors, perform calibration
checking all active electronic and optical components, including the
transmitter, receiver, and analyzer. Challenge the monitor three
times with each reference gas (see example data sheet in Figure 1).
Do not use the same gas twice in succession. The linearity check
must be done hands-off, as follows. No adjustments other than the
calibration adjustments described in section 2.1.3 of appendix B to
this part are permitted prior to or during the linearity test
period. To the extent practicable, the duration of each linearity
test, from the hour of the first injection to the hour of the last
injection, shall not exceed 24 unit operating hours. Record the
monitor response from the data acquisition and handling system. For
each concentration, use the average of the responses to determine
the error in linearity using Equation A-4 in this appendix.
Linearity checks are acceptable for monitor or monitoring system
certification, recertification, or quality assurance if none of the
test results exceed the applicable performance specifications in
section 3.2 of this appendix.
The status of emission data from a CEMS prior to and during a
linearity test period shall be determined as follows:
(a) For the initial certification of a CEMS, data from the
monitoring system are considered invalid until all certification
tests, including the linearity test, have been successfully
completed, unless the data validation procedures in Sec. 75.20(b)(3)
are used. When the procedures in Sec. 75.20(b)(3) are followed,
substitute the words ``initial certification'' for
``recertification,'' and complete all of the initial certification
tests by the applicable deadline in Sec. 75.4, rather than within
the time periods specified in Sec. 75.20(b)(3)(iv) for the
individual tests.
(b) For the routine quality assurance linearity checks required
by section 2.2.1 of appendix B to this part, use the data validation
procedures in section 2.2.3 of appendix B to this part.
(c) When a linearity test is required as a diagnostic test or
for recertification, use the data validation procedures in
Sec. 75.20(b)(3).
(d) For linearity tests of non-redundant backup monitoring
systems, use the data validation procedures in
Sec. 75.20(d)(2)(iii).
(e) For linearity tests performed during a grace period and
after the expiration of a grace period, use the data validation
procedures in sections 2.2.3 and 2.2.4, respectively, of appendix B
to this part.
[[Page 28164]]
6.3 * * *
6.3.1 Pollutant Concentration Monitor and CO2 or
O2 Monitor 7-day Calibration Error Test
For the purposes of initial certification and recertification,
measure the calibration error of each pollutant concentration
monitor and CO2 or O2 monitor while the unit
is combusting fuel at conditions of typical temperature and pressure
(but not necessarily generating electricity) once each day for 7
consecutive operating days according to the following procedures.
(In the event that extended unit outages occur after the
commencement of the test, the 7 consecutive unit operating days need
not be 7 consecutive calendar days.) Units using dual span monitors
must perform the calibration error test on both high-and low-scales
of the pollutant concentration monitor. The daily calibration error
test procedures in this section shall also be used to perform the
daily assessments and additional calibration error tests required
under sections 2.1.1 and 2.1.3 of appendix B to this part.
Do not make manual or automatic adjustments to the monitor
settings until after taking measurements at both zero and high
concentration levels for that day during the 7-day test. If
automatic adjustments are made following both injections, conduct
the calibration error test such that the magnitude of the
adjustments can be determined and recorded. Record and report test
results for each day using the unadjusted concentration measured in
the calibration error test prior to making any manual or automatic
adjustments (i.e., resetting the calibration).
The calibration error tests should be approximately 24 hours
apart, (unless the 7-day test is performed over non-consecutive
days). Perform calibration error tests at both the zero-level
concentration and either the mid-level or high-level concentration,
as specified in section 5.2 of this appendix. In addition, repeat
the procedure for SO2 and NOX pollutant
concentration monitors using the low-scale for units equipped with
emission controls or other units with dual span monitors. Use only
calibration gas, as specified in section 5.1 of this appendix.
Introduce the calibration gas at the gas injection port, as
specified in section 2.2.1 of this appendix. Operate each monitor in
its normal sampling mode. For extractive and dilution type monitors,
pass the calibration gas through all filters, scrubbers,
conditioners, and other monitor components used during normal
sampling and through as much of the sampling probe as is practical.
For in-situ type monitors, perform calibration, checking all active
electronic and optical components, including the transmitter,
receiver, and analyzer. Challenge the pollutant concentration
monitors and CO2 or O2 monitors once with each
calibration gas. Record the monitor response from the data
acquisition and handling system. Using Equation A-5 of this
appendix, determine the calibration error at each concentration once
each day (at approximately 24-hour intervals) for 7 consecutive days
according to the procedures given in this section.
Calibration error tests are acceptable for monitor or monitoring
system certification if none of these daily calibration error test
results exceed the applicable performance specifications in section
3.1 of this appendix.
The status of emission data from a CEMS during a 7-day
calibration error test period shall be determined as follows:
(a) For the initial certification of a CEMS, data from the
monitoring system are considered invalid until all certification
tests, including the 7-day calibration error test, have been
successfully completed, unless the data validation procedures in
Sec. 75.20(b)(3) are used. When the procedures in Sec. 75.20(b)(3)
are followed, substitute the words ``initial certification'' for
``recertification,'' and complete all of the initial certification
tests by the applicable deadline in Sec. 75.4, rather than within
the time periods specified in Sec. 75.20(b)(3)(iv) for the
individual tests.
(b) When a 7-day calibration error test is required as a
diagnostic test or for recertification, use the data validation
procedures in Sec. 75.20(b)(3).
* * * * *
6.5 Relative Accuracy and Bias Tests
For the purposes of initial certification, recertification, and
quality assurance, perform the required relative accuracy test
audits as follows for each CO2 and SO2
pollutant concentration monitor, each flow monitor, each
NOX continuous emission monitoring system, each
O2 monitor used to calculate heat input or CO2
concentration, each moisture monitoring system, and each
SO2-diluent continuous emission monitoring system (lb/
mmBtu) used by units with a qualifying Phase I technology for the
period during which the units are required to monitor SO2
emission removal efficiency, from January 1, 1997 through December
31, 1999:
(a) All relative accuracy test audits shall be done ``hands-
off'', as follows:
(1) 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.
(2) For 2-level and 3-level flow monitor audits, no re-
linearization of the monitor (i.e., changing of the polynomial
coefficients) is permitted between load levels.
(b) Except as provided in Sec. 75.21(a)(5), perform each RATA
while the unit (or units, if more than one unit exhausts into the
flue) is combusting the fuel that is normal for that unit (for some
units, more than one type of fuel may be considered normal; e.g., a
unit that combusts gas or oil on a seasonal basis). When relative
accuracy test audits are performed on continuous emission monitoring
systems or component(s) on bypass stacks/ducts, use the fuel
normally combusted by the unit (or units, if more than one unit
exhausts into the flue) when emissions exhaust through the bypass
stack/ducts.
(c) Perform each RATA at the load level(s) specified in section
6.5.1 or 6.5.2 of this appendix or in section 2.3.1.3 of appendix B
to this part, as applicable.
(d) For monitoring systems with dual ranges, perform the
relative accuracy test on the range normally used for measuring
emissions. For units with add-on SO2 or NOX
controls or for units that need a dual range to record high
concentration ``spikes'' during startup conditions, the low range is
considered normal. However, for some dual span units (e.g., for
units that switch fuels and have both a high and low span value),
either of the two measurement ranges may be considered normal; in
such cases, perform the RATA on the range that is in use at the time
of the scheduled test.
(e) Record monitor or monitoring system output from the data
acquisition and handling system.
(f) For initial certification and recertification RATAs and for
the quality assurance RATAs required by Sec. 75.20(d) or by section
2.3.1 of appendix B to this part, complete each single-load relative
accuracy test audit within a period of 168 consecutive unit
operating hours. For 2-level and 3-level flow monitor RATAs,
complete all of the RATAs at all levels, to the extent practicable,
within a period of 168 consecutive unit operating hours; however, if
this is not possible, up to 720 consecutive unit operating hours may
be taken to complete a multiple-load flow RATA.
(g) The status of emission data from the CEMS prior to and
during the RATA test period shall be determined as follows:
(1) For the initial certification of a CEMS, data from the
monitoring system are considered invalid until all certification
tests, including the RATA, have been successfully completed, unless
the data validation procedures in Sec. 75.20(b)(3) are used. When
the procedures in Sec. 75.20(b)(3) are followed, substitute the
words ``initial certification'' for ``recertification,'' and
complete all of the initial certification tests by the applicable
deadline in Sec. 75.4, rather than within the time periods specified
in Sec. 75.20(b)(3)(iv) for the individual tests.
(2) For the routine quality assurance RATAs required by section
2.3.1 of appendix B to this part, use the data validation procedures
in section 2.3.2 of appendix B to this part.
(3) For recertification RATAs, use the data validation
procedures in Sec. 75.20(b)(3).
(4) For quality assurance RATAs of non-redundant backup
monitoring systems, use the data validation procedures in
Secs. 75.20(d)(2)(v) and (vi).
(5) For RATAs performed during and after the expiration of a
grace period, use the data validation procedures in sections 2.3.2
and 2.3.3, respectively, of appendix B to this part.
(h) For each SO2 or CO2 pollutant
concentration monitor, each flow monitor, and each NOX
continuous emission monitoring system, calculate the relative
accuracy, in accordance with section 7.4 of this appendix. In
addition (except for CO2 monitors), test for bias and
determine the appropriate bias adjustment factor, in accordance with
sections 7.6.4 and 7.6.5 of this appendix, using the data from the
relative accuracy test audits.
6.5.1 Gas Monitoring System RATAs (Special Considerations)
(a) For the purposes of initial certification, recertification,
and quality assurance, perform the required relative accuracy test
audits for each SO2 or CO2 pollutant
[[Page 28165]]
concentration monitor, each O2 monitor, each
NOX continuous emission monitoring system, and each
SO2-diluent continuous emission monitoring system (lb/
mmBtu) used by units with a qualifying Phase I technology for the
period during which the units are required to monitor SO2
emission removal efficiency, from January 1, 1997 through December
31, 1999, at the normal load level for the unit (or combined units,
if common stack), as defined in section 6.5.2.1 of this appendix. If
two load levels have been designated as normal, the RATAs may be
done at either load level.
