[Federal Register Volume 63, Number 98 (Thursday, May 21, 1998)]
[Proposed Rules]
[Pages 28032-28195]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 98-11749]



[[Page 28031]]

_______________________________________________________________________

Part II





Environmental Protection Agency





_______________________________________________________________________



40 CFR Parts 72 and 75



Acid Rain Program; Continuous Emission Monitoring Rule Revisions; Acid 
Rain Program: Determinations Under EPA Study of Bias Test and Relative 
Accuracy and Availability Analysis; Proposed Rules

  Federal Register / Vol. 63, No. 98 / Thursday, May 21, 1998 / 
Proposed Rules  

[[Page 28032]]



ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 72 and 75

[FRL-6007-8]
RIN 2060-AG46


Acid Rain Program; Continuous Emission Monitoring Rule Revisions

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

-----------------------------------------------------------------------

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 < 90.0 percent or 
when the diluent missing data period exceeds 72 hours, Sec. 75.36 
specifies that the owner or operator must use the procedures in section 
5.5 of Appendix F to determine the hourly heat input.
    Utility representatives have asked EPA to consider revising the 
missing data procedures for CO2 and heat input (see, e.g., 
Docket A-97-35, Items II-D-20, II-D-30, II-E-13, and II-E-14). The 
utilities object to several elements of the current procedures. They 
suggest that the Appendix G procedures are burdensome and that the 
missing data procedures are considerably different from the standard 
missing data procedures for SO2, NOX, and flow 
rate, which are based solely on historical data and monitor 
availability and require no additional procedures such as fuel 
sampling.
Discussion of Proposed Changes
    EPA has reconsidered the provisions of Secs. 75.35 and 75.36 in 
light of the concerns raised by the regulated community, and is 
proposing revisions to the diluent gas missing data procedures for 
CO2 and for heat input determinations. The Agency proposes 
that the same missing data routines prescribed in Sec. 75.33(b) for 
SO2 pollutant concentration monitors also be applied to the 
CO2 and O2 data streams that are used to 
determine CO2 emissions and heat input. The diluent gas 
substitute data values would therefore be determined in a purely 
mathematical way, based on historical data and the percent monitor data 
availability; no fuel sampling procedures would be required.
    Note that these proposed revisions would require the percent 
monitor data availability to be known on an hourly basis. This would 
require the percent availability for CO2 and O2 
monitors to be updated hourly within the data acquisition system. EPA 
realizes that this would involve software modifications, and in cases 
where the unit heat input is determined using a flow monitor and an 
O2 diluent monitor in accordance with Equation F-17 or F-18, 
some new recordkeeping provisions would also be required. The necessary 
recordkeeping provisions have been proposed in Sec. 75.57(g). To allow 
time for software revisions to be made, the revised missing data 
procedures in Secs. 75.35 and 75.36 would not take effect until January 
1, 2000. The owner or operator could, however, opt to use the new 
procedures prior to January 1, 2000.
    EPA believes that today's proposed revisions to the missing data 
procedures for CO2 and heat input determinations would be 
relatively easy to implement because the missing data routines for 
SO2 monitors are well-established and are familiar to both 
the regulated community and to software vendors. The Agency believes 
that the proposed revised missing data procedures would ensure that 
data availability remains high and would, over time, reduce the cost of 
compliance with the requirements of part 75.
2. Prohibition Against Low Monitor Data Availability
Background
    Under the current rule, when a unit uses SO2, flow rate, 
and NOX monitoring systems to account for its emissions, for 
each clock hour in which a CEMS fails to provide quality assured data, 
a substitute data value must be reported to EPA in accordance with the 
standard missing data procedures of Sec. 75.33. The method required for 
determining the appropriate substitute data values under Sec. 75.33 
depends on several factors, such as the overall monitor data 
availability and the length of the missing data period. For monitor 
data availabilities  90.0 percent, the substitute data value 
(which is reported for each clock hour of the missing data period) will 
normally be the arithmetic average of the readings from the hour before 
and the hour after the missing data period. At other times, it will be 
the 90th (or 95th) percentile value from a lookback period of 720 (for 
SO2) or 2,160 (for NOX and flow rate) quality 
assured monitor operating hours. When the data availability drops below 
90.0 percent, the substitute data value for SO2 will be the 
maximum concentration recorded in the last 720 quality assured monitor 
operating hours, and for flow rate and NOX, the substitute 
data value will be the maximum flow rate or NOX emission 
rate recorded in the last 2,160 quality assured monitor operating hours 
at the corresponding load range.
    Based on four years of program implementation, EPA believes that 
the standard missing data procedures need to be strengthened. As 
presently written, the missing data algorithms lack a safeguard which 
will ensure that high monitor data availability continues to be 
maintained in future years. In the current version of Sec. 75.33, no 
distinction is made between data availabilities of 89.0 percent, 50.0 
percent or 10.0 percent. For all three of these data availability 
percentages, the substitute data value is the same (i.e., the maximum 
value in a lookback period of 720 or 2,160 quality-assured monitor 
operating hours). This has potentially serious consequences. For 
example, if the substitute data value from the lookback period is non-
punitive or perhaps is even favorable to the facility (e.g., if a low-
sulfur fuel was burned during the lookback period), there would be 
little incentive to repair a malfunctioning CEMS in a timely manner and 
emissions could possibly be under-reported for a long period of time. 
Currently, part 75 does not specifically address this ``gaming 
activity.''
Discussion of Proposed Changes
    In order to maintain the credibility of the SO2 
allowance accounting system and to ensure that affected units continue 
to comply with their part 76 NOX emission limits, monitor 
data availability must not be allowed to deteriorate indefinitely 
without clear and significant consequence to the facility. Therefore, 
in today's rulemaking, EPA is proposing to add a

[[Page 28048]]

safeguard to part 75 to ensure that this does not happen. A new 
paragraph 75.33(d) would be added, which would make it a violation of 
the primary measurement requirement of Sec. 75.10(a) to allow the 
annual monitor data availability to drop below 80.0 percent for 
SO2, NOX, flow rate, or CO2. Based on 
an analysis conducted on data availability information for the third 
quarter of 1996, EPA believes that affected facilities will easily be 
able to comply with the 80.0 percent data availability criterion (see 
analyses in Docket A-97-35, Item II-B-16). The results of that analysis 
indicated a mean percent monitor data availability of 96.9 percent for 
SO2, 95.0 percent for NOX, and 96.6 percent for 
flow rate. Although there were 13 (out of 995 total) SO2 
monitors, 21 (out of 997 total) flow monitors, and 46 (out of 1365 
total) NOX monitoring systems with percent monitor 
availabilities below 80.0 percent in the 4th quarter of 1996, the 
Agency expects that many of these systems would be exempt from the 
prohibition based on a limited number of operating hours in the 
previous year (see Docket A-97-35, Item II-A-8).
    The proposed prohibition would not apply to units that have only a 
limited number of operating hours (less than 3000 hours of operation in 
the previous 12 calendar quarters) because such units can have a low 
data availability percentage without necessarily having extended 
monitor downtime incidents. In addition, no violation would occur if 
the low monitor availability is caused by a sudden and reasonably 
unforeseeable event beyond the control of the owner or operator (such 
as destruction of monitoring equipment by fire or flood). The owner or 
operator would, however, be required to notify the Administrator, in 
writing, within 7 days of the occurrence of such catastrophic events 
and also to provide notification to the EPA Regional Office and to the 
appropriate State agency. The owner or operator would be further 
required to submit a corrective action plan, including an 
implementation schedule. Thus, this proposed prohibition should not 
result in violations of part 75, except for situations involving poor 
operation and maintenance practices, which are clearly not beyond the 
control of the owner or operator.
    Another option considered by the Agency was to modify the standard 
missing data algorithms for SO2, NOX, and flow 
rate as follows. Under this option, the algorithms for monitor data 
availabilities of 90.0 percent to 100.0 percent would remain unchanged. 
The algorithms currently used for all monitor data availabilities below 
90.0 percent would be retained, but these would apply only to data 
availabilities between 80.0 percent and 89.9 percent. Finally, a new 
algorithm would be added for monitor data availabilities below 80.0 
percent. When the data availability drops below 80.0 percent, the 
appropriate maximum substitute data value would have to be used (i.e., 
the maximum potential concentration for SO2 or 
CO2, the maximum NOX emission rate, or the 
maximum potential flow rate). EPA believes that requiring maximum 
values to be reported when the data availability drops below 80.0 
percent would provide incentive to the affected sources to keep their 
monitors well-maintained. Because any changes to the standard missing 
data algorithms would require software modifications, this option, if 
adopted, would not take effect until January 1, 2000. The Agency has 
not proposed this option because it would require software changes for 
all affected units even though very few units have data availabilities 
that fall below 80.0 percent. The Agency seeks comment, however, on 
whether this option should be used instead of the proposed prohibition 
given that it is more consistent with the structure of the missing data 
requirements in part 75 and would be self-implementing without any need 
to initiate enforcement actions to achieve the desired result of 
continued high data availabilities that assure accurate reporting of 
emissions.
    The Agency also emphasizes that the required data availability for 
the Acid Rain Program would remain at 100.0 percent even if the 
proposed prohibition is adopted, meaning that substitute data would 
have to be supplied for any periods in which data from a certified 
monitoring system are not available. This approach is in sharp contrast 
to most other CEMS programs that do not rely on substitute data. In 
those programs, the Agency, as well as State and local agencies, expect 
and often require much higher data availabilities than 80.0 percent. 
Based on the number of units with data availability higher than 95.0 
percent under the Acid Rain Program, CEMS data availability less than 
95.0 percent may well indicate a failure to properly operate and 
maintain a CEMS. Many agencies rely on that 95.0 percent availability 
level to target systems for inspection and other compliance-related 
follow-up actions. In addition, agencies have adopted various required 
minimum data availabilities for CEMS that far exceed the 80.0 percent 
level selected for the prohibition proposed in today's rulemaking.
    It is also important to note that monitor availability under part 
75 and monitor downtime under other programs are not always the same. 
Under part 75, a source may have actual monitoring data that are 
suspect, based on an evaluation of various quality assurance 
activities. In this situation, the owner or operator may, as a 
conservative measure, report substitute data rather than the actual 
data. In contrast, this type of missing data substitution does not 
occur under most other programs. In most programs, the suspect data 
would simply be invalidated and no emission data would be reported for 
those hours.
    Therefore, because of the structure of the missing data provisions 
in the Acid Rain Program and the generally applicable economic 
incentive to achieve high data availabilities under part 75, it would 
be improper to equate the proposed prohibition in today's rulemaking 
with a required minimum data availability requirement established for 
other programs that do not have the same features. The Agency does not 
intend that this proposed provision should serve as a precedent for 
evaluating the appropriate achievable data availability for other 
programs. Consistent with current practices, the Agency would continue 
to expect CEMS to achieve high data availability and that, generally, 
monitor downtime in excess of 5.0 percent may warrant appropriate 
investigation and follow-up activities.

G. General Authority to Grant Petitions Under Part 75

Background
    Section 75.66(a) provides generally that a designated 
representative of a unit subject to part 75 may submit a petition to 
the Administrator. Sections 75.66(b) through (h) address petitions to 
the Administrator on the specified topics of alternative flow 
monitoring methods, alternatives to standards incorporated by 
reference, alternative monitoring systems, parametric monitoring 
procedures, missing data for units with add-on emission controls, 
emission or heat input apportionments, and the partial recertification 
process. Each of these subsections set forth the items which must be 
included with a particular type of petition. In addition, Sec. 75.66(i) 
states that, for any other petition to the Administrator under part 75, 
the designated representative for an affected unit shall include 
sufficient information for the evaluation of such petition.

