# Acid Rain Program; Continuous Emission Monitoring Rule Revisions

> Briefs, arguments, decisions, and more.

URL: https://www.frixlaw.com/law-library/documents/fr%3A98-11749

## Record

- **Collection:** Federal Register
- **Document type:** Proposed Rule
- **Published:** May 21, 1998
- **Citation:** 63 FR 28032

## Text

SUMMARY: Title IV of the Clean Air Act (CAA or the Act), as amended by
the Clean Air Act Amendments of 1990, authorizes the Environmental
Protection Agency (EPA or Agency) to establish the Acid Rain Program.
The Acid Rain Program and the provisions in this 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
------------------------------------------------------------------------
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.
---------------------------------------------------------------------------

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 2 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

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Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A98-11749. Public record. Not legal advice.