(b) For the initial certification of a gas monitoring system and
for recertifications in which, in addition to a RATA, one or more
other tests are required (i.e., a linearity test, cycle time test,
or 7-day calibration error test), EPA recommends that the RATA not
be commenced until the other required tests of the CEMS have been
passed.
6.5.2 Flow Monitor RATAs (Special Considerations)
(a) Except for flow monitors on bypass stacks/ducts and peaking
units, perform relative accuracy test audits for the initial
certification of each flow monitor at three different exhaust gas
velocities (low, mid, and high), corresponding to three different
load levels within the range of operation, as defined in section
6.5.2.1 of this appendix. For a common stack/duct, the three
different exhaust gas velocities may be obtained from frequently
used unit/load combinations for the units exhausting to the common
stack. Select the three exhaust gas velocities such that the audit
points at adjacent load levels (i.e., low and mid or mid and high),
in megawatts (or in thousands of lb/hr of steam production), are
separated by no less than 25.0 percent of the range of operation, as
defined in section 6.5.2.1 of this appendix.
(b) For flow monitors on bypass stacks/ducts and peaking units,
the flow monitor relative accuracy test audits for initial
certification and recertification shall be single-load tests,
performed at the normal load, as defined in section 6.5.2.1 of this
appendix.
(c) The semiannual and annual quality assurance flow monitor
RATAs required under appendix B to this part shall be done at the
load level(s) specified in section 2.3.1.3 of appendix B.
(d) Flow monitor recertification RATAs shall be done at three
load level(s), unless otherwise specified in paragraph (b) of this
section or unless otherwise approved by the Administrator.
6.5.2.1 Range of Operation and RATA Load Levels (Definitions)
The owner or operator shall determine the upper and lower
boundaries of the ``range of operation'' for each unit (or
combination of units, for common-stack configurations) that uses
CEMS to account for its emissions. The lower boundary of the range
of operation of a unit shall be the minimum safe, stable load (or,
for common-stacks, the lowest of the minimum safe, stable loads for
any of the units discharging through the stack). The upper boundary
of the range of operation of a unit shall be the maximum sustainable
load. The ``maximum sustainable load'' is the higher of: (1) the
nameplate or rated capacity of the unit, less any physical or
regulatory limitations or other deratings, or (2) the highest
sustainable unit load, based on at least four quarters of
representative historical operating data. For common-stacks, the
maximum sustainable load is the sum of all of the maximum
sustainable loads of the individual units discharging through the
stack, unless this load is unattainable in practice, in which case
use the highest sustainable combined load for the units that
discharge through the stack, based on at least four quarters of
representative historical operating data. The load values for the
unit(s) shall be expressed either in units of megawatts or thousands
of lb/hr of steam load.
The operating levels for relative accuracy test audits shall,
except for peaking units, be defined as follows: (1) the low
operating level shall be the first 30.0 percent of the range of
operation; (2) the mid operating level shall be the middle portion
(30.0 to 60.0 percent) of the range of operation; and (3) the high
operating level shall be the upper end (60.0 to 100.0 percent) of
the range of operation. For example, if the upper and lower
boundaries of the range of operation are 100 and 1100 megawatts,
respectively, then the low, mid, and high operating levels would be
100 to 400 megawatts, 400 to 700 megawatts, and 700 to 1100
megawatts, respectively.
The provisions of this paragraph become effective January 1,
2000. This determination shall be made just prior to conducting the
quality assurance RATAs required under section 2.3 of appendix B of
this part (in the same calendar quarter in which the RATAs are
conducted) but not required more frequently than once a year, if the
RATA(s) are conducted semiannually. The owner or operator shall
determine, for each unit or common stack (except for peaking units)
the load level (low, mid or high) that is the most frequently used.
In addition, the owner or operator shall determine which load level
is the second most frequently-used. To make the determinations, the
owner or operator shall construct a historical load frequency
distribution (e.g., histogram), depicting the relative number of
operating hours at each of the three load levels, low, mid and high.
The frequency distribution shall be based upon all available data
from the four most recent QA operating quarters, as defined in
section 2.3.1.1 of appendix B of this part. The owner or operator
shall use the frequency distribution to determine, to the nearest
0.1 percent, the percentage of the time that each load level (low,
mid, high) has been used in the previous four QA operating quarters.
A summary of the data used for these determinations shall be kept
on-site in a format suitable for inspection and the results of the
determinations shall be included in the electronic quarterly report
under Sec. 75.64.
Except for peaking units, the owner or operator shall designate
the most frequently used load level as the normal load level for
each unit (or combination of units, for common stacks). The owner or
operator may also, if appropriate, designate the second most
frequently used load level as an additional normal load level for
the unit or stack. For peaking units, the entire operating load
range shall be considered normal.
Beginning on January 1, 2000, the owner or operator shall report
the upper and lower boundaries of the range of operation for each
unit (or combination of units, for common stacks), in units of
megawatts or thousands of lb/hr of steam production, in the
electronic quarterly report required under Sec. 75.64. Except for
peaking units, the owner or operator shall also indicate in the
electronic quarterly report: (1) the two load levels (low, mid, or
high) that are the most frequently used, as determined under this
section; (2) the relative (percent) historical usage of each load
level, as determined under this section; and (3) the load level (or
levels) designated as normal under this section.
6.5.2.2 Multi-Load Flow RATA Results
For each multi-load flow RATA, calculate the flow monitor
relative accuracy at each operating level. If a flow monitor
relative accuracy test is failed or aborted due to a problem with
the monitor on any level of a 2-level (or 3-level) relative accuracy
test audit, the RATA must be repeated at that load level. However,
the entire 2-level (or 3-level) relative accuracy test audit does
not have to be repeated unless the flow monitor polynomial
coefficients are changed, in which case a 3-level RATA is required.
* * * * *
6.5.6 Reference Method Traverse Point Selection
Select traverse points that ensure acquisition of representative
samples of pollutant and diluent concentrations, moisture content,
temperature, and flue gas flow rate over the flue cross section. To
achieve this, the reference method traverse points shall meet the
requirements of section 3.2 of Performance Specification 2 (``PS No.
2'') in appendix B to part 60 of this chapter (for SO2,
NOX, and moisture monitoring system RATAs), Performance
Specification 3 in appendix B to part 60 of this chapter (for
O2 and CO2 monitor RATAs), Method 1 (or 1A)
(for volumetric flow rate monitor RATAs), Method 3 (for molecular
weight), and Method 4 (for moisture determination) in appendix A to
part 60 of this chapter.
The following alternative reference method traverse point
locations are permitted for moisture and gas monitor RATAs:
(a) For all moisture determinations, a single reference method
point, located at least 1.0 meter from the stack wall, may be used.
(b) For gas monitoring system RATAs, the owner or operator may
use any of the following options:
(1) At any location (including locations where stratification is
expected), use a minimum of six traverse points along a diameter, in
the direction of any expected stratification. The points shall be
located in accordance with Method 1 in appendix A to part 60 of this
chapter.
(2) At locations where section 3.2 of PS No. 2 allows the use of
a short reference method measurement line (with three points located
at 0.4, 1.0, and 2.0 meters from the stack wall), the owner or
operator may use an alternative 3-point measurement line, locating
the three points at 4.4, 14.6, and 29.6 percent of the way across
the stack, in
[[Page 28166]]
accordance with Method 1 in appendix A to part 60 of this chapter.
(3) At locations where stratification is likely to occur (i.e.,
following a wet scrubber or when dissimilar gas streams are
combined), the short measurement line from section 3.2 of PS No. 2
(or the alternative line described in paragraph (c) of this section)
may be used in lieu of the prescribed ``long'' measurement line in
section 3.2 of PS No. 2, provided that the 12-point stratification
test described in section 6.5.6.1 of this appendix is performed and
passed one time at the location (according to the acceptance
criteria of section 6.5.6.3(a) of this appendix) and provided that
either the 12-point stratification test or the alternative
(abbreviated) stratification test in section 6.5.6.2 of this
appendix is performed and passed prior to each subsequent RATA at
the location (according to the acceptance criteria of section
6.5.6.3(a) of this appendix).
(4) A single reference method measurement point, located no less
than 1.0 meter from the stack wall, may be used at any sampling
location if the 12-point stratification test described in section
6.5.6.1 of this appendix is performed and passed one time at the
location (according to the acceptance criteria of section 6.5.6.3(b)
of this appendix) and provided that either the 12-point
stratification test or the alternative (abbreviated) stratification
test in section 6.5.6.2 of this appendix is performed and passed
prior to each subsequent RATA at the location (according to the
acceptance criteria of section 6.5.6.3(b) of this appendix).
6.5.6.1 Stratification Test
(a) With the unit(s) operating under steady-state conditions at
normal load, as defined in section 6.5.2.1 of this appendix, use a
traversing gas sampling probe to measure the pollutant
(SO2 or NOX) and diluent (CO2 or
O2) concentrations at a minimum of twelve (12) points,
located according to Method 1 in appendix A to part 60 of this
chapter.
(b) Use Methods 6C, 7E, and 3A in appendix A to part 60 of this
chapter to make the measurements. Data from the reference method
analyzers must be quality assured by performing analyzer calibration
error and system bias checks before the series of measurements and
by conducting system bias and calibration drift checks after the
measurements, in accordance with the procedures of Methods 6C, 7E,
and 3A.
(c) Measure for a minimum of 2 minutes at each traverse point.
To the extent practicable, complete the traverse within a 2-hour
period.
(d) If the load has remained constant ( 3.0 percent)
during the traverse and if the reference method analyzers have
passed all of the required quality assurance checks, proceed with
the data analysis.
(e) Calculate the average NOX, SO2, and
CO2 (or O2) concentrations at each of the
individual traverse points. Then, calculate the arithmetic average
NOX, SO2, and CO2 (or
O2) concentrations for all traverse points.
6.5.6.2 Alternative (Abbreviated) Stratification Test
(a) With the unit(s) operating under steady-state conditions at
normal load, as defined in section 6.5.2.1 of this appendix, use a
traversing gas sampling probe to measure the pollutant
(SO2 or NOX) and diluent (CO2 or
O2) concentrations at three points. The points shall be located
according to the specifications for the long measurement line in
section 3.2 of PS No. 2 (i.e., locate the points 16.7 percent, 50.0
percent, and 83.3 percent of the way across the stack).