[[Page 28049]]

Discussion of Proposed Changes
    Today's proposal would revise Sec. 75.66(a) to state clearly that 
the designated representative of an affected unit may petition the 
Administrator for authorization to apply an alternative to any 
requirement under part 75 or incorporated by reference in part 75, 
regardless of whether another section of part 75 explicitly allows such 
a petition concerning the particular requirement. EPA views this change 
as a clarification to the general authority already provided by 
Secs. 75.66(a) and (i). The proposed rule would also be amended to 
include new paragraphs (i) through (l), which would set forth the 
specific requirements for other petitions that are explicitly allowed 
by other sections of the rule but which are not currently included in 
this section. In addition, the proposed rule, at Sec. 75.66(m), would 
also indicate the appropriate documentation to be submitted for 
petitions under subsection (a), except those under subsections (b) 
through (l), where the required documentation is already specified. The 
required documentation in subsection (m) would be: (1) Identification 
of the unit; (2) information explaining why the proposed alternative 
should be used instead of the existing part 75 provision; (3) 
descriptions and, if applicable, diagrams of the equipment and 
procedures to be used in the proposed alternative; and (4) information 
demonstrating that the proposed alternative is consistent with the 
purposes of the provision for which an alternative is requested and is 
consistent with the purposes of part 75 and of section 412 of the Act.
Rationale
    As presently codified, EPA is concerned that the rule does not 
state clearly what types of petitions may be submitted under 
Sec. 75.66. In particular, existing subsection (i) could be interpreted 
as referring only to petitions that are mentioned in other sections of 
part 75 and that are not specifically listed in Sec. 75.66(b) through 
(h). EPA has not interpreted Sec. 75.66(i) in this manner. In 
administering the Act, EPA has inherent discretion to grant de minimis 
exceptions from statutory or regulatory requirements, where EPA 
determines that holding the regulated entity to the applicable 
requirement would yield a gain of trivial or no benefit, provided 
Congress has not unambiguously demonstrated its intent to foreclose 
such exceptions. See, e.g., Public Citizen v. Young, 831 F.2d 1108, 113 
(D.C. Cir. 1987); Alabama Power Co. v. Costle, 636 F.2d 323, 360-61 
(D.C. Cir. 1979). Since the issuance of part 75 in 1993, EPA has 
accepted, and, in some cases exercised its discretion and granted, 
petitions under Sec. 75.66 that requested exceptions and that were not 
specifically referenced in Sec. 75.66(b) through (h) or elsewhere in 
part 75 (see Docket A-97-35, Item II-B-17). Such petitions have 
included, for example, a request to set a CO2 span lower 
than that required by part 75 in order to more accurately quality 
assure the CO2 monitor. Another petition requested an 
alternative to the requirement to perform an annual RATA on a unit that 
was scheduled to shutdown, prior to the deadline for performing the 
RATA, in order to install a scrubber, construct a new stack, and 
install and certify new CEMS. A petition was also submitted for 
permission to use a propane sampling frequency as specified in the 
State operating permit and to then calculate SO2 emissions 
by using the highest sulfur content recorded during the previous 365 
days and report these data in quarterly reports. These petitions were 
submitted for the purpose of requesting alternatives to various 
requirements of part 75, even though the ability to petition the Agency 
on these issues was not referenced explicitly in other sections of part 
75 or in Sec. 75.66(b) through (h). In most cases, the circumstances 
leading to the request for an alternative to a part 75 requirement were 
not anticipated during the drafting of part 75 regulations. In fact, 
today's proposal revises several part 75 requirements to allow for 
alternatives that were originally requested and approved through the 
petition process set forth in Sec. 75.66. The Agency continues to 
believe that the general provision allowing petitions for alternatives 
to part 75 requirements is necessary to enable EPA to address 
circumstances that were not foreseen during the development of such 
requirements. This is important since circumstances can sometimes vary 
significantly from boiler to boiler. While the response to comment 
document for the January 11, 1993 rule (see Docket A-91-69, Item V-C-1, 
Issue # M-8.8.2) might be read to bar petitions for exceptions from any 
provision of part 75, EPA maintains that such a reading would be 
inconsistent with the regulatory language of Secs. 75.66(a) and (i) 
that allow such petitions, and with the established practice of the 
Agency in administering part 75.
    The existing Sec. 75.66(i) states that for petitions other than 
Sec. 75.66(b) through (h) petitions submitted under the section, the 
designated representative should include sufficient information for the 
evaluation of the petition. No other information is provided concerning 
the contents of such petitions. As Secs. 75.66(b) through (h) all 
provide a list of the type of information that should be included in 
petitions submitted under the respective sections, the Agency believes 
that, in addition to amending Sec. 75.66(a) to clarify that petitions 
may be submitted for circumstances that may not be covered by other 
sections authorizing petitions to the Administrator, it is appropriate 
to provide units with a list of the type of information that should be 
included with the petition. Similarly, EPA believes that it is 
appropriate to add to the section provisions setting forth the 
information requirements for those petitions that are explicitly 
allowed under other sections of part 75 but that are not listed in the 
existing Sec. 75.66. All these revisions would make the petition 
process more uniform and minimize confusion regarding what information 
EPA would require in order to accept and consider any petition for an 
alternative to a part 75 requirement.

H. NOX Mass Monitoring Provisions for Adoption by 
NOX Mass Reduction Programs

Background
    Part 75 contains requirements for monitoring NOX 
emissions with a continuous emission monitoring system or other 
approved method. Owners and operators are required to calculate hourly, 
quarterly average, and annual average NOX emission rates (in 
lb/mmBtu). Part 75, however, currently contains no requirements for 
reporting NOX mass emissions (in tons). Other NOX 
emission reduction programs being developed pursuant to title I of the 
Act (such as the NOX Budget Program in the Ozone Transport 
Region) are expected to require reporting of NOX mass 
emissions from many of the units affected under the Acid Rain Program. 
To streamline reporting burdens under multiple programs and to allow 
for the administration of multi-state NOX mass trading 
programs, the Agency believes it appropriate to amend part 75 to 
include provisions for monitoring, recording, and reporting 
NOX mass emissions that could apply to such trading 
programs. These provisions would provide standard procedures--resulting 
in precise, reliable, accessible, and timely emissions data--that could 
be adopted under a state or federal NOX mass emission 
reduction program. To the extent that these standard provisions are 
adopted, the burden on industry would be reduced and the administration 
of the programs would be facilitated, in

[[Page 28050]]

that the Agency or implementing states would not need to develop 
NOX mass monitoring provisions anew and industry would not 
need to become familiar with multiple approaches to NOX mass 
monitoring.
Discussion of Proposed Changes
    The proposed NOX mass emissions provisions would apply 
only where EPA, states, or groups of states incorporate them and 
mandate their use through a separate regulatory action. The proposed 
amendments would make changes to Secs. 75.1, 75.2, 75.4, 75.16, 75.17, 
Appendix D, section 2.1.2.2, and Appendix F, section 5.5. They would 
also add a new subpart H containing new Secs. 75.70, through 75.73 and 
a new section 8 in Appendix F containing sections 8.1, 8.1.1, 8.1.2, 
8.1.3, 8.1.4, 8.2, 8.3, 8.3.1, and 8.3.2.
    Section 75.1, the purpose and scope section, would be amended to 
broaden the scope by adding that part 75 will also set forth provisions 
for monitoring and reporting NOX mass emissions that EPA, 
states, or groups of states may require sources to use to demonstrate 
compliance with a NOX mass emission reduction program. 
Section 75.2 would be amended to add that the provisions of part 75 may 
also apply to sources subject to a state or federal NOX mass 
emission reduction program.
    The compliance date section, Sec. 75.4(a), would be altered to 
state that the provisions relating to monitoring and reporting of 
NOX mass emissions become applicable on the deadlines 
specified in the applicable state or federal NOX mass 
emission reduction program requiring the use of part 75 to monitor and 
report NOX mass emissions.
    Section 75.16 would be amended to state that title IV affected 
units using the provisions of part 75 to monitor and report 
NOX mass emissions under a state or federal NOX 
mass emission reduction program would have to meet the heat input 
monitoring and determination requirements in both Sec. 75.16 and in 
subpart H, Secs. 75.71 and 75.72. Section 75.17 would be amended to 
state that title IV affected units using the provisions of part 75 to 
monitor and report NOX mass emissions under such a program 
would have to meet the NOX emission monitoring and 
determination requirements in both Sec. 75.17 and subpart H, 
Secs. 75.71 and 75.72.
    The applicable procedures for the monitoring and determination of 
NOX mass emissions would be added in proposed subpart H, 
Secs. 75.70, 75.71, and 75.72 and corresponding recordkeeping and 
reporting requirements would be set forth in Sec. 75.73.
    Section 75.70 would set forth the general requirements including: 
definitions, compliance dates, incorporation by reference, initial 
certification and recertification procedures, quality assurance and 
quality control requirements, substitute data requirements, and 
requirements regarding petitions. In general these provisions for 
monitoring NOX mass would mirror the provisions for 
monitoring of SO2, NOX, and CO2 for 
compliance with title IV. However, because the program would be a state 
program, rather than a federal program, there would be some differences 
in the administrative requirements. These differences would be most 
pronounced for units that were not subject to Acid Rain emission 
limitations and were not already subject to the provisions of part 75. 
The major differences in administrative requirements would involve the 
process for petitioning under Sec. 75.66 and the process for certifying 
and recertifying monitors. Under the existing Acid Rain Program, the 
Administrator must approve all petitions under Sec. 75.66. Under this 
proposal, petitions for units that were only subject to the provisions 
of part 75 because they were subject to a state or federal 
NOX mass emission reduction program, would have to be 
approved by both the permitting authority for the applicable 
NOX mass program and the Administrator. The permitting 
authority would also be responsible for reviewing and approving or 
disapproving certification and recertification applications for such 
units.
    Section 75.71 sets forth the general monitoring methodologies that 
would be allowed for different types of units. The proposal would 
require units to determine hourly NOX mass emissions (in lb) 
by monitoring NOX emission rate (in lbs/mmBtu) and heat 
input (in mmBtu/hr) on an hourly basis and by multiplying those two 
values and the hourly unit operating time (in hour or fraction of an 
hour) together. Coal units and other units that burn solid fuel and 
that are covered by subpart H would be required to measure 
NOX emission rate using a NOX emission rate CEM 
consisting of a NOX concentration CEM and a diluent CEM 
(CO2 or O2 CEM) and to measure heat input using a 
diluent CEM and a continuous volumetric flow monitor. All gas- and oil-
fired units covered by subpart H would be allowed to use that approach 
or, alternatively, could measure NOX emission rate using a 
NOX emission rate CEM and heat input by using a fuel 
flowmeter and performing fuel sampling and analysis. This alternative 
for determining heat input from gas- and oil-fired units is set forth 
in Appendix D of part 75. Gas and oil units that qualify as either 
peaking units or low mass emission units under part 75 would also have 
additional lower cost monitoring methodologies available to them. 
Peaking units, for example, would have the option to do source testing 
to create heat input versus NOX emission rate correlation 
curves. Then, based on hourly measurement of heat input from a fuel 
flowmeter and fuel sampling and analysis using the provisions in 
Appendix D to part 75, the heat input vs NOX emission rate 
correlation curves would be used to estimate the hourly NOX 
emission rate. This rate would be used in conjunction with hourly 
measured heat input to determine NOX mass. A unit that 
qualifies as a low mass emission unit would have the option to use a 
fuel-type and boiler-type specific default NOX emission rate 
and the unit's maximum rated hourly heat input to determine 
NOX mass emissions. The low mass emissions unit provisions 
are in proposed Sec. 75.19.
    Section 75.72 sets forth the specific requirements for monitoring 
emissions at units that share common stacks and/or common pipes, for 
units that emit to multiple stacks and for units that receive fuel from 
multiple pipes. These provisions mirror similar provisions in 
Sec. 75.16 for monitoring SO2 mass emissions from similar 
units and groups of units.
    Appendix D, section 2.1.2.2 would indicate that the heat input 
apportionment procedures of that section would not be applicable for 
units whose compliance with this part is required under a 
NOX mass emissions reduction program. Instead, the unit 
would have to meet the heat input monitoring and determination 
requirements in subpart H, Secs. 75.71 and 75.72.
    The applicable procedures for calculating NOX mass 
emissions would be added in proposed section 8 of Appendix F. Section 
8.1 of Appendix F contains proposed equations for determining hourly 
NOX mass emissions, section 8.2 contains proposed equations 
for determining quarterly, cumulative annual and ozone season 
NOX mass emissions, and section 8.3 contains specific 
provisions for monitoring NOX emissions from a common stack. 
Additionally, revisions to section 5.5 of Appendix F would indicate 
that the heat input calculation procedures of section 5.5.3 would not 
be applicable for units whose compliance with this part is required 
under a NOX mass emissions reduction program.