Alternatively, the concentration measurements may be made at six
traverse points along a diameter. The six points shall be located in
accordance with Method 1 in appendix A to part 60 of this chapter.
(b) Use Methods 6C, 7E, and 3A in appendix A to part 60 of this
chapter to make the measurements. Data from the reference method
analyzers must be quality assured by performing analyzer calibration
error and system bias checks before the series of measurements and
by conducting system bias and calibration drift checks after the
measurements, in accordance with the procedures of Methods 6C, 7E,
and 3A.
(c) Measure for a minimum of 2 minutes at each traverse point.
To the extent practicable, complete the traverse within a 1-hour
period.
(d) If the load has remained constant ( 3.0 percent)
during the traverse and if the reference method analyzers have
passed all of the required quality assurance checks, proceed with
the data analysis.
(e) Calculate the average NOX, SO2, and
CO2 (or O2) concentrations at each of the
individual traverse points. Then, calculate the arithmetic average
NOX, SO2, and CO2 (or
O2) concentrations for all traverse points.
6.5.6.3 Stratification Test Results and Acceptance Criteria
(a) For each pollutant or diluent gas, the short reference
method measurement line described in section 3.2 of PS No. 2 may be
used in lieu of the long measurement line prescribed in section 3.2
of PS No. 2, if the results of a stratification test, conducted in
accordance with section 6.5.6.1 or 6.5.6.2 of this appendix (as
appropriate; see section 6.5.6(b)(3) of this appendix), show that
the concentration at each individual traverse point differs by no
more than 10.0 percent from the arithmetic average
concentration for all traverse points. The results are also
acceptable if the concentration at each individual traverse point
differs by no more than 5 ppm or 0.5 percent
CO2 (or O2) from the arithmetic average
concentration for all traverse points.
(b) For each pollutant or diluent gas, a single reference method
measurement point, located at least 1.0 meter from the stack wall
may be used for that pollutant or diluent gas if the results of a
stratification test, conducted in accordance with section 6.5.6.1 or
6.5.6.2 of this appendix (as appropriate; see section 6.5.6(b)(4) of
this appendix), show that the concentration at each individual
traverse point differs by no more than 5.0 percent from
the arithmetic average concentration for all traverse points. The
results are also acceptable if the concentration at each individual
traverse point differs by no more than 3 ppm or
0.3 percent CO2 (or O2) from the
arithmetic average concentration for all traverse points.
(c) The owner or operator shall keep the results of all
stratification tests on-site, suitable for inspection, as part of
the supplementary RATA records required under Sec. 75.56(a)(7) or
Sec. 75.59(a)(7), as applicable.
6.5.7 Sampling Strategy
Conduct the reference method tests so they will yield results
representative of the pollutant concentration, emission rate,
moisture, temperature, and flue gas flow rate from the unit and can
be correlated with the pollutant concentration monitor,
CO2 or O2 monitor, flow monitor, and
SO2 or NOX continuous emission monitoring
system measurements. The minimum acceptable time for a gas
monitoring system RATA run or for a moisture monitoring system RATA
run is 21 minutes. For each run of a gas monitoring system RATA, all
necessary pollutant concentration measurements, diluent
concentration measurements, and moisture measurements (if
applicable) must, to the extent practicable, be made within a 60-
minute period. For NOX-diluent or SO2-diluent
monitoring system RATAs, the pollutant and diluent concentration
measurements must be made simultaneously. For flow monitor RATAs,
the minimum time per run shall be 5 minutes. Flow rate reference
method measurements may be made either sequentially from port to
port or simultaneously at two or more sample ports. The velocity
measurement probe may be moved from traverse point to traverse point
either manually or automatically. If, during a flow RATA,
significant pulsations in the reference method readings are
observed, be sure to allow enough measurement time at each traverse
point to obtain an accurate average reading (e.g., a ``sight-
weighted'' average from a manometer). A minimum of one set of
auxiliary measurements for stack gas molecular weight determination
(i.e., diluent gas data and moisture data) is required for every
clock hour of a flow RATA or for every three test runs (whichever is
less restrictive). Successive flow RATA runs may be performed
without waiting in-between runs. If an O2-diluent monitor
is used as a CO2 continuous emission monitoring system,
perform a CO2 system RATA (i.e., measure CO2,
rather than O2, with the reference method). To properly
correlate individual SO2 or NOX continuous
emission monitoring system data (in lb/mmBtu) and volumetric flow
rate data with the reference method data, annotate the beginning and
end of each reference method test run (including the exact time of
day) on the individual chart recorder(s) or other permanent
recording device(s).
* * * * *
6.5.9 Number of Reference Method Tests
Perform a minimum of nine sets of paired monitor (or monitoring
system) and reference method test data for every required (i.e.,
certification, recertification, semiannual, or annual) relative
accuracy test audit. For 2-level and 3-level relative accuracy test
audits of flow monitors, perform a minimum of nine sets at each of
the operating levels.
Note: The tester may choose to perform more than nine sets of
reference method tests. If this option is chosen, the tester may
reject a maximum of three sets of the test results, as long as the
total number of test
[[Page 28167]]
results used to determine the relative accuracy or bias is greater
than or equal to nine. Report all data, including the rejected CEM
data and corresponding reference method test results.
* * * * *
58. Section 7 of appendix A to part 75 is amended by revising the
introductory text of section 7.2.1 and the term ``R'' following
equation A-5 and by revising section 7.6.4; and by adding 4 paragraphs
at the end of section 7.6.5 and a new section 7.7 to read as follows:
7. Calculations
* * * * *
7.2 * * *
7.2.1 Pollutant Concentration and Diluent Monitors
For each reference value, calculate the percentage calibration
error based upon instrument span for daily calibration error tests
using the following equation:
* * * * *
(Eq. A-5)
Where:
R=Reference value of zero or upscale (high-level or mid-level, as
applicable) calibration gas introduced into the monitoring system.
* * * * *
7.6.4 Bias Test
For gas monitoring systems, if the mean difference, d, is
greater than the absolute value of the confidence coefficient, |cc|,
the monitor or monitoring system has failed to meet the bias test
requirement. For flow monitor bias tests, if the mean difference, d,
is greater than |cc| at any load level designated as normal under
section 6.5.2.1 of this appendix, the monitor has failed to meet the
bias test requirement.
7.6.5 * * *
For single-load RATAs of SO2-and NOX-
diluent monitoring systems and for single-load flow RATAs required
or allowed under section 6.5.2 of this appendix and sections
2.3.1.3(b) and 2.3.1.3(c) of appendix B to this part, the
appropriate BAF is determined directly from the RATA results at
normal load, using Equation A-12. Notwithstanding, when a
NOX or SO2 CEMS installed on a low-emitting
affected unit (i.e., average SO2 concentration during the
RATA <250 ppm or average NOX emission rate <0.200 lb/
mmBtu) meets the normal 10.0 percent relative accuracy specification
(as calculated using Equation A-10) or the alternate relative
accuracy specification in section 3.3 of this appendix for low-
emitters, but fails the bias test, the BAF may be determined using
Equation A-12, or a default BAF of 1.111 may be used.
For a 2-level flow RATA, if the RATA is passed but the bias test
is failed at a load level designated as normal under section 6.5.2.1
of this appendix, use Equation A-12 to calculate the bias adjustment
factor at both of the operating levels. For a 3-level flow monitor
relative accuracy test audit, if the RATA is passed but the bias
test is failed at a load level designated as normal under section
6.5.2.1 of this appendix, calculate bias adjustment factors only for
the two most-frequently used load levels, as determined in section
6.5.2.1 of this appendix. For both 2-level and 3-level flow RATAs,
whenever the bias test is failed at a load level designated as
normal under section 6.5.2.1 of this appendix, apply the larger of
the two calculated bias adjustment factors to subsequent flow
monitor data using Equation A-11.
Each time a RATA is successfully completed and the appropriate
bias adjustment factor has been determined, apply the BAF
prospectively to all monitoring system data, beginning with the
first clock hour following the hour in which the RATA was completed.
For a 2-load flow RATA, the ``hour in which the RATA was completed''
refers to the hour in which the testing at both loads was completed;
for a 3-load RATA, it refers to the hour in which the testing at all
three loads was completed.
Use the bias-adjusted values in computing substitution values in
the missing data procedure, as specified in subpart D of this part,
and in reporting the concentration of SO2, the flow rate,
and the average NOX emission rate, the unit heat input,
and the calculated mass emissions of SO2 and
CO2 during the quarter and calendar year, as specified in
subpart G of this part.
7.7 Reference Flow-to-Load Ratio or Gross Heat Rate
The owner or operator shall determine Rref, the
reference value of the ratio of flow rate to unit load, each time
that a successful flow RATA is performed at a load level designated
as normal in section 6.5.2.1 of this appendix. The owner or operator
shall report the current value of Rref in the electronic
quarterly report required under Sec. 75.64 and shall also report the
completion date of the associated RATA. If two load levels have been
designated as normal under section 6.5.2.1 of this appendix, the
owner or operator shall determine a separate Rref value
for each of the normal load levels. The requirements of this section
shall become effective as of January 1, 2000. The reference flow-to-
load ratio shall be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TP21MY98.007
(Eq. A-13)
Where:
Rref=Reference value of the flow-to-load ratio, from the
most recent normal-load flow RATA, scfh/megawatts or scfh/1000 lb/hr
of steam.
Qref=Average stack gas volumetric flow rate measured by
the reference method during the normal-load RATA, scfh.
Lavg=Average unit load during the normal-load flow RATA,
megawatts or 1000 lb/hr of steam.
In Equation A-13, for a common stack, Lavg shall be
the sum of the operating loads of all units that discharge through
the stack. For a unit that discharges its emissions through multiple
stacks, Qref will be the sum of the total volumetric flow
rates that discharge through all of the stacks. Round off the value
of Rref to 2 decimal places.
In addition to determining Rref or as an alternative
to determining Rref, a reference value of the gross heat
rate (GHR) may be determined. In order to use this option, quality
assured diluent gas (CO2 or O2) must be
available for each hour of the most recent normal-load flow RATA.
The reference value of the GHR shall be determined as follows:
[GRAPHIC] [TIFF OMITTED] TP21MY98.008
(Eq. A-13a)
Where:
(GHR)ref=Reference value of the gross heat rate at the
time of the most recent normal-load flow RATA, Btu/kwh or Btu/lb
steam load.
(Heat Input)avg=Average hourly heat input during the
normal-load flow RATA, as determined using the applicable equation
in appendix F to this part, mmBtu/hr.
Lavg=Average unit load during the normal-load flow RATA,
megawatts or 1000 lb/hr of steam.
In the calculation of (Heat Input)avg, use
Qref, the average volumetric flow rate measured by the
reference method during the RATA, and use the average diluent gas
concentration measured during the flow RATA.
* * * * *
59. Section 1 of appendix B to part 75 is revised as follows:
Appendix B to Part 75--Quality Assurance and Quality Control
Procedures
1. Quality Assurance/Quality Control Program
Develop and implement a quality assurance/quality control (QA/
QC) program for the continuous emission monitoring systems, excepted
monitoring systems approved under appendix D, E, or I to this part,
and alternative monitoring systems under subpart E of this part, and
their components. At a minimum, include in each QA/QC program a
written plan that describes in detail (or that refers to separate
documents containing) complete, step-by-step procedures and
operations for each of the following activities. Upon request from
regulatory authorities, the source shall make all procedures,
maintenance records, and ancillary supporting documentation from the
manufacturer (e.g., software coefficients and troubleshooting
diagrams) available for review during an audit.
1.1 Requirements for All Monitoring Systems
1.1.1 Preventive Maintenance
Keep a written record of procedures needed to maintain the
monitoring system in proper operating condition and a schedule for
those procedures. This shall, at a minimum, include procedures
specified by the manufacturers of the equipment and, if applicable,
additional or alternate procedures developed for the equipment.
[[Page 28168]]
1.1.2 Recordkeeping and Reporting
Keep a written record describing procedures that will be used to
implement the recordkeeping and reporting requirements in subparts
E, F, and G and appendices D, E, and I of this part, as applicable.
1.1.3 Maintenance Records
Keep a record of all testing, maintenance, or repair activities
performed on any monitoring system or component in a location and
format suitable for inspection. A maintenance log may be used for
this purpose. The following records should be maintained: date,
time, and description of any testing, adjustment, repair,
replacement, or preventive maintenance action performed on any
monitoring system and records of any corrective actions associated
with a monitor's outage period. Additionally, any adjustment that
recharacterizes a system's ability to record and report emissions
data must be recorded (e.g., changing flow monitor polynomial
coefficients, temperature and pressure coefficients, and dilution
ratio settings), and a written explanation of the procedures used to
make the adjustment(s) shall be kept.
1.2 Specific Requirements for Continuous Emissions Monitoring
Systems
1.2.1 Calibration Error Test and Linearity Check Procedures
Keep a written record of the procedures used for daily
calibration error tests and linearity checks (e.g., how gases are to
be injected, adjustments of flow rates and pressure, introduction of
reference values, length of time for injection of calibration gases,
steps for obtaining calibration error or error in linearity,
determination of interferences, and when calibration adjustments
should be made). Identify any calibration error test and linearity
check procedures specific to the continuous emission monitoring
system that vary from the procedures in appendix A to this part.
1.2.2 Calibration and Linearity Adjustments
Explain how each component of the continuous emission monitoring
system will be adjusted to provide correct responses to calibration
gases, reference values, and/or indications of interference both
initially and after repairs or corrective action. Identify
equations, conversion factors, assumed moisture content, and other
factors affecting calibration of each continuous emission monitoring
system.
1.2.3 Relative Accuracy Test Audit Procedures
Keep a written record of procedures and details peculiar to the
installed continuous emission monitoring systems that are to be used
for relative accuracy test audits, such as sampling and analysis
methods.
1.2.4 Parametric Monitoring for Units with Add-on Emission Controls
The owner or operator shall keep a written (or electronic)
record including a list of operating parameters for the add-on
SO2 or NOX emission controls, including
parameters in Sec. 75.55(b) or Sec. 75.58(b), as applicable, and the
range of each operating parameter that indicates the add-on emission
controls are operating properly. The owner or operator shall keep a
written (or electronic) record of the parametric monitoring data
during each SO2 or NOX missing data period.
1.3 Specific Requirements for Excepted Systems Approved under
Appendices D, E, and I
1.3.1 Fuel Flowmeter Accuracy Test Procedures
Keep a written record of the specific fuel flowmeter accuracy
test procedures. These may include: standard methods or
specifications listed in Sec. 75.20(g) and section 2.1.5.1 of
appendix D to this part and incorporated by reference under
Sec. 75.6; the procedures of sections 2.1.5.2 or 2.1.7 of appendix D
to this part; or other methods approved by the Administrator through
the petition process of Sec. 75.66(c).
1.3.2 Transducer or Transmitter Accuracy Test Procedures
Keep a written record of the procedures for testing the accuracy
of transducers or transmitters of an orifice-, nozzle-, or venturi-
type fuel flowmeter under section 2.1.6 of appendix D to this part.
These procedures should include a description of equipment used,
steps in testing, and frequency of testing.
1.3.3 Fuel Flowmeter, Transducer, or Transmitter Calibration and
Maintenance Records
Keep a record of adjustments, maintenance, or repairs performed
on the fuel flowmeter monitoring system. Keep records of the data
and results for fuel flowmeter accuracy tests and transducer
accuracy tests, consistent with appendix D to this part.
1.3.4 Primary Element Inspection Procedures
Keep a written record of the standard operating procedures for
inspection of the primary element (i.e., orifice, venturi, or
nozzle) of an orifice-, venturi-, or nozzle-type fuel flowmeter.
Examples of the types of information to be included are: what to
examine on the primary element; how to identify if there is
corrosion sufficient to affect the accuracy of the primary element;
and what inspection tools (e.g., boroscope), if any, are used.
1.3.5 Fuel Sampling Method and Sample Retention
Keep a written record of the standard procedures used to perform
fuel sampling, either by utility personnel or by fuel supply company
personnel. These procedures should specify the portion of the ASTM
method used, as incorporated by reference under Sec. 75.6, or other
methods approved by the Administrator through the petition process
of Sec. 75.66(c). These procedures should describe safeguards for
ensuring the availability of an oil sample (e.g., procedure and
location for splitting samples, procedure for maintain sample splits
on site, and procedure for transmitting samples to an analytical
laboratory). These procedures should identify the ASTM analytical
methods used to analyze sulfur content, gross calorific value, and
density, as incorporated by reference under Sec. 75.6, or other
methods approved by the Administrator through the petition process
of Sec. 75.66(c).
1.3.6 Appendix E Monitoring System Quality Assurance Information
Identify the unit manufacturer's recommended range of quality
assurance- and quality control-related operating parameters. Keep
records of these operating parameters for each hour of unit
operation (i.e., fuel combustion). Keep a written record of the
procedures used to perform NOX emission rate testing.
Keep a copy of all data and results from the initial and from the
most recent NOX emission rate testing, including the
values of quality assurance parameters specified in section 2.3 of
appendix E to this part.
1.3.7 Appendix I Additional Requirements
1.3.7.1 For all appendix I systems, the fuel sampling and
analysis requirements in section 1.3.5 of this appendix shall be
met; and, for the diluent monitor, the Calibration Error Test and
Linearity Check Procedures requirements in sections 1.2.1 and 1.2.2
of this appendix shall be met.
1.3.7.2 For appendix I systems that are certified according to
the system certification procedures, the Relative Accuracy Test
Audit Procedures requirement in section 1.2.3 of this appendix shall
be met for the annual or semiannual Method 2 flow RATA.
1.3.7.3 For appendix I systems that are certified according to
the component-by-component certification procedures, the fuel
flowmeter requirements applicable to the type of fuel flowmeter used
in sections 1.3.1 through 1.3.5 of this appendix shall be met. The
Relative Accuracy Test Audit Procedures requirement in section 1.2.3
of this appendix shall be met for the diluent monitor that is part
of the appendix I system.
1.4 Requirements for Alternative Systems Approved under Subpart E
1.4.1 Daily Quality Assurance Tests
Explain how the daily assessment procedures specific to the
alternative monitoring system are to be performed.
1.4.2 Daily Quality Assurance Test Adjustments
Explain how each component of the alternative monitoring system
will be adjusted in response to the results of the daily
assessments.
1.4.3 Relative Accuracy Test Audit Procedures
Keep a written record of procedures and details peculiar to the
installed alternative monitoring system that are to be used for
relative accuracy test audits, such as sampling and analysis
methods.
60. Section 2 of appendix B to part 75 is amended by:
a. Revising sections 2.1.1, 2.1.3, 2.1.4, 2.2, 2.3; revising
paragraph (1) of section 2.1.5.1;
b. Redesignating existing section 2.4 as section 2.5; and
c. Adding a new section 2.4, to read as follows:
[[Page 28169]]
2. Frequency of Testing
* * * * *
2.1 * * *
2.1.1 Calibration Error Test
Except as provided in section 2.1.1.2 of this appendix, perform
the daily calibration error test of each gas monitoring system
(including moisture monitoring systems consisting of wet- and dry-
basis O2 analyzers) according to the procedures in
section 6.3.1 of appendix A to this part, and perform the daily
calibration error test of each flow monitoring system according to
the procedure in section 6.3.2 of appendix A to this part. For
continuous moisture sensors, follow the manufacturer's recommended
procedures for the daily calibration error check. Include the
calibration procedures as part of the quality assurance program
required under section 1 of this appendix.
* * * * *
2.1.3 Additional Calibration Error Tests and Calibration Adjustments
In addition to the daily calibration error tests required under
section 2.1.1 of this appendix, a calibration error test of a CEMS
shall be performed in accordance with section 2.1.1 of this
appendix, as follows: (1) whenever a daily calibration error test is
failed; (2) whenever a monitoring system is returned to service
following repair or corrective maintenance that could affect the
monitor's ability to accurately measure and record emissions data;
and (3) after making certain calibration adjustments, as described
in this section. In all cases, data from the CEMS are considered
invalid until the required additional calibration error test has
been successfully completed.