[[Page 28051]]

Rationale
    (a) Authority to Propose NOX Mass Provisions. The 
authority for the proposed NOX mass provisions rests in two 
separate portions of the Act. First, section 412(a) states that the 
owner or operator of an affected source under title IV must monitor and 
quality assure data for sulfur dioxide and nitrogen oxide for each 
affected unit at the source. 42 U.S.C. 7651k(a). This section does not 
limit the nitrogen oxide data requirement to emission rate data in lb/
mmBtu or to data necessary for compliance with emission limits 
established under title IV. Indeed, oil-and gas-fired units have been 
required to report NOX emission rate data under part 75 even 
though only existing coal units are subject to NOX emission 
limits under title IV. (See 58 FR 3590, 3644, January 11, 1993). Thus, 
the Agency believes that providing for reporting NOX mass 
emissions under part 75 is an appropriate exercise of the authority 
under section 412, particularly since NOX mass emissions 
reporting may be required under a separate applicable requirement.
    Second, independently of the authority granted by section 412, 
section 114(a) of the Act gives the Administrator broad authority to 
collect data for ``the purpose of developing or assisting in the 
development of any implementation plan under section 110 or 111(d)'', 
``of determining whether any person is in violation of any such 
standard or a requirement of such a plan'', or ``carrying out any other 
provision of [the] Act'' (except certain provisions of title II 
concerning mobile sources). Section 114 is, of course, not limited to 
sources that are affected units under title IV. Moreover, section 
301(a)(1) authorizes the Administrator ``to prescribe such regulations 
as are necessary to carry out his functions'' under the Act, including 
the functions specified in section 114. Thus, EPA maintains that the 
Agency is authorized to adopt provisions in part 75 that could govern 
monitoring of NOX mass emissions, especially where such 
information is expected to support States' efforts to attain ambient 
air quality standards.
    From a policy perspective, now is the appropriate and most 
efficient time to adopt these changes. In July 1997, EPA Administrator 
Carol Browner announced a series of initiatives to reform environmental 
data management and collection (see Docket A-97-35, Item II-I-21). The 
new initiatives are intended to streamline reporting requirements and 
increase coordination across different programs that affect the same 
sources. There are a number of examples of ongoing efforts to 
streamline the reporting of emissions for utility units. One example is 
a proposal to revise the NSPS NOX standards for utility and 
industrial boilers subject to reporting under 40 CFR part 60. That 
proposal would allow facilities to submit NSPS reports through part 75 
reporting (see 62 FR 36948, July 9, 1997). Another example is the Ozone 
Transport Commission's NOX Budget program. That program is 
expected to require utility sources and certain industrial sources in 
the northeast to reduce emissions of NOX through a trading 
program similar to the Acid Rain SO2 trading program. On 
January 31, 1996, the OTC released the Model Rule which outlines 
procedures for the monitoring and reporting of NOX mass 
emissions; these procedures are based on the monitoring and reporting 
requirements set forth in part 75 (see Docket A-97-35, Items II-I-7 and 
II-I-22). Today's proposal would facilitate the coordination of 
reporting under the Acid Rain Program and NOX mass programs 
like the OTC NOX Budget Program.
    In addition, the Agency believes it is appropriate to include these 
requirements in the current proposal because the Acid Rain affected 
units may be undertaking DAHS software changes to respond to the other 
proposed revisions to part 75 if they are adopted. The Agency would 
enable facilities to coordinate the necessary software changes by 
proposing the revised reporting requirements to allow for 
NOX mass emission reporting at this time along with the 
other part 75 revisions. Although EPA is proposing this requirement now 
to facilitate software changes, the requirement to actually record and 
report NOX mass emission data under part 75 generally would 
not become effective for any unit unless and until a program requiring 
such recording and reporting is implemented for that particular unit 
(EPA notes that, as discussed elsewhere in Section III.C.4. of this 
preamble, a limited group of title IV affected units (i.e., low mass 
emissions units) would be required to record and report NOX 
mass emissions for purposes of the Acid Rain Program.) In addition, if 
a state elected to require the use of these requirements to support a 
state NOX mass emission monitoring and reporting 
requirement, these requirements would not become federally enforceable 
until those requirements were approved by EPA as part of the SIP.
    (b) Monitoring Methodology. The proposed requirement would require 
sources to determine NOX mass as a function of hourly 
average NOX emission rates, heat input rates, and unit 
operating time. EPA is proposing this approach because it accurately 
accounts for NOX mass emissions without requiring any 
changes to the current missing data routines and quality assurance 
requirements in part 75. An alternative to this approach, not included 
in today's proposal, would be to measure total mass emissions using a 
NOX pollutant concentration monitor, a volumetric flow 
monitor and unit operating time, analogous to the approach taken 
currently for SO2 emissions. This methodology would have two 
advantages: first, there would be less missing data from a 
NOX pollutant concentration monitor than from a 
NOX CEMS which (under the existing and proposed rule) 
contains both a NOX pollutant concentration monitor and a 
diluent monitor; and second, it would avoid possible overestimation 
from a bias adjustment factor applied to the NOX system to 
correct bias in the diluent monitor (see Docket A-97-35, Item II-D-96).
    However, this methodology would also have a number of 
disadvantages. In order to monitor NOX as total mass 
emissions using a NOX pollutant concentration monitor and a 
volumetric flow monitor, several major changes would need to be made to 
part 75. The entire concept of a NOX CEMS--and the quality 
assurance tests and missing data procedures associated with the 
NOX CEMS--might need to be revised, to include either a 
NOX CEMS with only a NOX pollutant concentration 
monitor and a DAHS (in which case, a separate flow monitoring system 
would also be required in order to determine NOX mass), or a 
NOX CEMS with a NOX pollutant concentration 
monitor, a volumetric flow monitor, and a DAHS. Since the relative 
accuracy standard currently in part 75 for NOX systems is in 
lb/mmBtu, it would be necessary to establish a new relative accuracy 
standard for NOX concentration in ppm if the NOX/
flow method described above were incorporated into the final rule. Bias 
adjustment would also have to occur on the newly defined NOX 
CEMS. It would also be necessary to create a missing data procedure 
either for NOX concentration in ppm or for hourly 
NOX mass emission rate in lb/hr. Hourly NOX mass 
emission rate would be calculated using the same formula as for 
SO2 mass emission rate (Equation F-1 or F-2), only using a 
constant of 1.194 x 10-7(lb/scf)/ppm NOX. In 
addition, this methodology would not easily support the monitoring and 
reporting of NOX emission rate data in lb/mmBtu.

[[Page 28052]]

Therefore, in order to meet the emission rate reporting requirements, 
affected sources under title IV would still be required to maintain a 
diluent CEMS and the current NOX emission rate missing data 
procedures. The Agency has not proposed this approach because it does 
not believe that the benefits of slightly reduced amounts of missing 
data for NOX mass and removal of the bias adjustment factor 
for the diluent monitor justify the complication of having two separate 
procedures for monitoring NOX emissions from a given unit. 
Nevertheless, the Agency requests comment on whether this approach to 
measuring mass emissions should be used in lieu of the proposed heat 
input and emission rate approach for sources required to report 
NOX mass.
    (c) Common Stack and Pipe Monitoring. The Agency notes that the 
proposed procedures for monitoring NOX emission rate at a 
common stack to determine NOX mass emissions under the 
proposed Sec. 75.72 procedures are different than the procedures 
currently allowed for monitoring NOX emission rate in 
Sec. 75.17. The Agency is concerned that the Sec. 75.17 provisions 
would be too imprecise for measuring NOX mass emissions 
because the two values used to determine NOX mass emissions 
(NOX emission rate and heat input) are not required to be 
measured at the same location. In the existing rule, NOX 
emission rate may be monitored at the unit level in the duct leading to 
the common stack and heat input can be determined from measurements at 
the common stack and then apportioned to the individual units using 
unit load. While this heat input apportionment method has been allowed 
for Acid Rain purposes, it is not accurate in all cases because it does 
not account for different heat rates from the units exhausting to the 
common stack and does not account for differences in operating time at 
the units. It has been allowed by the Agency for Acid Rain purposes 
because apportioned heat input determined under Sec. 75.16 (e) had only 
a limited effect on emissions trading (i.e., on the SO2 
allowance program). Although apportioned heat input determined under 
Sec. 75.16(e) is used to determine compliance with the reduced 
utilization provisions of the Acid Rain Program, the apportioned heat 
input estimate was deemed accurate enough for that purpose and for the 
relatively small number of units and short period involved. 
Determinations of reduced utilization are required only for Phase I 
units during 1995-1999 and for opt-in units. However, for purposes of a 
NOX mass trading program, the heat input value would be used 
in the calculation to determine NOX mass, and an imprecise 
unit level heat input value could cause the NOX mass 
emissions from some units to be underestimated. The NOX mass 
trading program could be undermined by the lack of a consistent 
emissions value for each NOX allowance. Therefore, the 
proposed provisions for monitoring heat input and NOX 
emission rate from units in a NOX mass trading program would 
be similar to the provisions that are currently used for monitoring 
SO2 mass emissions at a common stack at Sec. 75.16. The 
provisions for monitoring SO2 mass emissions require that 
the two values needed to determine SO2 mass emissions, stack 
flow rate and SO2 concentration, be monitored at the same 
location. The Agency is proposing that, for purposes of determining 
NOX mass emissions, a facility could use the same location 
options currently available for SO2: the facility could 
either monitor both NOX emission rate and heat input at the 
common stack level or monitor them both at the unit level. The Agency 
is also proposing a third option: heat input could be monitored at the 
unit level and summed to the common stack level, while NOX 
emission rate could be monitored at the common stack level. Even though 
this option would allow NOX emission rate and heat input to 
be measured at different locations, it does not have the inherent 
inaccuracies described above because it does not require heat input 
apportionment.
    Similarly, the optional procedures currently allowed for the 
apportionment of heat input measured at a common pipe in Appendix D, 
section 2.1.2.2 are not available for units with a common pipe under 
subpart H. As discussed above for common stacks, the Agency is 
concerned that the heat input apportionment under Appendix D, section 
2.1.2.2 provisions would be too imprecise for the purpose of 
calculating NOX mass emissions. In the existing rule, heat 
input can be determined from measurements at the common pipe and then 
apportioned to the individual units using unit load. For purposes of 
calculating NOX mass emissions under subpart H for a unit 
which is supplied fuel from a common pipe, the measurement of fuel flow 
rate would have to be made at the pipe leading to the individual unit 
in order to determine unit level heat input.
    The Agency solicits comment on the proposed approach for monitoring 
NOX mass emissions at a common stack or pipe and whether it 
is appropriate to mirror the common stack and pipe provisions for 
SO2 mass emissions.
    (d) Multiple duct/stack monitoring. The current provisions for 
monitoring NOX emission rate, in Secs. 75.17(c)(1) and (2), 
allow the owner or operator to determine NOX emission rate 
for a unit that exhausts through multiple ducts or stacks using a Btu-
weighted sum of the NOX emission rates measured in each duct 
or stack or by monitoring NOX emission rate in only one duct 
or stack. The new proposed Sec. 75.72 would set forth specific 
requirements for monitoring NOX mass in multiple ducts or 
stacks and would in some cases place a number of limits on the options 
in Sec. 75.17(c) and in some cases not allow the options in 
Sec. 75.17(c). The proposed options for monitoring NOX mass 
are similar to the existing provision in Sec. 75.16(d) for monitoring 
SO2 mass emissions at multiple ducts/stacks. They are also 
similar to the provisions being used in the OTC NOX Budget 
Program to determine NOX mass in similar situations.
    The new proposed Sec. 75.72 does not contain an option for any 
units to use a Btu-weighted sum of the NOX emission rates 
measured in each duct or stack. The reason that this option is not 
appropriate is that in order to use this option to determine a unit's 
NOX emission rate, the owner or operator of the unit would 
have to monitor both NOX emission rate and heat input in 
each duct or stack. (As discussed above, the heat input apportionment 
method allowed under Sec. 75.17 is not sufficiently accurate for a 
NOX mass program.) These two values allow the calculation of 
NOX mass and, therefore, there is no reason to determine a 
Btu-weighted sum for purposes of this subpart.
    The new proposed Sec. 75.72 would not allow coal units to monitor 
NOX emission rate in only one duct or stack. The proposal 
would also not allow gas and oil units to monitor the NOX 
emission rate in only one duct or stack, unless heat input is 
determined using the provisions of Appendix D to this part and the 
owner or operator makes a demonstration that the emission rate would 
always be the same in both ducts or stacks. Reasons that the emission 
rate might vary include the use of add-on emission controls in the 
ducts or stacks or venting of emissions to one duct or stack and not 
the other.
    These limitations are required for monitoring mass emissions (in 
lbs), but are not necessary for monitoring emission rate (in lbs/mmBtu) 
at coal units or gas and oil units that use continuous volumetric flow 
monitors, because, for reasons discussed above, monitoring mass 
requires the monitoring of both emission rate and heat input. Since the 
amount of stack

[[Page 28053]]

flow that is vented to each duct or stack could vary significantly 
depending upon the location and use of dampers and induction fans in 
the ducts or stacks, it is necessary to measure volumetric flow in both 
ducts or stacks in order to determine heat input for the unit(s). In 
order to accurately use these heat input values to determine 
NOX mass, it is also necessary to measure NOX 
emission rate in both ducts or stacks. Therefore, proposed Sec. 75.72 
would require monitoring of heat input and NOX emission rate 
in both ducts or stacks for coal units and gas-and oil-fired units that 
use continuous volumetric flow monitors and exhaust to multiple ducts 
or stacks.
    Since gas-and oil-fired units that are using the procedures in 
appendix D of part 75 to determine heat input based on fuel consumption 
do not have to measure volumetric flow in the duct or stack in order to 
determine heat input, EPA believes it is appropriate to allow these 
units to measure NOX emission rate in only one duct or stack 
if they can demonstrate to both the permitting authority and the 
Administrator that the NOX emission rate in either duct or 
stack is representative of the NOX emission rate in each 
duct or stack. Therefore, proposed Sec. 75.72 allows gas-and oil-fired 
units that are using the procedures in appendix D of part 75 to measure 
NOX emission rate in only one duct or stack if they can 
demonstrate to both the permitting authority and the Administrator that 
the NOX emission rate in either duct or stack is 
representative of the NOX emission rate in each duct or 
stack.
    (e) Reporting of NOX Mass Emissions. The Agency also 
notes that the proposed procedures differ in two key respects from the 
way data is currently reported under part 75. The first difference is 
that the proposal would require reporting of hourly NOX mass 
emissions, in lbs, (instead of hourly mass emission rate, in lb/hr, as 
is currently required for the reporting of SO2 under part 
75). The OTC NOX Budget Program is expected to require the 
reporting of hourly mass emissions, in lb, rather than hourly mass 
emission rates, in lb/hr, because of experience under the Acid Rain 
Program with reporting hourly SO2 and CO2 mass 
emission rates. As discussed in Section III.R.1 of this preamble, the 
reporting of hourly SO2 and CO2 mass emission 
rates has been a source of some confusion in the implementation of the 
Acid Rain Program. For the reasons presented in Section III.R.1 of this 
preamble, EPA is not proposing to change the existing SO2 
and CO2 reporting requirements. However, the existing part 
75 does not require any NOX mass emission reporting, and in 
order to avoid the problems experienced under the Acid Rain Program and 
to be consistent with the OTC NOX Budget Program, EPA 
proposes here to base the new NOX reporting on mass 
emissions in pounds. Maintaining consistency with the provisions 
expected to be adopted for the OTC NOX Budget Program is 
important to ensure that a central body such as EPA would be able to 
effectively administer the program if states opted to participate in a 
multi-state NOX trading program larger than the Ozone 
Transport Region covered by the OTC NOX Budget Program.
    The second key difference is that, in addition to reporting a 
quarterly and cumulative annual total emissions value, the proposed 
revisions would also require reporting of a cumulative ozone season 
total value. Generally, the ozone season extends from May 1 to 
September 30 of every year. The cumulative ozone season emissions would 
be reported with the second quarter and third quarter reports submitted 
to EPA. The reason that reporting would be required on an ozone season 
basis is that one of the main reasons the data is being collected is to 
support other programs designed to control emissions during the ozone 
season.
    (f) Role of EPA and States/Localities in Administering the 
Monitoring Portion of a NOX Trading Program. The Agency also 
notes that another important potential difference between the use of 
this part to support the Acid Rain Program under Title IV of the CAA 
and the use of this part to support other NOX mass emission 
reduction programs is the role that EPA and the state or local 
permitting authority that may establish such a program will play. Under 
the Acid Rain Program, even though many states have assumed the role of 
the permitting authority under Phase II of the program, EPA still 
retains authority to issue approvals and disapprovals related to all of 
the monitoring and reporting issues, such as certification of 
monitoring systems under Sec. 75.20, approval of petitions under 
Sec. 75.66 and approvals of alternate monitoring petitions under 
Sec. 75.48. EPA believes that if a NOX mass emission 
reduction program is approved as part of a SIP or if EPA agrees to work 
with individual or groups of states to help administer the monitoring 
and reporting portion of a NOX mass emission reduction 
program, EPA would still have to be involved in the approval process.
    The level of this involvement might vary depending upon the 
specific type of approval or disapproval. It also would vary depending 
upon whether or not the unit had an Acid Rain emission limitation. For 
instance, EPA would play a significant role in the approval of an 
alternate monitoring petition under Sec. 75.48 or any other petitions 
under Sec. 75.66. For a unit with an Acid Rain emission limitation, any 
petition would already have to be approved by EPA. In order to 
streamline the process for these sources, EPA believes that EPA should 
continue to issue approvals and disapprovals of petitions. However, 
since sources would also be using the monitored data to meet SIP 
requirements, EPA would take this action in consultation with the 
applicable state. For units that are not subject to an Acid Rain 
emission limitation, EPA would still need to be involved in petition 
determinations. There are two primary reasons that this involvement 
would be necessary. The first would be as part of EPA's typical role in 
assuring that any alternative to the approved SIP will still result in 
the air quality benefit that would have been derived if the permitting 
authority had not deviated from the SIP. The second would be as part of 
EPA's role in administering the emissions tracking portion of a 
NOX mass emission reduction program. If EPA was not involved 
and a state approved, for a unit, an alternative that allowed 
variations to the reporting requirements, EPA might not be able to 
administer the emissions tracking portion of the program for that unit. 
Similarly, for approval and disapproval of certification applications 
and recertification applications, EPA believes that there should be two 
separate requirements; one for units subject to an Acid Rain emission 
limitation, and one for units not subject to an Acid Rain emission 
limitation. For units subject to an Acid Rain emission limitation, EPA 
would still approve or disapprove certification and recertification 
applications. This would streamline the process for units since they 
would only have to deal with one regulatory agency for both programs. 
For units not subject to an Acid Rain emission limitation, the 
permitting authority would approve certification and recertification 
applications. EPA requests comment on this approach and whether the 
respective roles of the Administrator and the permitting authority 
should be different for units that are subject to both an Acid Rain 
emission limitation and to a NOX mass emission reduction 
program and for units that are subject solely to a NOX mass 
emission reduction program.

[[Page 28054]]

I. Span and Range Requirements

Background
    The span and range requirements for part 75 continuous emission 
monitoring systems are found under section 2.1 of Appendix A to the 
January 11, 1993, rule, as amended on May 17, 1995. Sections 2.1.1, 
2.1.2, 2.1.3 and 2.1.4 of Appendix A give the specific span and range 
requirements for SO2 monitors, NOX monitors, 
diluent (O2 and CO2) monitors, and flow rate 
monitors, respectively.
    The span of a CEMS provides an estimate of the highest expected 
value for the parameter being measured by the CEMS. For instance, the 
span value of an SO2 monitor should be an approximation, 
based on the type of fuel being combusted, of the highest 
SO2 concentration likely to be recorded by the CEMS during 
operation of the affected unit. The range of a CEMS is the full-scale 
setting of the instrument. Under part 75, the range of a monitor must 
be equal to or greater than the span value. Section 2.1 of Appendix A 
further specifies that the range must be chosen such that the majority 
of the readings during normal operation fall between 25.0 and 75.0 
percent of full-scale. Part 75 span values are used to determine the 
appropriate reference gas concentrations and reference signals for 
daily calibration of the CEMS; the reference concentrations and signal 
values are expressed as percentages of the span value. The allowable 
daily calibration error for a CEMS is also expressed as a percentage of 
span.
    Sections 2.1.1 through 2.1.4 of Appendix A to the January 11, 1993 
rule specified procedures for determining the span values for four 
parameters: SO2, NOX, diluent gas (O2 
or CO2), and volumetric flow rate. For SO2, the 
``maximum potential concentration'' (MPC) was first calculated based on 
fuel sampling results from the previous 12 months (using the highest 
sulfur content and lowest heating value in Equation A-1a or A-1b). The 
SO2 span value was then obtained by multiplying the MPC by 
1.25 and rounding the result upward to the next highest multiple of 
100.0 ppm. The MPC values for NOX were specified in the rule 
and were based on the type of fuel being combusted (e.g., 800.0 ppm for 
coal-firing and 400.0 ppm for oil-firing). The NOX span 
value was then determined by multiplying the MPC by 1.25 (e.g., 1000.0 
ppm for coal-firing and 500.0 ppm for oil-firing). For CO2 
and O2, a span value of 20.0 percent CO2 or 
O2 was required for all diluent monitors. For flow rate, the 
``maximum potential velocity'' (MPV) was first determined either using 
Equation A-3a (or A-3b) or from historical test data (i.e., from 
velocity traverses conducted at or near maximum load). Then, the span 
value was obtained by multiplying the MPV by 1.25 and rounding the 
result upward to the next highest multiple of 100 feet per minute 
(fpm).
    In the January 11, 1993 rule, the SO2 or NOX 
monitor range derived from the MPC was referred to as the ``high-
scale.'' The rule further specified that whenever the majority of the 
readings during normal operation were expected to be less than 25.0 
percent of the high full-scale range value (e.g., if a scrubber were 
used to reduce SO2 emissions), a second, ``low-scale'' span 
and range would be required. The low scale of the CEMS would be defined 
as 1.25 times the ``maximum expected concentration'' (MEC). The 
original rule was prescriptive regarding the method of determining the 
MEC. For SO2, the MEC was to be calculated using Equation A-
2; for NOX, an MEC value of 320.0 ppm was to be used for 
coal-firing and 160.0 ppm for oil-or gas-firing.
    In the first two years of Acid Rain Program implementation, it 
became increasingly clear to both the regulated community and to EPA 
that the span and range provisions of part 75 lacked sufficient 
flexibility and clarity. The NOX provisions were 
particularly problematic, being overly prescriptive in some instances 
and sometimes requiring two spans and ranges when a single, 
appropriately-sized range would suffice. Also, the units of the flow 
rate span were expressed in terms of velocity (i.e., feet per minute), 
and this was not consistent with either the units of measure used for 
daily monitor calibrations or the units used for electronic reporting 
of flow rate data.
    The May 17, 1995 rule attempted to address these deficiencies, as 
follows. For SO2, an alternative means of determining the 
MPC, in lieu of using historical fuel sampling data, was added; the MPC 
could be based upon 30 days of historical CEMS data. The use of 
historical CEMS data was also allowed as an option for MEC 
determinations, instead of using Equation A-2. For NOX, the 
method of determining the MPC was made less prescriptive. First, a 
comprehensive list of MPC values was promulgated (Tables 2-1 and 2-2 in 
Appendix A), taking into consideration the unit type in addition to the 
fuel type. The MPC value from this list could be used in lieu of the 
fuel-based MPC prescribed in the original rule. Second, two alternative 
methods of determining the MPC or MEC were added, i.e., from historical 
CEMS data or from emission test results. Finally, flexibility was added 
to the dual-range requirements for NOX monitors so that, in 
many instances, the span and range requirements of part 75 could be met 
on a site-specific basis, using a single span and range.
    The span provisions for CO2 and O2 were not 
significantly changed in the May 17, 1995 rule. For flow rate, however, 
a more detailed procedure for determining the span value was added. 
This addition was considered necessary because during the first year of 
program implementation it came to light that there are actually two 
important span values associated with flow rate: (a) the 
``calibration'' span value used for daily calibrations, and (b) the 
``flow rate'' span value in units of standard cubic feet per hour 
(scfh). These two span values are both derived from the MPV, but are 
almost invariably expressed in different units of measure, and, 
therefore, the two spans are generally not equal numerically. For 
instance, the calibration span value for the daily calibration of a 
differential pressure-type flow monitor, expressed in units of inches 
of water, is a small number (generally less than 5.0 in. 
H2O); while the flow rate span value, in scfh, is a very 
large number, usually in the tens or hundreds of millions.
    The May 17, 1995 rule also revised the procedures for adjusting the 
span and range of SO2, NOX, and flow monitors. 
Sections 2.1.1.4, 2.1.2.4, and 2.1.4 of Appendix A to the original rule 
had specified that span and range adjustments were required whenever 
the MPC, the MEC, or the MPV changed significantly. When a significant 
change in the MPC, MEC, or MPV occurred, a new range setting was to be 
established and a new span value defined, equal to 80.0 percent of the 
adjusted range value. The revised sections 2.1.1.4, 2.1.2.4, and 2.1.4 
of Appendix A to the May 17, 1995 rule changed this procedure, 
requiring the new span value to be determined first, followed by the 
new range. The May 17, 1995 rule also added procedures for addressing 
full-scale exceedances, specifying that the full-scale value is to be 
reported for an exceedance of one hour and that a range adjustment is 
required for an exceedance greater than one hour. Finally, the May 17, 
1995 rule specified that whenever the range of a gas monitor is 
adjusted, a linearity test is required, and a calibration error test 
must be done when the range of a flow monitor is adjusted.
Discussion of Proposed Changes
    Since promulgation of the May 17, 1995 rule, EPA has continued to 
receive questions and comments about the span and range sections of 
part 75. Many of