Routine calibration adjustments of a monitor are permitted after
any successful calibration error test. These routine adjustments
shall be made so as to bring the monitor readings as close as
practicable to the known tag values of the calibration gases or to
the actual value of the flow monitor reference signals. An
additional calibration error test is required following routine
calibration adjustments where the monitor's calibration has been
physically adjusted (e.g., by turning a potentiometer) to verify
that the adjustments have been made properly. An additional
calibration error test is not required, however, if the routine
calibration adjustments are made by means of a mathematical
algorithm programmed into the data acquisition and handling system.
The EPA recommends that routine calibration adjustments be made, at
a minimum, whenever the daily calibration error exceeds the limits
of the applicable performance specification in appendix A to this
part for the pollutant concentration monitor, CO2 or
O2 monitor, or flow monitor.
Additional (non-routine) calibration adjustments of a monitor
are permitted, provided that an appropriate technical justification
is included in the quality control program required under section 1
of this appendix. The allowable non-routine adjustments are as
follows. The owner or operator may physically adjust the calibration
of a monitor (e.g., by means of a potentiometer), provided that the
post-adjustment zero and upscale responses of the monitor are within
the performance specifications of the instrument given in section
3.1 of appendix A to this part. An additional calibration error test
is required following such adjustments to verify that the monitor is
operating within the performance specifications.
2.1.4 Data Validation
(a) An out-of-control period occurs when the calibration error
of an SO2 or NOX pollutant concentration
monitor exceeds 5.0 percent of the span value (or exceeds 10 ppm,
for span values <200 ppm), when the calibration error of a
CO2 or O2 monitor (including O2
monitors used to measure CO2 emissions or percent
moisture) exceeds 1.0 percent O2 or CO2, or
when the calibration error of a flow monitor or a moisture sensor
exceeds 6.0 percent of the span value, which is twice the applicable
specification of appendix A to this part. Notwithstanding, a
differential pressure-type flow monitor for which the calibration
error exceeds 6.0 percent of the span value shall not be considered
out-of-control if |R-A|, the absolute value of the difference
between the monitor response and the reference value in Equation A-
6, is 0.02 inches of water. The out-of-control period
begins with the hour of completion of the failed calibration error
test and ends with the hour following the hour of completion of a
successful calibration error test. Note, however, that if the failed
calibration, corrective action, and successful calibration error
test occur within the same hour, emission data for that hour
recorded by the monitor after the successful calibration error test
may be used for reporting purposes, provided that 2 or more valid
readings are obtained as required by Sec. 75.10. A NOX-
diluent continuous emission monitoring system is considered out-of-
control if the calibration error of either component monitor exceeds
twice the applicable performance specification in appendix A to this
part. Emission data shall not be reported from an out-of-control
monitor.
(b) An out-of-control period also occurs whenever interference
of a flow monitor is identified. The out-of-control period begins
with the hour of completion of the failed interference check and
ends with the hour of completion of an interference check that is
passed.
2.1.5 * * *
2.1.5.1 * * *
(1) Data from a monitoring system are invalid, beginning with
the first hour following the expiration of a 26-hour data validation
period or beginning with the first hour following the expiration of
an 8-hour start-up grace period (as provided under section 2.1.5.2
of this appendix), if the required subsequent daily assessment has
not been conducted.
* * * * *
2.2 Quarterly Assessments
For each primary and redundant backup continuous emission
monitoring system, perform the following quarterly assessments. This
requirement is effective as of the calendar quarter following the
calendar quarter in which the monitor or continuous emission
monitoring system is provisionally certified.
2.2.1 Linearity Check
Perform a linearity check, in accordance with the procedures in
section 6.2 of appendix A to this part, for each primary and
redundant backup SO2 and NOX pollutant
concentration monitor and each primary and redundant backup
CO2 or O2 monitor (including O2
monitors used to measure CO2 emissions or to continuously
monitor moisture) at least once during each QA operating quarter. A
QA operating quarter is a calendar quarter in which the unit
operates (i.e., combusts fuel) for at least 168 hours or, for common
stacks and bypass stacks, a calendar quarter in which flue gases are
discharged through the stack for at least 168 hours. For units using
both a low and high span value, a linearity check is required only
on the range(s) used to record and report emission data during the
QA operating quarter. Conduct the linearity checks no less than 30
days apart, to the extent practicable. The data validation
procedures in section 2.2.3 of this appendix shall be followed.
2.2.2 Leak Check
For differential pressure flow monitors, perform a leak check of
all sample lines (a manual check is acceptable) at least once during
each QA operating quarter. For this test, the unit does not have to
be in operation. Conduct the leak checks no less than 30 days apart,
to the extent practicable. If a leak check is failed, follow the
applicable data validation procedures in section 2.2.3(f) of this
appendix.
2.2.3 Data Validation
(a) A routine quality assurance linearity test shall not be
commenced if the monitoring system is operating out-of-control with
respect to any of the daily, quarterly, or semiannual quality
assurance assessments required by sections 2.1, 2.2, and 2.3 of this
appendix or with respect to the additional calibration error test
requirements in section 2.1.3 of this appendix.
(b) Linearity checks shall be done hands-off, as follows. No
adjustments of the monitor are permitted prior to or during the
linearity test period, other than the routine and non-routine
calibration adjustments described in section 2.1.3 of this appendix.
The non-routine adjustments are permitted only prior to the test,
not during the test period.
(c) If a daily calibration error test is failed during a
linearity test period, prior to completing the test, the linearity
test is invalidated and must be repeated. Data from the monitor are
invalidated prospectively from the hour of the failed calibration
error test until the hour of completion of a subsequent successful
calibration error test. The linearity test shall not be re-commenced
until the monitor has successfully completed a calibration error
test.
(d) An out-of-control period occurs when a linearity test is
failed (i.e., when the error in linearity at any of the three
concentrations in the quarterly linearity check (or any of the six
concentrations, when both ranges of a single analyzer with a dual
range are tested) exceeds the applicable specification in
[[Page 28170]]
section 3.2 of appendix A to this part) or when a linearity test is
aborted due to a problem with the CEMS. For a NOX-diluent
or SO2-diluent continuous emission monitoring system, the
system is considered out-of-control if either of the component
monitors exceeds the applicable specification in section 3.2 of
appendix A to this part or if the linearity test of either component
is aborted due to a problem with the monitor. The out-of-control
period begins with the hour of the failed or aborted linearity check
and ends with the hour of completion of a satisfactory linearity
check following corrective action and/or monitor repair. Note that a
monitor shall not be considered out-of-control when a linearity test
is aborted for a reason unrelated to the monitor's performance
(e.g., a forced unit outage).
(e) No more than four successive calendar quarters shall elapse
after the quarter in which a linearity check of a CEMS (or range of
a CEMS) was last performed without a subsequent linearity test
having been conducted. If a linearity test has not been completed by
the end of the fourth calendar quarter since the last linearity
test, then the linearity test must be completed within a 168 unit
operating hour ``grace period'' (as provided in section 2.2.4 of
this appendix) following the end of the fourth successive elapsed
calendar quarter, or data from the CEMS (or range) will become
invalid.
(f) An out-of-control period also occurs when a flow monitor
sample line leak is detected. The out-of-control period begins with
the hour of the failed leak check and ends with the hour of a
satisfactory leak check following corrective action.
(g) For each monitoring system, report the results of all
completed and partial linearity tests that affect data validation
(i.e., all completed, passed linearity checks; all completed, failed
linearity checks; and all linearity checks aborted due to a problem
with the monitor) in the quarterly report required under Sec. 75.64.
Note that linearity attempts which are aborted or invalidated due to
problems with the reference calibration gases or due to operational
problems with the affected unit(s) need not be reported. Such
partial tests do not affect the validation status of emission data
recorded by the monitor. However, a record of all linearity tests
and attempts (whether reported or not) must be kept on-site as part
of the official test log for each monitoring system.
2.2.4 Linearity and Leak Check Grace Period
When a required linearity test or flow monitor leak check has
not been completed by the end of the QA operating quarter in which
it is due or if, due to infrequent operation of a unit or infrequent
use of a required high range of a CEMS, four successive calendar
quarters have elapsed after the quarter in which a linearity check
of a CEMS (or range) was last performed without a subsequent
linearity test having been done, the owner or operator has a grace
period of 168 consecutive unit operating hours in which to perform a
linearity test or leak check of that CEMS (or range). The grace
period begins with the first unit operating hour following the
calendar quarter in which the linearity test was due. Data
validation during a linearity or leak check grace period shall be
done in accordance with the applicable provisions in section 2.2.3
of this appendix.
If, at the end of the 168 unit operating hour grace period, the
required linearity test or leak check has not been completed, data
from the monitoring system (or range) shall be invalid, beginning
with the hour following the expiration of the grace period. Data
from the monitoring system (or range) remain invalid until the hour
of completion of a subsequent successful hands-off linearity test or
leak check of the CEMS (or range). Note that when a linearity test
or a leak check is conducted within a grace period for the purpose
of satisfying the linearity test or leak check requirement from a
previous QA operating quarter, the results of that linearity test or
leak check may only be used to meet the linearity check or leak
check requirement of the previous quarter, not the quarter in which
the grace period is used.
2.2.5 Flow-to-Load Ratio or Gross Heat Rate Evaluation
For each installed flow rate monitoring system on each unit or
common stack, the owner or operator shall evaluate the flow-to-load
ratio quarterly, i.e., for each QA operating quarter, as defined in
sections 2.2.1 and 2.3.1.1 of this appendix. At the end of each QA
operating quarter, the owner or operator shall use Equation B-1 in
this appendix to calculate the flow-to-load ratio for every hour
during the quarter in which: (1) the unit (or combination of units,
for a common stack) operated within 10.0 percent of
Lavg, the average load during the most recent normal-load
flow RATA; and (2) a quality assured hourly average flow rate was
obtained with a certified flow rate monitor.
[GRAPHIC] [TIFF OMITTED] TP21MY98.009
(Eq. B-1)
Where:
Rh = Hourly value of the flow-to-load ratio, scfh/
megawatts or scfh/1000 lb/hr of steam load.
Qh = Hourly stack gas volumetric flow rate, as measured
by the flow rate monitor, scfh.
Lh = Hourly unit load, megawatts or 1000 lb/hr of steam;
must be within 10.0 percent of Lavg during
the most recent normal-load flow RATA.