[[Page 28055]]

the questions and comments have centered on the adjustment of span and 
range. The following questions are typical: When must the span and 
range be changed? What constitutes a ``significant'' change in the MPC, 
MEC, or MPV? When a span and range adjustment is required, what are the 
deadlines for making the changes and for completing the required 
linearity test? How should full-scale exceedances be reported? There 
also appears to be some lingering confusion and misunderstanding about 
how to determine the flow rate span values and how to calculate the 
maximum potential flow rate (MPF) and the NOX maximum 
emission rate (MER) (see Docket A-97-35, Items II-B-8, II-D-67, and II-
E-31). In view of this, EPA believes that the span and range sections 
of the rule are still not sufficiently clear, flexible, or detailed and 
are in need of further revision. In June, 1996, a national part 75 CEM 
Implementation Workgroup meeting was held in Washington D.C. to discuss 
possible revisions to part 75. One of the principal topics of 
discussion was span and range (see Docket A-97-35, Item II-E-32). 
Today's rulemaking proposes comprehensive revisions to sections 2.1 
through 2.1.4 of Appendix A, based in part on the discussions of the 
June, 1996 meeting. The principal changes are described in paragraphs 
(1) through (5), below.
1. Maximum Potential Values
    The basic procedure for determining the maximum potential of 
SO2 concentration would be unchanged by today's proposal. 
However, two new provisions would be added to section 2.1.1.1 of 
Appendix A to prevent overestimation of the MPC. The first of these 
provisions would allow the exclusion of clearly anomalous fuel sampling 
results when determining the MPC. The second provision would apply to 
units for which the designated representative certifies that the 
highest sulfur fuel is never combusted alone, but is always blended or 
co-fired with other fuel(s) during normal operation. For such units, 
the MPC would be calculated using best estimates of the highest sulfur 
content and lowest gross calorific value expected for the blend or fuel 
mixture and inserting these values into Equation A-1a or A-1b. The best 
estimates of the highest percent sulfur and lowest GCV for a blend or 
fuel mixture would be derived from weighted-average values based upon 
the historical composition of the blend or mixture in the previous 12 
(or more) months.
    The alternative procedure for determining the MPC of SO2 
based upon quality assured historical CEMS data would be retained, but 
it is proposed that the MPC be based, at a minimum, upon the previous 
720 quality assured monitor operating hours, rather than the previous 
30 unit operating days. This is to ensure that a sufficient quantity of 
valid data is used for the MPC determination. Making the determination 
based on 30 unit operating days does not provide that assurance, 
particularly for units that may only operate for a few hours a day 
(e.g., peaking units). Revised section 2.1.1.1 would also specify that 
for a unit with add-on SO2 emission controls, the historical 
CEMS data option may only be selected if the certified SO2 
monitor used to determine the MPC is located at the control device 
inlet.
    For NOX, the general procedures for determining the MPC 
would also remain the same, i.e., either: (1) use the MPC value 
prescribed in the original rule, (2) use the unit-specific value listed 
in Table 2-1 or 2-2, or (3) determine the MPC by emission testing or 
from historical CEM data. However, the following changes to section 
2.1.2.1 of Appendix A are proposed. First, a statement would be added 
that the MPC would have to be based upon the combustion of whichever 
fuel or blend combusted at the unit produces the highest level of 
NOX emissions. Second, an advisory statement would be added, 
noting that the initial MPC value determined for a unit that is not 
equipped with low-NOX burners (LNB) would have to be re-
evaluated if a low-NOX burner system is subsequently 
installed and optimized. Third, if historical CEMS data are used to 
determine the MPC, the determination would have to be based on the 
previous 720 (or more) quality assured monitor operating hours (instead 
of the previous 30 unit operating days). Fourth, units with add-on 
NOX emission controls could only use the historical CEM data 
option if the historical data represented uncontrolled emissions (e.g., 
if the certified CEMS used to collect the data were located prior to 
the control device inlet or, for a unit with seasonal NOX 
controls, if the historical data were from a period when the controls 
were not operating). Fifth, if emission testing is used for the MPC 
determination, sufficient tests would have to be performed at various 
loads and excess oxygen levels to ensure that a credible MPC value is 
obtained. For units with add-on NOX emission controls, the 
emission test data would have to be collected upstream of all controls, 
or, for a unit with seasonal controls, during a period when the 
controls were not operating. Finally, a specific requirement to 
calculate the maximum potential NOX emission rate (MER) 
would be added to section 2.1.2.1 of Appendix A. The May 17, 1995 rule 
had provided a definition of the MER in Sec. 72.2; however, a 
corresponding requirement to calculate the MER was not included in part 
75 at that time. The MER is occasionally needed to provide substitute 
NOX emission rates during missing data periods. The owner or 
operator would be permitted to use the diluent cap value of 5.0 percent 
CO2 or 14.0 percent O2 for boilers (or 1.0 
percent CO2 or 19.0 percent O2 for turbines) in 
the NOX MER calculation.
    For CO2, today's proposed rule would add a new section 
2.1.3.1 to Appendix A, which provides a definition of the MPC. The MPC 
for CO2 pollutant concentration monitors would be 14.0 
percent for boilers and 6.0 percent CO2 for combustion 
turbines. Alternatively, the MPC could be based on a minimum of 720 
hours of representative quality assured historical CEM data.
    For flow rate, the procedure for determining the MPV would be 
essentially unchanged by today's proposed rule, i.e., the MPV would 
either be determined from Equation A-3a (or A-3b, as applicable) in 
Appendix A, or it would be based on velocity traverse data taken at or 
near maximum load. However, a procedure for calculating the maximum 
potential flow rate (MPF) would be added to section 2.1.4.1 of Appendix 
A. The MPF is occasionally used to provide substitute flow rate data; 
therefore, a clear, consistent method of determining the MPF is needed.
2. Maximum Expected SO2 and NOX Concentrations
    Today's proposal would significantly change the procedures for 
determining the maximum expected concentration (MEC) of SO2. 
The purpose of the revisions would be to ensure that the proper span(s) 
and range(s) are selected for SO2 measurement. Proposed 
section 2.1.1.2 of Appendix A would require the MEC to be determined 
for units with SO2 controls and also for uncontrolled units 
that burn both high- and low-sulfur fuels (or blends) as primary or 
backup fuels (e.g., high- and low-sulfur coal or different grades of 
fuel oil).
    The revised procedures for determining the MEC for SO2 
would be as follows. For units with emission controls, Equation A-2 in 
Appendix A would be used to calculate the MEC. For uncontrolled units 
that burn both high-sulfur and low-sulfur fuels or blends as primary or 
backup fuels, Equation A-1a or A-1b in Appendix A (which in the

[[Page 28056]]

current rule is reserved for MPC calculations) would be used to 
determine an MEC value for each fuel or blend, with three important 
exceptions. The MEC would not be calculated for: (1) the highest-sulfur 
fuel or blend (because it would be duplicative of the MPC calculation); 
(2) fuels or blends with a total sulfur content no greater than the 
total sulfur content of natural gas, i.e.,  0.05 percent 
sulfur by weight, because Sec. 75.11(e)(3)(iv) of the current rule 
specifies that natural gas combustion does not trigger a dual span and 
range requirement for the SO2 monitor (for gas firing, the 
MEC and low-scale span values would be too low to be practical for 
quality assurance purposes, e.g., < 5 ppm for pipeline natural gas); 
and (3) fuels or blends that are combusted only during unit startup, 
because such fuels are infrequently used and are not representative of 
normal unit operation.
    Today's proposal would continue to allow the same flexibility in 
the SO2 MEC determination that was introduced in the May 17, 
1995 rule. That is, if a certified SO2 CEMS is already 
installed, the owner or operator could determine the MEC based upon 
historical continuous monitoring data, in lieu of using mathematical 
equations. If this option were chosen for a unit with SO2 
controls, the MEC would be the maximum SO2 concentration 
measured at the control device outlet by the CEMS over the previous 720 
or more quality assured monitor operating hours with the unit and the 
control device both operating normally. For units that burn both high- 
and low-sulfur fuels or blends as primary and backup fuels and have no 
SO2 controls, the MEC for each fuel would be the maximum 
SO2 concentration measured by the CEMS over the previous 720 
or more quality assured monitor operating hours in which that fuel or 
blend was the only fuel being burned in the unit.
    Today's rule also proposes to change the way in which the MEC is 
determined for NOX. Revised section 2.1.2.2 of Appendix A 
would require a determination of the MEC during normal operation for 
units with add-on NOX controls capable of reducing 
NOX emissions to 20.0 percent or less of the uncontrolled 
level (i.e., steam injection, water injection, selective catalytic 
reduction or selective non-catalytic reduction). A separate MEC 
determination would be required for each type of fuel combusted, except 
for fuels that are only used for unit startup or for flame 
stabilization. The MEC would be determined in one of three ways: (1) 
using Equation A-2 in Appendix A; or, if that equation is not 
appropriate, (2) by emission testing or (3) by using historical CEMS 
data from the previous 720 (or more) quality assured monitor operating 
hours. Revised section 2.1.2.2 would give specific guidelines and 
procedures by which to obtain the MEC when the emission testing or CEMS 
data options are selected. All CEMS or emission test data used for the 
MEC determination would be taken under stable operating conditions with 
all control devices and methods operating properly.
3. Span and Range Values
    For SO2, NOX, and flow rate, respectively, 
revised sections 2.1.1.3, 2.1.2.3 and 2.1.4.2 of Appendix A would allow 
the high-scale span value to be between 100.0 and 125.0 percent of the 
maximum potential value (i.e., the MPC or MPV), rounded off 
appropriately. This is a change from the current rule which requires 
the high span to be set at 125.0 percent of MPC or MPV, rounded off 
appropriately. However, the change is not expected to be disruptive, 
because properly sized span values previously determined by multiplying 
the MPC or MPV by 1.25 could continue to be used. The change would 
allow the owner or operator to set the span value in such a way that a 
small exceedance of MPC or MPV would not require a span change (see 
paragraph 5, ``Adjustment of Span and Range,'' below). The added 
flexibility in span selection would also allow different units with 
similar (but not identical) MPCs for SO2 and/or 
NOX to use the same span value and to use the same 
calibration gas concentrations, which could result in cost savings for 
some facilities. In 1996, EPA received and approved a petition from one 
utility to equalize the SO2 span values at several of its 
coal-fired units (see Docket A-97-35, Items II-C-23, II-D-71).
    For CO2 and O2 monitors, today's proposal 
would revise section 2.1.3 of Appendix A to allow the owner or operator 
maximum flexibility in selecting an appropriate span value. The 
CO2 or O2 span value would not be determined in 
the same way as an SO2, NOX, or flow rate span 
value. Rather, for CO2 monitors installed on boilers, any 
convenient span value between 14.0 percent and 20.0 percent 
CO2 representing the percent diluent in the flue gas would 
be acceptable. For combustion turbines, any CO2 span value 
between 6.0 and 14.0 percent CO2 could be used. For 
O2 monitors, a span value between 15.0 percent and 25.0 
percent O2 could be selected. However, if the O2 
concentrations are expected to be consistently below 15.0 percent, an 
alternative span value of less than 15.0 percent could be used, 
provided that an acceptable technical justification was included in the 
monitoring plan. The proposed rule would also allow purified instrument 
air containing 20.9 percent O2 to be used as the high level 
calibration gas for oxygen monitors having span values greater than or 
equal to 21.0 percent O2.
    There are two principal reasons why EPA is proposing increased 
flexibility in the selection of the CO2 and O2 
span values. The first is to encourage greater accuracy in the diluent 
gas measurements. The revisions would allow the span value to be 
customized so that the concentration of the upscale calibration gas 
used for daily calibrations can be as close as possible to the actual 
average CO2 or O2 concentrations in the stack. In 
1996, EPA received and approved a petition from one utility to use a 
CO2 span value of 15.0 percent for its coal-fired units, 
rather than the 20.0 percent span value required by part 75 (see Docket 
A-97-35, Items II-C-20, II-D-68). The second reason for revising the 
CO2 and O2 span requirements is to eliminate 
unnecessary high-level span and range requirements. The current rule 
requires a high span value of 20.0 percent for all CO2 and 
O2 monitors. However, there are many units (e.g., combustion 
turbines) for which the diluent gas concentrations are so low that the 
guideline in the current section 2.1 of Appendix A (i.e., that the 
majority of the readings be within 25.0 to 75.0 percent of full-scale) 
cannot be met unless a second, low-scale span and range are used. For 
most of these units, there are technical and safety reasons why the 
diluent concentrations must remain low; therefore, it is unreasonable 
to require a high range to be maintained if a lower range will suffice 
and can never be exceeded. During the Phase II certification process, 
EPA approved CO2 span values of 10.0 percent for a number of 
combustion turbines and waived the high-scale range requirement (see 
Docket A-97-35, Items II-C-19, II-C-21, II-D-64).
    Today's proposal would not change the basic way in which the full-
scale range setting of a monitor is determined. The range would still 
have to be set greater than or equal to the span value. However, the 
guideline for selecting an appropriate full-scale range in section 2.1 
of Appendix A would be revised as follows. With few exceptions, the 
full-scale range would be selected so that, to the extent practicable, 
the readings during typical unit operation fall between 20.0 and 80.0 
percent of full-scale; this represents a slight increase in flexibility 
from the ``25-to-75 percent of