In Equation B-1, the owner or operator may use either bias-
adjusted flow rates or unadjusted flow rates, provided that all of
the ratios are calculated the same way. For a common stack,
Lh shall be the sum of the hourly operating loads of all
units that discharge through the stack. For a unit that discharges
its emissions through multiple stacks or monitors its emissions in
multiple breechings, Qh will be the combined hourly volumetric flow
rate for all of the stacks or ducts. Round off each value of
Rh to 2 decimal places.
Alternatively, the owner or operator may calculate the hourly
gross heat rates (GHR) in lieu of the hourly flow-to-load ratios.
The hourly GHR shall be determined only for those hours in which
quality assured flow rate data and diluent gas (CO2 or
O2) concentration data are both available from a
certified CEMS or reference method. If this option is selected,
calculate each hourly GHR value as follows:
[GRAPHIC] [TIFF OMITTED] TP21MY98.010
(Eq. B-1a)
Where:
(GHR)h = Hourly value of the gross heat rate, Btu/kwh or
Btu/lb steam load.
(Heat Input)h = Hourly heat input, as determined from the
quality assured flow rate and diluent data, using the applicable
equation in appendix F to this part, mmBtu/hr.
Lh = Hourly unit load, megawatts or 1000 lb/hr of steam;
must be within 10.0 percent of Lavg during
the most recent normal-load flow RATA.
In Equation B-1a, the owner or operator may either use bias-
adjusted flow rates or unadjusted flow rates in the calculation of
(Heat Input)h, provided that all of the heat input values are
determined in the same manner.
The owner or operator shall evaluate the calculated hourly flow-
to-load ratios (or gross heat rates) as follows. A separate data
analysis shall be performed for each primary and each redundant
backup flow rate monitor used to record and report data during the
quarter. Each analysis shall be based on a minimum of 168 hours of
data. When two RATA load levels are designated as normal, the
analysis shall be performed at the higher load level, unless there
are fewer than 168 data points available at that load level, in
which case the analysis shall be performed at the lower load level.
If, for a particular flow monitor, fewer than 168 hourly flow-to-
load ratios (or GHR values) are available at any of the load levels
designated as normal, a flow-to-load (or GHR) evaluation is not
required for that monitor for that calendar quarter.
For each flow monitor, use Equation B-2 in this appendix to
calculate Eh, the absolute percentage difference between
each hourly Rh value and Rref, the reference
value of the flow-to-load ratio, as determined in accordance with
section 7.7 of appendix A to this part. Note that Rref
shall always be based upon the most recent normal-load RATA, even if
that RATA was performed in the calendar quarter being evaluated.
[GRAPHIC] [TIFF OMITTED] TP21MY98.011
(Eq. B-2)
Where:
Eh = Absolute percentage difference between the hourly
average flow-to-load ratio and the reference value of the flow-to-
load ratio at normal load.
Rh = The hourly average flow-to-load ratio, for each flow
rate recorded at a load level within 10.0 percent of
Lavg.
[[Page 28171]]
Rref = The reference value of the flow-to-load ratio from
the most recent normal-load flow RATA, determined in accordance with
section 7.7 of appendix A to this part.
Equation B-2 shall be used in a consistent manner. That is, use
Rref and Rh if the flow-to-load ratio is being
evaluated, and use (GHR)ref and (GHR)h if the
gross heat rate is being evaluated. Finally, calculate
Ef, the arithmetic average of all of the hourly
Eh values. The owner or operator shall report the results
of each quarterly flow-to-load (or gross heat rate) evaluation, as
determined from Equation B-2, in the electronic quarterly report
required under Sec. 75.64.
The results of a quarterly flow-to-load (or gross heat rate)
evaluation are acceptable, and no further action is required, if the
calculated value of Ef is less than or equal to: (i) 15.0
percent, if Lavg for the most recent normal-load flow
RATA is 50 megawatts (or 500 klb/hr of steam)
and if unadjusted flow rates were used in the calculations; (ii)
10.0 percent, if Lavg for the most recent normal-load
flow RATA is 50 megawatts (or 500 klb/hr of
steam) and if bias-adjusted flow rates were used in the
calculations; (iii) 20.0 percent, if Lavg for the most
recent normal-load flow RATA is <50 megawatts (or <500 klb/hr of
steam) and if unadjusted flow rates were used in the calculations;
or (iv) 15.0 percent, if Lavg for the most recent normal-
load flow RATA is <50 megawatts (or <500 klb/hr of steam) and if
bias-adjusted flow rates were used in the calculations.
If Ef is above these limits, the owner or operator
shall: (a) implement Option 1 in section 2.2.5.1 of this appendix;
(b) perform a RATA in accordance with Option 2 in section 2.2.5.2 of
this appendix; or (c) re-examine the hourly data used for the flow-
to-load or GHR analysis and recalculate Ef, after
excluding all non-representative hourly flow rates.
If the owner or operator chooses to recalculate Ef,
the flow rates for the following hours are considered non-
representative and may be excluded from the data analysis:
(1) Any hour in which the type of fuel combusted was different
from the fuel burned during the most recent normal-load RATA. For
purposes of this determination, the type of fuel is different if the
fuel is in a different state of matter (i.e., solid, liquid, or gas)
than is the fuel burned during the RATA or if the fuel is a
different classification of coal (e.g., bituminous versus sub-
bituminous);
(2) Any hour in which an SO2 scrubber was bypassed;
(3) Any hour in which ``ramping'' occurred, i.e., the hourly
load differed by more than 15.0 percent from the load
during the preceding hour or the subsequent hour;
(4) If a normal-load flow RATA was performed and passed during
the quarter being analyzed, any hour prior to completion of that
RATA; and
(5) If a problem with the accuracy of the flow monitor was
discovered during the quarter and was corrected (as evidenced by
passing the abbreviated flow-to-load test in section 2.2.5.3 of this
appendix), any hour prior to completion of the abbreviated flow-to-
load test.
After identifying and excluding all non-representative hourly
data in accordance with (1) through (5) above, the owner or operator
may analyze the remaining data a second time. At least 168
representative hourly ratios or GHR values must be available to
perform the analysis; otherwise, the flow-to-load (or GHR) analysis
is not required for that monitor for that calendar quarter.
If, after re-analyzing the data, Ef meets the
applicable limit in (i),(ii), (iii), or (iv), above, no further
action is required. If, however, Ef is still above the
applicable limit, the monitor shall be declared out-of-control,
beginning with the first hour of the quarter following the quarter
in which Ef exceeded the applicable limit. The owner or
operator shall then either implement Option 1 in section 2.2.5.1 of
this appendix or Option 2 in section 2.2.5.2 of this appendix.
2.2.5.1 Option 1
Within one week of the end of the calendar quarter for which the
flow-to-load (or GHR) evaluation indicates noncompliance,
investigate and troubleshoot each flow monitor for which
Ef has been found to be above the applicable limit.
Evaluate the results of each investigation as follows:
(a) If the investigation fails to uncover a problem with the
flow monitor, a RATA shall be performed in accordance with Option 2
in section 2.2.5.2 of this appendix.
(b) If a problem with the flow monitor is identified through the
investigation (including the need to re-linearize the monitor by
changing the polynomial coefficients), corrective actions shall be
taken. All corrective actions (e.g., non-routine maintenance,
repairs, major component replacements, re-linearization of the
monitor, etc.) shall be documented in the operation and maintenance
records for the monitor. Data from the monitor shall remain invalid
until a probationary calibration error test of the monitor is passed
following completion of all corrective actions, at which point data
from the monitor are conditionally valid. The owner or operator
shall then either: (1) complete the abbreviated flow-to-load test in
section 2.2.5.3 of this appendix; or (2) perform a 3-level
recertification RATA according to the recertification test period
and data validation procedures of Sec. 75.20(b)(3), if the
corrective action has affected the linearity of the flow monitor
(e.g., by requiring changes to the flow monitor polynomial
coefficients).
2.2.5.2 Option 2
Perform a single-load RATA (at a load designated as normal under
section 6.5.2.1 of appendix A to this part) of each flow monitor for
which Ef is outside of the applicable limit. Data from
the monitor remain invalid until the required RATA has been
successfully completed.
2.2.5.3 Abbreviated Flow-to-Load Test
The following abbreviated flow-to-load test may be performed
after any documented repair, component replacement, or other
corrective maintenance to a flow monitor (except for changes
affecting the linearity of the flow monitor, such as adjusting the
flow monitor coefficients) to demonstrate that the repair,
replacement, or other maintenance has not significantly affected the
monitor's ability to accurately measure the stack gas volumetric
flow rate. Data from the monitoring system are considered invalid
from the hour of commencement of the repair, replacement, or
maintenance until the hour in which a probationary calibration error
test is passed following completion of the repair, replacement, or
maintenance and any associated adjustments to the monitor. The
abbreviated flow-to-load test shall be completed within 168 unit
operating hours of the probationary calibration error test (or, for
peaking units, within 30 unit operating days, if that is less
restrictive). Data from the monitor are considered to be
conditionally valid (as defined in Sec. 72.2 of this chapter),
beginning with the hour of the probationary calibration error test.
Operate the unit(s) in such a way as to reproduce, as closely as
practicable, the exact conditions at the time of the most recent
normal-load flow RATA. To achieve this, it is recommended that the
load be held constant to within 5.0 percent of the
average load during the RATA and that the diluent gas
(CO2 or O2) concentration be maintained within
0.5 percent CO2 or O2 of the
average diluent concentration during the RATA. For common stacks, to
the extent practicable, use the same combination of units and load
levels that were used during the RATA. When the process parameters
have been set, record a minimum of 6 and a maximum of 12 consecutive
hourly average flow rates, using the flow monitor(s) for which
Ef was outside the applicable limit. For peaking units, a
minimum of 3 and a maximum of 12 consecutive hourly average flow
rates are required. Also record the corresponding hourly load values
and, if applicable, the hourly diluent gas concentrations. Calculate
the flow-to-load ratio (or GHR) for each hour in the test hour
period, using Equation B-1 or B-1a. Determine Eh for each
hourly flow-to-load ratio (or GHR), using Equation B-2 of this
appendix and then calculate Ef, the arithmetic average of
the Eh values.