[[Page 28057]]

full-scale'' guideline in the current rule. Today's proposal would also 
emphasize that section 2.1 is only a guideline and would cite three 
specific cases in which it is inapplicable. Specifically, the guideline 
would not apply to: (1) quality assured SO2 readings 
obtained during the combustion of natural gas or fuel with equivalent 
total sulfur content (because the resulting SO2 emissions 
are too low to be subject to the span and range requirements); (2) 
quality assured SO2 or NOX readings on the high 
range for an affected unit with SO2 or NOX 
emission controls and two span values (because the high range is not 
the normal operating range for the unit); and (3) quality assured 
SO2 or NOX readings less than 20.0 percent of the 
low measurement range for a dual-span unit with SO2 or 
NOX emission controls, provided that the low readings are 
associated with periods of high control device efficiency (because it 
is not necessary to re-range a monitor based on non-representative 
hours of exceptional control performance).
    For flow monitors, today's rule proposes to revise section 2.1.4.2 
of Appendix A to more clearly define the ``calibration span value'' 
(which is the span expressed in the units of measure used for the daily 
calibrations) and the ``flow rate span value'' (which is the span 
expressed in the units used for electronic data reporting, i.e., scfh). 
The proposed rule defines these two span values in considerable detail 
and outlines how to use them. EPA believes that this will result in 
greater consistency in implementation of the part 75 flow rate 
monitoring requirements.
4. Dual Span and Range Requirements for SO2 and 
NOX
    In today's rule, revisions are proposed to the dual span and range 
requirements for SO2 and NOX monitors in sections 
2.1.1.4 and 2.1.2.4 of Appendix A. The revised provisions are 
essentially the same for both pollutants. To determine whether a 
second, low-scale span is required in addition to the high-scale span 
based on the MPC, each of the maximum expected concentration (MEC) 
values determined under revised section 2.1.1.2 or 2.1.2.2 of Appendix 
A would be compared against the maximum potential concentration (MPC) 
determined under proposed sections 2.1.1.1 or 2.1.2.1. If this 
comparison shows any of the MEC values to be < 20.0 percent of the MPC, 
a low-scale span would be required. If several of the MEC values are 
found to be < 20.0 percent of the MPC, then the low-scale span would be 
based upon whichever MEC value is closest to 20.0 percent of the MPC. 
The low-scale span value would be determined in a manner similar to the 
high-scale span, i.e., by multiplying the MEC by a factor between 1.00 
and 1.25 and rounding off the result appropriately.
    When both a high-scale span and a low-scale span are required for 
SO2 or NOX, proposed sections 2.1.1.4 and 2.1.2.4 
would allow the owner or operator to use either of the following 
monitor configurations to meet the dual-range requirement: (1) a single 
analyzer with two ranges, or (2) two separate analyzers connected to a 
common probe and sample interface. The use of other monitoring 
configurations would be subject to the approval of the Administrator. 
The monitor configurations would be represented in the monitoring plan 
as follows: (a) the high and low ranges could be designated as two 
separate, primary monitoring systems; (b) the high and low ranges could 
be designated as separate components of a single, primary monitoring 
system; or (c) one range (the ``normal'' range) could be designated as 
a primary monitoring system, and the other range as a non-redundant 
backup monitoring system. The high and low ranges would be quality 
assured according to their designation in the monitoring plan. Primary 
monitoring systems would have to meet the QA requirements for primary 
systems in Sec. 75.20(c), Appendix A, and Appendix B, with the 
following exception: relative accuracy test audits (RATAs) would be 
required only on the normal range. For units with emission controls, 
the low range would be considered normal; for other units, the range in 
use at the time of the scheduled RATA would be considered normal. Non-
redundant backup systems would have to meet the applicable QA 
requirements for ``like-kind replacement analyzers'' in proposed 
Sec. 75.20(d).
    Today's rule would add a new alternative provision under sections 
2.1.1.4 and 2.1.2.4 of Appendix A for dual-span units with 
SO2 or NOX emission controls. The new provision 
would allow the owner or operator to use a ``default high-range value'' 
in lieu of operating, maintaining, and quality assuring a high-scale 
monitor range. The default high-range value would be 200.0 percent of 
the MPC (based on uncontrolled emissions). This value would be reported 
whenever the SO2 or NOX concentration exceeded 
the full-scale of the low-range analyzer. The default high-range value 
is being proposed for controlled units that seldom, if ever, experience 
full-scale exceedances of the low monitor range during normal operation 
(e.g., units that have a permit condition requiring cessation of unit 
operation when a full-scale exceedance occurs or units that experience 
low-range exceedances only during startup). EPA solicits comment on the 
proposed approach of using a default high-range value in lieu of a high 
range monitor and on the value of the default.
    EPA specifically requests comment on whether the proposed dual-span 
monitoring configurations, monitoring system designations, and quality 
assurance requirements are adequate, or whether there are additional 
configurations (e.g., one range with two spans, two separate analyzers 
with separate probes, etc.) that should be included in the rule.
    Finally, when two spans and ranges are required, proposed revised 
sections 2.1.1.4 and 2.1.2.4 of Appendix A would specify that the low 
range would have to be used to record emission data when the 
SO2 or NOX concentrations are expected to be 
consistently below 20.0 percent of the MPC (i.e., when a fuel or blend 
with a MEC value < 20.0 percent of the MPC is combusted). And if the 
full-scale of the low range is exceeded, the high range would be used 
to record data (or, if applicable, the default high range value would 
be reported).
5. Adjustment of Span and Range
    In today's rule, detailed guidelines and procedures are proposed 
for adjusting the span and range of the CEMS in revised sections 
2.1.1.5, 2.1.2.5, 2.1.3.2 and 2.1.4.3 of Appendix A. The intent of 
these provisions is to ensure that each owner or operator assesses the 
adequacy of all CEMS span values on at least a quarterly basis (and 
whenever operational changes are planned) and, based on that 
assessment, makes any necessary adjustments to the spans or ranges in a 
timely manner. EPA believes that the proposed procedures are 
sufficiently flexible so that frequent span and range adjustments will 
not be necessary. The procedures are primarily directed at CEMS with 
improperly-sized spans and ranges, to bring them into full conformance 
with part 75 requirements or for future changes in unit operation 
(e.g., fuel switch or low-NOX burner installation) that may 
significantly affect the level of emissions or flow. All required span 
or range adjustments would have to be made no later than 45 days after 
the end of the quarter in which the need to adjust the span or range is 
identified, unless the span change would require new calibration gases 
to be ordered for daily calibration error and linearity tests, in which 
case, the owner or operator would have up to

[[Page 28058]]

90 days after the end of the quarter to make the span adjustment.
    The revised procedures for span and range adjustment would be as 
follows. First, if the maximum value upon which the high span value is 
based (i.e., the MPC or, for flow rate, the MPF) is exceeded during a 
calendar quarter, but the span is not exceeded, the span or range would 
not have to be adjusted. However, for missing data purposes, if any 
quality assured hourly concentration or flow rate exceeds the MPC or 
MPF by  5.0 percent during the quarter, a new MPC or MPF 
would have to be defined, equal to the highest value recorded during 
the quarter, and a monitoring plan update would be required. Second, 
for the high measurement range, if any quality assured reading exceeded 
the span value by  10.0 percent during the quarter but did 
not exceed the range, a new MPC or MPF (as applicable) would have to be 
defined, equal to the highest on-scale reading recorded during the 
quarter, and the span value would also have to be changed. If the new 
span value exceeded the current full-scale range setting, then a new 
range setting would also be required. Similar span adjustment 
requirements would apply to the low scale if the two measurement ranges 
are used separately for distinctly different modes of operation (e.g., 
during the combustion of different fuels), rather than being used in 
combination to provide a continuum of measurement range capability.
    The proposed procedures for responding to full-scale exceedances 
are as follows. Whenever the full-scale of a high monitor range is 
exceeded, excluding hours of non-representative operating conditions 
(e.g., a trial burn of a new fuel), corrective action would be required 
to adjust the span and range. In addition, any time the range is 
exceeded, a value of 200.0 percent of the current full-scale range 
would be reported to EPA for each hour of each full-scale exceedance. 
The Agency believes that 200.0 percent of the range is sufficiently 
conservative to ensure that emissions would not be under-reported. One 
utility that experienced a full-scale exceedance of the high 
SO2 monitor range estimated from the results of fuel 
sampling that the SO2 concentration was approximately 150.0 
percent of full-scale during the incident (see Docket A-97-35, Item II-
D-24).
    For units with two span values and two measurement ranges for a 
particular parameter (e.g., SO2), when the full-scale of the 
low range is exceeded, provided that the high monitor range is 
available to record emission data, no corrective actions would be 
required. However, if, at the time of the low-range exceedance or 
during the continuation of the low-range exceedance, the high range is 
either out-of-service or out-of-control for any reason (and therefore 
is not available to record quality assured data), the MPC would have to 
be reported until the readings either returned to the low scale or 
until the high scale returned to service and was able to provide 
quality assured data. However, if the reason the high scale is 
unavailable is because of a high scale exceedance, 200.0 percent of the 
high range value would be reported for each hour of the exceedance.
    Proposed sections 2.1.1.5(e), 2.1.2.5(e), and 2.1.4.3(e) of 
Appendix A would require that the monitoring plan be updated whenever 
changes are made in the maximum potential values, maximum expected 
values, span values, or full-scale range settings. The updates would be 
made in the quarter in which the changes become effective. The proposed 
sections 2.1.1.5(e) and 2.1.2.5(e) of Appendix A would further require 
a linearity test to be done whenever the span of a gas monitor is 
adjusted, if the span change is significant enough to require new 
calibration gases for daily calibration error tests and linearity 
checks. Finally, proposed sections 2.1.4.3(c) and (d) of Appendix A 
would require a calibration error test to be done whenever a flow 
monitor span or range is adjusted (unless the adjustment requires a 
significant change to the flow monitor that would require 
recertification under Sec. 75.20(b)).

J. Quality Assurance/Quality Control (QA/QC) Program

1. QA/QC Plan
Background
    Section 1 of Appendix B to part 75 as originally promulgated on 
January 11, 1993 sets forth provisions for developing and implementing 
a quality control program. As part of the quality control program, 
section 1 requires that the source develop and maintain a quality 
control plan that documents how the equipment used to report emissions 
data for part 75 is maintained and quality assured. While the 
provisions in sections 1.1, 1.2, and 1.4 of Appendix B to part 75 are 
applicable only to continuous emissions monitoring systems, the 
provisions in sections 1.3 and 1.5 of the existing rule are more 
generally applicable to all monitoring systems under part 75. The 
quality assurance requirements for excepted monitoring systems under 
Appendices D and E and for alternative monitoring systems under subpart 
E are provided in the respective Appendices or subpart of part 75, as 
revised; however, specific guidelines for the quality control plans for 
these systems are not given.
    Based on the experience of state and EPA inspectors at Acid Rain 
field audits, there has been confusion and inconsistency among industry 
sources regarding the contents of the quality control plan. In some 
cases, utility staff have requested further guidance from EPA on what 
the quality control plan should contain. Based on this experience, the 
Agency believes that the quality control program provisions in section 
1 of Appendix B need to be revised. Specifically, the rule needs to be 
clarified in two areas: (1) the applicability of the QA/QC program 
(i.e., do the provisions apply to all monitoring systems, only to CEMS, 
or only to specific excepted or alternative monitoring systems?); and 
(2) the recordkeeping requirements for repair and maintenance events. 
In addition, several utilities have asked EPA to consider deleting the 
requirement to maintain an inventory of spare parts, which they believe 
to be unnecessary and burdensome.
Discussion of Proposed Changes
    The proposed revisions discussed in this section affect section 1 
of Appendix B to part 75. The terms ``quality control program and 
plan'' would be changed to ``quality assurance/quality control program 
and plan.'' The scope of section 1 would be expanded to include QA/QC 
program provisions for excepted monitoring systems under Appendices D, 
E, and I and alternative monitoring systems under subpart E. Section 1 
would also be reordered to separate the requirements applicable to all 
monitoring systems (section 1.1) from the requirements specific to CEMS 
(section 1.2). The preventative maintenance provisions, in section 1.3 
of the existing rule, would be moved to section 1.1.1 of the proposal, 
and would be revised to delete the requirement to maintain an inventory 
of spare parts. A new section 1.1.3 would be added to specify the 
requirements for maintaining records of testing, maintenance, and 
repair activities. QA/QC program requirements specific to excepted 
monitoring systems under Appendices D, E, and I would be added in 
section 1.3. These provisions would require written procedures to be 
maintained for fuel flowmeter testing, primary element inspection, and 
fuel sampling and analysis as well as requiring a description of 
equipment and records of testing to be maintained. Section 1.3.6 would 
make the