The results of the abbreviated flow-to-load test shall be
considered acceptable, and no further action is required if the
value of Ef does not exceed the applicable limit
specified in section 2.2.5.1 of this appendix. All conditionally
valid data recorded by the flow monitor shall be considered quality
assured, beginning with the hour of the probationary calibration
error test that preceded the abbreviated flow-to-load test. However,
if Ef is outside the applicable limit, all conditionally
valid data recorded by the flow monitor shall be considered invalid
back to the hour of the probationary calibration error test that
preceded the abbreviated flow-to-load test, and a single-load RATA
is required in accordance with section 2.2.5.2 of this appendix. If
the flow monitor must be re-linearized, however, a 3-load RATA is
required, in accordance with the recertification test period and
data validation procedures of Sec. 75.20(b)(3).
2.3 Semiannual and Annual Assessments
For each primary and redundant backup continuous emission
monitoring system, perform relative accuracy assessments either
[[Page 28172]]
semiannually or annually, as specified in subsection 2.3.1.1 or
2.3.1.2, below, for the type of test and the performance achieved.
This requirement is effective as of the calendar quarter following
the calendar quarter in which the continuous emission monitoring
system is provisionally certified. A summary chart showing the
frequency with which a relative accuracy test audit must be
performed, depending on the accuracy achieved, is located at the end
of this appendix in Figure 2.
2.3.1 Relative Accuracy Test Audit (RATA)
2.3.1.1 Standard RATA Frequencies
Except as otherwise specified in Sec. 75.21(a)(6) or (a)(7) or
in section 2.3.1.2 of this appendix, perform relative accuracy test
audits semiannually, i.e., once every two successive QA operating
quarters for each primary and redundant backup SO2
pollutant concentration monitor, flow monitor, CO2
pollutant concentration monitor (including O2 monitors used to
determine CO2 emissions), moisture monitoring system,
NOX-diluent continuous emission monitoring system, or
SO2-diluent continuous emission monitoring system used by
units with a Phase I qualifying technology for the period during
which the units are required to monitor SO2 emission
removal efficiency, from January 1, 1997 through December 31, 1999.
A QA operating quarter is a calendar quarter in which the unit
operates for at least 168 hours or, for a common stack or bypass
stack, a calendar quarter in which flue gases are discharged through
the stack for at least 168 hours. A calendar quarter that does not
qualify as a QA operating quarter shall be excluded in determining
the deadline for the next RATA. No more than eight successive
calendar quarters shall elapse after the quarter in which a RATA was
last performed without a subsequent RATA having been conducted. If a
RATA has not been completed by the end of the eighth calendar
quarter since the quarter of the last RATA, then the RATA must be
completed within a 720 unit operating hour grace period (as provided
in section 2.3.3 of this appendix) following the end of the eighth
successive elapsed calendar quarter, or data from the CEMS will
become invalid.
The relative accuracy test audit frequency of a CEMS may be
reduced, as specified in subsection 2.3.1.2, below, for primary or
redundant backup monitoring systems which qualify for less frequent
testing. Perform all required RATAs in accordance with the
applicable procedures and provisions in sections 6.5 through 6.5.2.2
of appendix A to this part and subsections 2.3.1.3 and 2.3.1.4 of
this appendix.
2.3.1.2 Reduced RATA Frequencies
Relative accuracy test audits of primary and redundant backup
SO2 pollutant concentration monitors, CO2
pollutant concentration monitors (including O2 monitors used to
determine CO2 emissions), moisture monitors, flow
monitors, or NOX-diluent or SO2-diluent
monitoring systems may be performed annually (i.e., once every four
successive QA operating quarters, rather than once every two
successive QA operating quarters) if any of the following conditions
are met for the specific monitoring system involved: (1) the
relative accuracy during the audit of an SO2 or
CO2 pollutant concentration monitor (including an O2
pollutant monitor used to measure CO2 using the
procedures in appendix F to this part) or of a NOX-
diluent or SO2-diluent continuous emissions monitoring
system is 7.5 percent; (2) prior to January 1, 2000, the
relative accuracy during the audit of a flow monitor is
10.0 percent at each operating level tested; (3) on and
after January 1, 2000, the relative accuracy during the audit of a
flow monitor is 7.5 percent at each operating level
tested; (4) on low flow (10.0 fps) stacks/ducts, when
flow monitor achieves a relative accuracy 7.5 percent
(10.0 percent if prior to January 1, 2000) during the audit or when
the monitor mean, calculated using Equation A-7 in appendix A to
this part, is within 1.5 fps of the reference method
mean; (5) on low SO2 emitting units (average
SO2 concentrations 250 ppm, or average SO2
emission rate 0.500 lb/mmBtu for SO2-diluent continuous
emission monitoring systems), when the CEMS achieves a relative
accuracy 7.5 percent during the audit or when the monitor
mean value from the RATA is within 12 ppm (or 0.025 lb/
mmBtu for SO2-diluent continuous emission monitoring
systems) of the reference method mean value; (6) on low
NOX emitting units (average NOX emission rate
0.200 lb/mmBtu), when the NOX continuous
emission monitoring system achieves a relative accuracy
7.5 percent or when the monitoring system mean value from
the RATA, calculated using Equation A-7 in appendix A to this part,
is within 0.015 lb/mmBtu of the reference method mean
value; (7) for a CO2 or O2 monitor, when the mean
difference between the reference method values from the RATA and the
corresponding monitor values is within 0.7 percent
CO2 or O2; and (8) when the relative accuracy of a
continuous moisture monitoring system is 7.5 percent or
when the mean difference between the reference method values from
the RATA and the corresponding monitoring system values is within
0.7 percent H2O.
2.3.1.3 RATA Load Levels
(a) For SO2 pollutant concentration monitors,
CO2 pollutant concentration monitors (including
O2 monitors used to determine CO2 emissions),
moisture monitoring systems, and SO2-diluent and
NOX-diluent monitoring systems, the required RATA tests
shall be done at the load level designated as normal under section
6.5.2.1 of appendix A to this part. If two load levels are
designated as normal, the required RATA(s) may be done at either
load level.
(b) For flow monitors installed on peaking units and bypass
stacks, all required relative accuracy test audits shall be single-
load audits at the normal load, as defined in section 6.5.2.1 of
appendix A to this part.
(c) For all other flow monitors, the RATAs shall be performed as
follows. When a flow monitor qualifies for an annual RATA frequency
under section 2.3.1.2 of this appendix, the annual RATA shall be
done at the two most frequently used load levels, as determined
under section 6.5.2.1 of appendix A to this part. The annual 2-load
flow RATA may be performed alternately with a single-load flow RATA
at the most frequently used (normal) load level if the flow monitor
is on a semiannual RATA frequency. In addition, a single-load flow
RATA, at the most frequently used load level, may be performed in
lieu of the 2-load RATA if, for the four QA operating quarters prior
to the quarter in which the RATA is performed, the historical load
frequency distribution determined under section 6.5.2.1 of appendix
A to this part shows that the unit has operated at the most
frequently used load level for 85.0 percent of the time.
Finally, a 3-load RATA, at the low-, mid-, and high-load levels,
determined under section 6.5.2.1 of appendix A to this part, shall
be performed at least once in every period of five consecutive
calendar years, and a 3-load RATA is required whenever a flow
monitor is re-linearized, i.e., when one or more of its polynomial
coefficients are changed. For all multi-level flow audits, the audit
points at adjacent load levels (e.g., mid and high) shall be
separated by no less than 25.0 percent of the ``range of
operation,'' as defined in section 6.5.2.1 of appendix A to this
part.
2.3.1.4 Number of RATA Attempts
The owner or operator may perform as many RATA attempts as are
necessary to achieve the desired relative accuracy test audit
frequencies and/or bias adjustment factors. However, the data
validation procedures in section 2.3.2 of this appendix must be
followed.
2.3.2 Data Validation
(a) A routine quality assurance RATA shall not commence if the
monitoring system is operating out-of-control with respect to any of
the daily and quarterly quality assurance assessments required by
sections 2.1 and 2.2 of this appendix or with respect to the
additional calibration error test requirements in section 2.1.3 of
this appendix.
(b) All RATAs must be done hands-off, as follows. No adjustment
of the monitor's calibration is permitted prior to or during the
RATA test period, other than the adjustments described in section
2.1.3 of this appendix. The non-routine calibration adjustments
described in section 2.1.3 of this appendix are permitted only prior
to the RATA, not during the test period. For 2-level and 3-level
flow monitor audits, no linearization of the monitor is permitted
in-between load levels.
(c) For single-load RATAs, if a daily calibration error test is
failed during a RATA test period, prior to completing the test, the
RATA is invalidated and must be repeated. Data from the monitor are
invalidated prospectively from the hour of the failed calibration
error test until the hour of completion of a subsequent successful
RATA. The subsequent RATA shall not be re-commenced until the
monitor has successfully passed a calibration error test in
accordance with section 2.1.3 of this appendix. For multiple-load
flow RATAs, each load level is treated as a separate RATA (i.e.,
when a calibration error test is failed prior to completing the RATA
at a particular load level, only the RATA at that load level is
invalidated; the results of any previously-passed RATA(s) at the
other load level(s) are unaffected).
(d) If a RATA is failed (that is, if the relative accuracy
exceeds the applicable
[[Page 28173]]
specification in section 3.3 of appendix A to this part) or if the
RATA is aborted prior to completion due to a problem with the CEMS,
then all emission data from the CEMS are invalidated prospectively
from the hour in which the RATA is failed or aborted. Data from the
CEMS remain invalid until the hour of completion of a subsequent
RATA that meets the applicable specification in section 3.3 of
appendix A to this part. Note that a monitoring system shall not be
considered out-of-control when a RATA is aborted for a reason other
than monitoring system malfunction (see paragraph (g) of this
section).
(e) For a 2-level or 3-level flow RATA, if, at any load level, a
RATA is failed or aborted due to a problem with the CEMS, the RATA
at that load level must be repeated. Data from the flow monitor are
invalidated from the hour in which the test is failed or aborted and
remain invalid until the successful completion of a RATA at the
failed load level. RATA(s) that were previously passed at the other
load level(s) do not have to be repeated unless the flow monitor
must be re-linearized following the failed or aborted test. If the
monitor is re-linearized, a subsequent 3-load RATA is required.