[[Page 28059]]

recordkeeping requirements consistent with the quality assurance 
requirements of section 2.3.1 of Appendix E. Section 1.3.7 would 
specify which QA/QC program requirements apply for excepted monitoring 
systems under Appendix I. Finally, section 1.4 would define the QA/QC 
program requirements for alternative monitoring systems approved under 
subpart E, based on the quality assurance requirements of subpart E.
Rationale
    The Agency believes that the manner in which quality assurance/
quality control (QA/QC) and maintenance-related activities are 
performed can have a significant effect upon the accuracy of the data 
reported by a monitoring system. Therefore, today's proposal seeks to 
ensure that adequate records are kept to document that each monitoring 
system and its ancillary components is being maintained and operated in 
a proper manner. Section 1 in Appendix B to part 75 would, therefore, 
be amended to provide sources with General guidance regarding QA/QC 
program requirements. However, the Agency recognizes that QA/QC 
programs may vary from site to site and that many sources have already 
developed and implemented an effective QA/QC program. It is the 
Agency's intent to allow each source the flexibility to develop and 
implement a QA/QC program that will result in the reporting of accurate 
emissions data through proper equipment calibration, maintenance and 
troubleshooting procedures.
    (a) Inventory of Spare Parts. Section 1.3 of Appendix B to part 75 
in the January 11, 1993 rule requires that an inventory of spare parts 
be maintained as part of the QA/QC program. The intent of this 
requirement is one of the fundamental goals of a QA/QC program, i.e., 
to maximize the availability of quality-assured data from the 
monitoring system. Since maintenance and repairs are required in order 
to keep the monitoring system operating properly, the need for 
replacement parts will arise over the term of use of the monitoring 
equipment. In order to minimize the amount of time when the system is 
unable to provide data because a new part is needed, the existing rule 
requires that the source maintain an inventory of spare parts. The 
Agency has received comments on this requirement from both affected 
utilities and from state inspectors arguing that it is unnecessary and 
cumbersome (see Docket A-97-35, Item II-D-49, II-E-28). Commenters have 
suggested that different approaches have been effectively employed to 
ensure that spare parts are available in a timely manner; however, not 
all of these approaches require that an inventory of spare parts be 
kept on-site. For example, some spare parts may be available on a very 
timely basis from a local supplier, making it unnecessary to maintain 
spare parts on-site. The Agency believes that these different 
approaches may be adequate substitutes for keeping an on-site inventory 
of spare parts. Therefore, the requirement to maintain an inventory of 
spare parts would be removed in today's proposal, although the 
objective of an effective QA/QC program, i.e., to maximize data 
availability, would not change.
    (b) Maintenance Records. The Agency believes that maintaining 
records of monitoring system maintenance and repairs is an essential 
component of an effective QA/QC program. Several utilities have 
indicated that they agree and have instituted QA/QC programs which 
include maintaining such records (see, e.g., Docket A-97-35, Item II-D-
88). However, some EPA and state inspectors have found that not all 
sources keep adequate records of maintenance and repairs in their QA/QC 
program. EPA believes that this failure to keep adequate records 
compromises the effectiveness of the QA/QC program. Therefore, today's 
proposal would require each source to maintain proper records of all 
testing, maintenance, or repair activities performed on any monitoring 
system or component. Additionally, today's proposal would require that 
these records and any additional supporting documentation be made 
available for review during an audit.
    (c) Excepted Monitoring System Requirements. The required quality 
assurance activities for excepted monitoring systems are set forth in 
the respective Appendices D, E, or I. Today's proposed revisions in 
section 1.3 of Appendix B would specify that information on the 
approved methods, test procedures and test results must be maintained 
on-site suitable for inspection as part of the QA/QC program. The 
proposed revisions would consolidate all of the QA/QC requirements in 
Appendix B rather than having them spread out in Appendices D, E, and 
I.
2. Flow Monitor Polynomial Coefficient
Background
    Many of the stack gas volumetric flow rate monitors currently in 
use by affected sources use software polynomial coefficients to convert 
electrical signals from the monitors into flow rate values that are 
electronically reported to the Acid Rain Division. The flow rate values 
generated from these monitors are used by the source's data acquisition 
and handling system (DAHS) to compute hourly mass emission rates of 
SO2, CO2, and hourly heat input rates. Currently, 
affected sources are not specifically required to report, record, or 
document the numerical values of the polynomial coefficients used by 
their flow monitors.
Discussion of Proposed Changes
    Proposed Sec. 75.59(a)(5)(vi) and proposed revisions to section 
1.1.3 of Appendix B would require the current values of the flow 
monitor coefficients to be recorded and would require records to be 
kept of any changes or adjustments to the coefficient values. The 
proposed revisions in Sec. 75.20(b) define flow monitor coefficient 
adjustment as an event which requires recertification.
Rationale
    (a) Recordkeeping of Coefficients. The agency has recently become 
aware (by a comment received in response to a request for review of the 
Acid Rain Audit Manual) of a potentially serious omission in the flow 
monitor recordkeeping requirements of part 75 (see Docket A-97-35, Item 
II-D-92). The commenter indicated that part 75 lacks a requirement to 
document the values of the polynomial coefficients which are programmed 
into the software of most flow monitoring devices, and that the Acid 
Rain CEM audit manual does not recommend that Agency or state auditors 
check the coefficient values. The values of the polynomial coefficients 
are important because they are directly related to the accuracy of a 
flow monitor. The coefficient values are usually established at three 
different load levels (low, mid, and high), in a process called 
``linearization'' or ``characterization'' of the monitor. Linearization 
is done in an attempt to ensure that the flow monitor reads accurately 
across all load levels. The Agency agrees with the commenter that the 
flow monitor variables are a critical component of the flow monitoring 
system and that the adjustment of those variables represents a 
significant change to the flow monitoring system. Therefore, today's 
rulemaking proposes to add Sec. 75.59(a)(5)(vi) to require owners and 
operators of affected sources to record the numerical values of the 
flow monitor polynomial coefficients used during initial certification 
of the monitor and during each subsequent relative accuracy test audit 
(RATA). In

[[Page 28060]]

addition, section 1 of Appendix B to part 75 would be revised to 
require that any changes to the flow monitor polynomial coefficients be 
documented and maintained as part of the QA/QC program maintenance 
records. Section 1 of Appendix B would also be changed to require the 
source to document procedures related to the adjustment of flow monitor 
variables in its QA/QC plan. The values of the flow monitor 
coefficients and the related adjustment procedures would be required to 
be kept on-site, in a format suitable for review by an inspector during 
an audit.
    (b) Recertification After Adjustment of Coefficients. Since 
changing the flow monitor polynomial constants relinearizes the 
instrument, significantly altering the monitored reading, today's 
proposed rule would amend Sec. 75.20(b) to require recertification 
subsequent to any flow monitor polynomial coefficient change. Since a 
three level RATA is the only part 75 quality assurance test that checks 
the linearity of a flow monitor, the recertification would require a 
three level RATA.

K. Calibration Gas Concentration for Daily Calibration Error Tests

Background
    All part 75 gas monitoring systems are required by section 2.1.1 of 
Appendix B of the current rule to pass daily calibration error tests, 
in order to validate emission data from the CEMS. The procedures for 
conducting the daily calibration error tests are found in section 6.3.1 
of Appendix A. Each daily calibration error test consists of injecting 
two protocol gases of known concentration into the CEMS and comparing 
the responses of the instrument to the tag values of the protocol 
gases. The two required gas concentrations for the calibration error 
tests are zero-level (i.e., 0.0 to 20.0 percent of the span value of 
the instrument) and high-level (80.0 to 100.0 percent of span).
    The span values of part 75 SO2 and NOX 
monitors are determined by multiplying the maximum potential 
concentration (MPC) by 1.25 and rounding the result upward to the 
nearest 100.0 ppm. For CO2 and O2 monitors, a 
span value of 20.0 percent O2 or CO2 is 
prescribed. These span values have been deliberately oversized to 
prevent full-scale exceedances from occurring. Consequently, the 
SO2, NOX, CO2, and O2 
readings obtained during normal unit operation are generally well below 
the span values and typically range from about 25.0 to 75.0 percent of 
full-scale. Because of the oversized span values, the concentrations of 
the high-level calibration gases used for daily calibration error tests 
are often much higher than the actual pollutant and diluent gas 
concentrations in the stack. As a result, the representativeness of the 
daily calibration error test can be questioned, because the test does 
not always check the accuracy of an analyzer on the part of the scale 
where most of the readings occur. For instance, typical CO2 
concentrations for many part 75 units range from about 10.0 to 12.0 
percent CO2 (i.e., 50.0 to 60.0 percent of the span value). 
However, when CO2 analyzers are calibrated, the high-level 
calibration gas concentrations (i.e., 16.0 to 20.0 percent 
CO2 ) are considerably higher than normal stack emissions. 
In view of this, EPA believes it would be appropriate to allow the 
owner or operator to have greater flexibility in selecting a 
representative upscale gas for daily calibrations. One State agency has 
successfully implemented this type of flexibility in its CEM program. 
The State's CEM rule specifies the acceptable range of values for the 
upscale calibration gas, but adds the following qualifying statement, 
``* * *unless an alternative concentration can be demonstrated to 
better represent the normal source operating levels *-*-*'' (see Docket 
A-97-35, Item II-D-72).
Discussion of Proposed Changes
    Today's rule proposes to add flexibility to the procedures for 
conducting the calibration error tests of part 75 gas monitors to 
encourage daily calibrations to be done more representatively. Section 
6.3.1 of Appendix A would be revised so that, beginning on January 1, 
2000, either the mid-level gas (50.0 to 60.0 percent of span) or the 
high-level gas (80.0 to 100.0 percent of span) could be used as the 
upscale calibration gas for daily calibration error tests. A 
corresponding change would be made to the procedure for calculating the 
calibration error in section 7.2.1 of Appendix A. Prior to January 1, 
2000, the owner or operator would have the option of using the mid-
level calibration gas for daily calibrations if it better represents 
the typical stack gas concentrations than the high-level gas.

L. Linearity Test Requirements

Background
    Section 75.20(c) of the current part 75 rule requires a 3-point 
linearity test of each SO2 and NOX pollutant 
concentration monitor and each diluent gas (O2 or 
CO2) monitor, as part of the initial certification process. 
A linearity test consists of a series of nine reference calibration gas 
injections at three different known concentration levels (low, mid, and 
high) to establish the accuracy of a gas analyzer across its 
measurement range. The procedures for conducting linearity tests are 
found in section 6.2 of Appendix A to part 75. Section 6.1 of Appendix 
A specifies that linearity tests must be done while the unit is 
operating.
    After the initial certification of a gas monitoring system, section 
2.2 of Appendix B to part 75 requires periodic linearity tests to be 
performed. A linearity check is required during each unit operating 
quarter or, for bypass stacks, during each quarter in which flue gases 
are discharged through the stack. For units with two span values for a 
particular parameter (e.g., units with add-on SO2 controls), 
linearity tests must be conducted on both the ``low'' and ``high'' 
monitor ranges. Successive linearity tests are, to the extent 
practicable, to be conducted no less than 2 months apart.
    Utility representatives have asked EPA to consider changing the 
requirement for the unit to be operating when linearity tests are done 
(see Docket A-97-35, Items II-D-20, II-D-65, II-E-13, II-E-14). This 
has been requested because owners and operators of peaking units and 
other units that operate on an ``on-call'' basis have experienced 
difficulty in complying with the requirement for the unit to be on-line 
during linearity tests. For instance, a unit may only operate for a few 
hours in a quarter and not be needed again until the next quarter. In 
such a situation, the utility might be forced to re-start and operate 
the unit (whether or not it is needed) to comply with the linearity 
test requirement. Some of the utility representatives have also 
expressed the opinion that for certain monitoring technologies (e.g., 
dry extractive), on-line and off-line linearity tests are essentially 
equivalent.
Discussion of Proposed Changes
1. Unit Operation During Linearity Tests
    Today's rule proposes to revise the linearity test requirements of 
part 75 to make them easier with which to comply. EPA agrees that the 
current linearity test requirements of part 75 lack flexibility and 
that compliance with the requirements is particularly difficult for 
infrequently operated units. However, the Agency does not agree with 
the utility representatives that have suggested allowing off-line 
linearity tests as the best solution to the problem. Nor is the Agency 
proposing to allow technology-specific exemptions to the on-line 
linearity test requirement.