(f) For a CO2 pollutant concentration monitor (or an
O2 monitor used to measure CO2 emissions)
which also serves as the diluent component in a NOX-
diluent (or SO2-diluent) monitoring system, if the
CO2 (or O2) RATA is failed, then both the
CO2 (or O2) monitor and the associated
NOX-diluent (or SO2-diluent) system are
considered out-of-control until the hour of completion of subsequent
hands-off RATAs which demonstrate that both systems have met the
applicable relative accuracy specifications in sections 3.3.2 and
3.3.3 of appendix A to this part. The out-of-control period for each
monitoring system begins with the hour of completion of the failed
CO2 (or O2) monitor RATA.
(g) For each monitoring system, report the results of all
completed and partial RATAs that affect data validation (i.e., all
completed, passed RATAs; all completed, failed RATA; and all RATAs
aborted due to a problem with the CEMS) in the quarterly report
required under Sec. 75.64. Note that RATA attempts that are aborted
or invalidated due to problems with the reference method or due to
operational problems with the affected unit(s) need not be reported.
Such runs do not affect the validation status of emission data
recorded by the CEMS. In addition, aborted RATA attempts that are
part of the process of optimizing a monitoring system's performance
do not have to be reported, provided that, in the period extending
from the hour in which the test is aborted to the hour of
commencement of the next RATA attempt: (1) no corrective maintenance
or reprogramming of the monitoring system is done; and (2) only the
calibration adjustments allowed under section 2.1.3 of this appendix
are made. However, a record of all RATAs and RATA attempts (whether
reported or not) must be kept on-site as part of the official test
log for each monitoring system.
(h) Each time that a hands-off RATA of an SO2
pollutant concentration monitor, a NOX-diluent monitoring
system, or a flow monitor is successfully completed, perform a bias
test in accordance with section 7.6.4 of appendix A to this part.
Apply the appropriate bias adjustment factor to the reported
SO2, NOX, or flow rate data, in accordance
with section 7.6.5 of appendix A to this part.
(i) Failure of the bias test does not result in the monitoring
system being out-of-control.
2.3.3 RATA Grace Period
The owner or operator has a grace period of 720 consecutive unit
operating hours in which to complete the required RATA for a
particular CEMS, whenever: (a) a required RATA has not been
performed by the end of the QA operating quarter in which it is due;
(b) five consecutive calendar years have elapsed without a required
3-load flow RATA having been conducted; (c) an SO2 RATA
has not been completed by the end of the calendar quarter in which
the annual usage of fuel(s) with a total sulfur content greater than
the total sulfur content of natural gas exceeds 480 hours, for a
unit which is conditionally exempted under Sec. 75.21(a)(7) from the
SO2 RATA requirements of this part; or (d) eight
successive calendar quarters have elapsed, following the quarter in
which a RATA was last performed, without a subsequent RATA having
been done, due to: (1) infrequent operation of the unit(s); (2)
frequent combustion of fuel(s) with a total sulfur content no
greater than the total sulfur content of natural gas (i.e.,
0.05 percent sulfur by weight) (SO2 monitors,
only); or (3) a combination of factors (1) and (2).
Except for SO2 monitoring system RATAs, the grace
period shall begin with the first unit operating hour following the
calendar quarter in which the required RATA was due. For
SO2 monitor RATAs, the grace period shall begin with the
first unit operating hour in which fuel with a total sulfur content
greater than the total sulfur content of natural gas (i.e., >0.05
percent sulfur by weight) is burned in the unit(s), following the
quarter in which the required RATA is due. Data validation during a
RATA grace period shall be done in accordance with the applicable
provisions in section 2.3.2 of this appendix.
If, at the end of the 720 unit operating hour grace period, the
RATA has not been completed, data from the monitoring system shall
be invalid, beginning with the first unit operating hour following
the expiration of the grace period. Data from the CEMS remain
invalid until the hour of completion of a subsequent hands-off RATA.
Note that when a RATA (or RATAs, if more than one attempt is made)
is done during a grace period in order to satisfy a RATA requirement
from a previous quarter (i.e., for reasons (a), (b), or (d) in this
section), the deadline for the next RATA shall be determined from
the quarter in which the RATA was due, not from the quarter in which
the grace period is used.
2.3.4 Bias Adjustment Factor
Except as otherwise specified in section 7.6.5 of appendix A to
this part, if an SO2 pollutant concentration monitor,
flow monitor, or NOX continuous emission monitoring
system fails the bias test specified in section 7.6 of appendix A to
this part, use the bias adjustment factor given in Equations A-11
and A-12 of appendix A to this part to adjust the monitored data.
2.4 Recertification, Quality Assurance, and RATA Deadlines
When a significant change is made to a monitoring system such
that recertification of the monitoring system is required in
accordance with Sec. 75.20(b), a recertification test (or tests)
must be performed to ensure that the CEMS continues to generate
valid data. In many instances, a required recertification test is
the same type of test as one of the routine, periodic quality
assurance tests required by this appendix (e.g., a linearity test or
a RATA). When this occurs, the recertification test may be used to
satisfy the quality assurance test requirement of this appendix. For
example, if, for a particular change made to a CEMS, one of the
required recertification tests is a linearity check and the
linearity test is successful, then, unless another recertification
event occurs in that same QA operating quarter, it would not be
necessary to perform a subsequent linearity test of the CEMS in that
quarter. For this reason, EPA recommends that owners or operators
coordinate component replacements, system upgrades, and other events
that may require recertification, to the extent practicable, with
the periodic quality assurance testing required by this appendix.
When a quality assurance test is done for the dual purpose of
recertification and routine quality assurance, the applicable data
validation procedures in Sec. 75.20(b)(3) shall be followed in lieu
of the procedures in this appendix.
Except as provided in section 2.3.3 of this appendix, whenever a
successful RATA of a gas monitor or a successful 2-load or 3-load
RATA of a flow monitor is performed (irrespective of whether the
RATA is done to satisfy a recertification requirement or to meet the
quality assurance requirements of this appendix, or both), the
deadline for the next RATA shall be established based upon the date
and time of completion of the RATA and the relative accuracy
percentage obtained. For 2-load and 3-load flow RATAs, use the
highest percentage relative accuracy at any of the loads to
determine the deadline for the next RATA. The results of a single-
load flow RATA may be used to establish a RATA deadline when: (1)
the single-load flow RATA is specifically required under section
2.3.1.3(b) of this appendix (for flow monitors installed on peaking
units and bypass stacks); or (2) the single-load RATA is allowed for
a unit that has operated at the most frequently used load level for
85.0 percent of the time, under section 2.3.1.3(c) of
this appendix. No other single-load flow RATA may be used to
establish an annual RATA frequency; however, a 2-load flow RATA may
be performed in place of any required single-load RATA, in order to
establish an annual RATA frequency.
2.5 Other Audits
* * * * *
61. Figures 1 and 2 at the end of appendix B are revised to read as
follows:
[[Page 28174]]
Figure 1.--Quality Assurance Test Requirements
----------------------------------------------------------------------------------------------------------------
QA test frequency requirements
Test --------------------------------------------------
Daily* Quarterly* Semiannual*
----------------------------------------------------------------------------------------------------------------
Calibration Error (2 pt.)....................................
Interference (flow)..........................................
Flow-to-Load Ratio........................................... ...............
Leak Check (DP flow monitors)................................ ...............
Linearity (3 pt.)............................................ ...............
RATA (SO2, NOX, CO2, percent H2O) 1.......................... ...............
RATA (flow ) 1, 2............................................ ............... ...............
----------------------------------------------------------------------------------------------------------------
*For monitors on bypass stack/duct, ``daily'' means bypass operating days, only. ``Quarterly'' means once every
QA operating quarter. ``Semiannual'' means once every two QA operating quarters.
1 Conduct RATA annually (i.e., once every four QA operating quarters), if monitor meets accuracy requirements to
qualify for less frequent testing.
2 For flow monitors installed on peaking units and bypass stacks, conduct all RATAs at a single, normal load.
For other flow monitors, conduct RATAs at the two most frequently used loads. Alternating single-load and 2-
load RATAs may be done if a monitor is on a semiannual frequency. A single-load RATA may be done in lieu of a
2-load RATA if, in the past four QA operating quarters, the unit has operated at one load level for 85.0 percent of the time. A 3-load RATA is required at least once in every period of five consecutive
calendar years and whenever a flow monitor is re-linearized.
Figure 2.--Relative Accuracy Test Frequency Incentive System
----------------------------------------------------------------------------------------------------------------
RATA Semiannual1 (percent) Annual1
----------------------------------------------------------------------------------------------------------------
SO2.......................................... 7.5% < RA 10.0% or RA 7.5.% or 15.0 ppm 2. minus> 12.0 ppm 2
SO2/diluent.................................. 7.5% < RA 10.0% or RA 7.5% or 0.030 lb/mmBtu 2. minus> 0.025 lb/mmBtu 2
NOX/diluent.................................. 7.5% < RA 10.0% or RA 7.5% or 0.020 lb/mmBtu 2. minus>0.015 lb/mmBtu 2
Flow (Phase I)............................... 10.0% < RA 15.0% or RA 10.0%
1.5 fps 2.
Flow (Phase II).............................. 7.5% < RA 10.0% or RA 7.5%
1.5 fps 2.
CO2/O2....................................... 7.5% < RA 10.0% or RA 7.5% or 1.0% CO2/O22. minus> 0.7% CO2/O22
Moisture..................................... 7.5% < RA 10.0% or RA 7.5% or 1.0% H2O2. minus> 0.7% H2O2
----------------------------------------------------------------------------------------------------------------
1 The deadline for the next RATA is the end of the second (if semiannual) or fourth (if annual) successive QA
operating quarter following the quarter in which the CEMS was last tested. Exclude calendar quarters in which
the unit operates for < 168 hours (or, for common stacks and bypass stacks, exclude quarters in which gases
discharge through the stack for < 168 hours) in determining the RATA deadline. For SO2 monitors, QA operating
quarters in which only fuel with a total sulfur content no greater than the total sulfur content of natural
gas (i.e., 0.05 percent sulfur by weight) is combusted may also be excluded. However, the
exclusion of calendar quarters is limited as follows: the deadline for the next RATA shall be no more than 8
calendar quarters after the quarter in which a RATA was last performed.