[[Page 28061]]

Rather, today's proposal would retain the requirement for linearity 
tests to be performed while the unit is combusting fuel at conditions 
of typical stack temperature and pressure. A clarifying statement would 
be added to section 6.2 of Appendix A, indicating that the unit does 
not have to be generating electricity during the test. But EPA would 
continue to require that a linearity test be performed while the unit 
is combusting fuel at conditions of typical stack temperature and 
pressure in order to test the monitoring system under the same 
conditions as when the monitor is measuring emissions, in order to 
account for any temperature and pressure effects. An on-line linearity 
test challenges a CEMS while it is in equilibrium with the stack 
environment and has been sampling stack gas continuously for a period 
of time.
2. Linearity Test Frequency
    The Agency proposes instead to add flexibility to the linearity 
test requirements by changing the basis upon which the frequency of 
linearity tests is determined and by providing a linearity grace 
period. In today's proposal, section 2.2 of Appendix B would be revised 
to require that a linearity test be performed in each ``QA operating 
quarter'' rather than in each ``unit operating quarter'' or ``bypass 
stack operating quarter.'' For linearity tests, a QA operating quarter 
would be defined in the same way as for RATAs, i.e., as a calendar 
quarter in which the unit operates for at least 168 hours (or, for 
common stacks, a quarter in which effluent gases discharge through the 
stack for at least 168 hours). EPA believes that the QA operating 
quarter methodology would, in most instances, enable the owner or 
operator of a peaking unit or other infrequently operated unit to 
complete an on-line linearity test within the calendar quarter in which 
it is due. However, the following additional changes would be made to 
further ensure that the linearity test requirements can be met: (1) the 
requirement to perform successive linearity tests at least 2 months 
apart would be reduced to allow successive tests to be done one month 
(30 days) apart; and (2) a new section, 2.2.4, would be added to 
Appendix B, providing a 168 unit operating hour grace period after the 
end of each QA operating quarter in which to complete the required 
test. Thus, to make it easier for infrequently operated units to 
complete the required linearity tests in the quarters in which they are 
due, the required waiting time between successive linearity tests would 
be reduced. And, if circumstances should prevent a linearity test from 
being completed in the QA operating quarter in which it is due, the 
test could be done during the grace period. If the required linearity 
test were not completed by the end of the grace period, data from the 
monitor would be considered invalid from the hour after the grace 
period expires until the hour of completion of a subsequent successful 
linearity test.
    For infrequently operated units, certain calendar quarters would 
not qualify as QA operating quarters. Therefore, in accordance with 
today's proposed rule, no linearity tests would be required in those 
quarters. However, this exemption from linearity testing would not be 
without limit. Proposed section 2.2.2 of Appendix B would allow no more 
than four consecutive calendar quarters to elapse following the quarter 
in which the last linearity test was conducted, without a subsequent 
linearity test having to be performed. That is, a linearity test would 
either have to be done by the end of the fourth consecutive elapsed 
calendar quarter since the last test or within a 168 unit operating 
hour grace period after the end of the fourth consecutive elapsed 
quarter. Data from the monitor would become invalid if the linearity 
test was not completed by the end of the grace period and would remain 
invalid until a linearity test was successfully completed.
    Today's proposal would also change the requirement for units with 
two span values for a particular parameter (e.g., units with add-on 
SO2 controls) to perform quarterly linearity tests on both 
the low and high monitor ranges. Section 2.2.1 of Appendix B would be 
revised to require a linearity test of a monitor range only if that 
range is used to report data during the QA operating quarter. However, 
under proposed section 2.2.3(e) of Appendix B, at least one linearity 
test of each range would still be required every four calendar quarters 
to maintain data validation on the range.
3. Linearity Test Method
    Today's proposal would add two new requirements to section 6.2 of 
Appendix A: (1) that all linearity tests must be done ``hands-off,'' 
meaning that no adjustments of the CEMS other than certain calibration 
error adjustments would be permitted prior to or during the linearity 
test period; and (2) to the extent practicable, each linearity test 
would have to be completed within a period of 24 unit operating hours. 
These proposed provisions are intended to ensure greater consistency in 
the way in which linearity tests are conducted and to ensure that the 
tests are completed in a timely manner. The allowable calibration 
adjustments prior to and during a linearity test would be defined in 
proposed section 2.1.3 of Appendix B. For a further discussion, see 
Section O of this preamble, ``CEM Data Validation,'' below.
4. Exemptions
    Finally, section 6.2 of Appendix A would be revised to exempt 
SO2 and NOX monitors with span values of 30 ppm 
or less from the linearity test requirements of part 75. At these low 
span values, the linearity test begins to lose its significance. For 
example, typical low, mid, and high calibration gases for a span value 
of 30.0 ppm would be 24.0 ppm, 18.0 ppm, and 9.0 ppm, respectively. The 
appropriate linearity performance specification in section 3.2 of 
Appendix A is  5.0 ppm at each calibration gas level. 
Therefore, in this illustration, the monitor reading could be 14.0 ppm 
for both the ``low'' and ``mid'' gases or 20.0 ppm for both the ``mid'' 
and ``high'' gases. Even though a valid straight line comparing the 
reference gas concentrations and the monitor readings cannot be 
constructed from such data, the monitor would still appear to pass the 
linearity test.

M. Flow-to-Load Test

Background
    The current quality assurance requirements for flow rate monitoring 
systems in Appendices A and B to part 75 include daily calibration 
error tests, daily interference checks, quarterly leak checks (for 
differential pressure type monitors only), and semiannual or annual 
relative accuracy test audits. Of these required QA tests, only the 
RATA provides a true evaluation of a flow monitor's measurement 
accuracy by direct comparison against an independent reference method. 
The daily calibration error test purports to check flow monitor 
accuracy, but, as explained below, the ability of the test to 
accomplish this objective is somewhat questionable.
    There is a distinct difference between the daily calibration error 
test of a flow rate monitor and the calibration error test of a gas 
monitor. To calibrate a gas monitor, a protocol gas of known 
concentration is sent through the monitoring system and analyzed. This 
generally serves as a reliable indicator of the system's ability to 
accurately measure pollutant or diluent gas concentrations, because the 
calibration closely simulates the sampling and analysis of stack gas by 
the monitoring

[[Page 28062]]

system. A flow monitor calibration error test, on the other hand, does 
not provide the same level of assurance of data quality. Generally, a 
flow monitor calibration checks the system's internal electronic 
components by means of reference signals. The calibration error test is 
useful in that it can diagnose certain types of monitor problems, but 
it is not a ``true'' calibration of the monitor, since it does not 
evaluate the system's ability to measure an actual stack gas flow rate. 
In order to perform true daily flow monitor calibrations, two reference 
stack gas flow rates would have to be generated and measured. Practical 
considerations preclude such calibrations from being done, however, 
because the unit load level would have to be significantly varied 
during each operating day, and suitable reference method measurements 
(e.g., velocity traverses using EPA Method 2) would have to be made 
daily at each calibration load level.
    Because of the limited usefulness of the flow monitor daily 
calibration error test, EPA believes that a more substantive, periodic 
QA test is needed to ensure that the accuracy of the reported flow rate 
data is maintained in the interval between successive RATAs. The Agency 
is particularly concerned about the potential for poor data quality 
from flow monitors that are not properly maintained. For instance, the 
sensors of DP and thermal-type monitors are subject to plugging and/or 
fouling, which will cause the monitors to read lower than true and can 
result in under-reporting of emissions. One utility observed a 
substantial increase in the readings from its flow monitor after the 
sensors were cleaned during a unit outage. Apparently, the sensor 
problems had not been detected by the daily calibration error tests 
(see Docket A-97-35, Item II-E-29). A second utility experienced a 
gradual deterioration of the monitor's performance in the 9-month 
period following the RATA. By the sixth month (at load levels and 
CO2 concentrations virtually identical to the conditions at 
the time of the RATA), the flow monitor readings were consistently 15.0 
to 20.0 percent lower than the baseline average flow rate measured by 
EPA Reference Method 2 during the RATA. However, during the 9-month 
period, the flow monitor had consistently passed its daily calibration 
error tests (see Docket A-97-35, Item II-B-11). During a State 
inspection of a third utility, the inspector observed a consistent 20.0 
to 30.0 percent difference between the hourly flow rates measured by 
the primary and redundant backup flow monitors even though both 
monitors had been passing their daily calibration error tests. In this 
instance, the primary flow monitor was being used for data reporting 
and was reading higher than the redundant backup monitor; therefore, it 
is unlikely that emissions were being under-reported. Had the primary 
monitor malfunctioned and the redundant backup been used, however, 
emissions would have been significantly under-reported (see Docket A-
97-35, Item II-B-10).
Discussion of Proposed Changes
    In view of the apparent shortcomings of the flow monitor daily 
calibration error test, EPA proposes to add a new flow monitor quality 
assurance test, the ``flow-to-load test,'' to part 75. The flow-to-load 
test, which would be performed quarterly, is described in proposed 
sections 7.7 of Appendix A and 2.2.5 of Appendix B. The proposed 
quarterly flow-to-load test would be required beginning in the first 
quarter of the year 2000.
    The basic premise of the flow-to-load test is that a meaningful 
correlation exists between the stack gas volumetric flow rate and unit 
load. In general, for a single unit discharging to a single stack, as 
the load increases, the flow rate increases proportionally, and the 
flow rate at a given load should remain relatively constant if the same 
type of fuel is burned (see Docket A-97-35, Items II-B-9, II-D-69). 
Common stacks are somewhat less predictable, because the same combined 
unit load can be produced in a number of ways by using different 
combinations of boilers. Despite this, if the diluent gas concentration 
is properly taken into account, the flow-to-load characteristics of 
common stacks often become more normalized (see Docket A-97-35, Items 
II-B-9, II-D-73, II-D-74, II-D-76, II-D-83, II-D-84). The flow-to-load 
ratio, or a normalized ratio, can thus serve as a quantitative 
indicator of flow monitor accuracy from quarter to quarter until the 
next RATA is performed.
    The quarterly flow-to-load ratio test would be conducted as 
follows. The owner or operator would be required to determine 
Rref, a reference value of the ratio of flow rate to unit 
load, each time that a successful normal-load flow RATA is performed. 
The value of Rref would be reported in the electronic 
quarterly report required under Sec. 75.64, along with the completion 
date of the associated RATA. If two load levels (e.g., mid and high) 
are designated as normal, the owner or operator would determine a 
separate Rref value for each normal load level. The 
reference flow-to-load ratio would be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TP21MY98.059

    In the equation above, Rref is the reference value of 
the flow-to-load ratio from the most recent normal-load flow RATA; 
Qref is the average stack gas volumetric flow rate (in scfh) 
measured by the reference method during the normal-load RATA; and 
Lavg is the average unit load during the normal-load flow 
RATA. For a common stack, Lavg would be the sum of the 
operating loads of all units that discharge through the stack. For a 
unit that discharges its emissions through multiple stacks or ducts, 
Qref would be the sum of the total volumetric flowrates that 
discharge through all of the stacks (or ducts). The reference flow-to-
load ratio would be rounded off to 2 decimal places.
    As an alternative, the owner or operator could calculate a 
reference value of the gross heat rate (GHR) in lieu of 
Rref. In order to exercise this option, quality assured 
diluent gas (CO2 or O2) data would have to be 
available for each hour of the most recent normal-load flow RATA. The 
reference value of the GHR would be determined as follows:
[GRAPHIC] [TIFF OMITTED] TP21MY98.060

    In the equation above, (GHR)ref is the reference value 
of the gross heat rate at the time of the most recent normal-load flow 
RATA; (Heat Input)avg is the arithmetic average hourly heat 
input during the normal-load flow RATA; and Lavg is the 
average unit load during the normal-load flow RATA. In calculating 
(Heat Input)avg, the average volumetric flow rate measured 
by the reference method during the RATA would be used in conjunction 
with the average diluent gas concentration measured during the RATA, 
substituting these values into the applicable heat input equation in 
Appendix F.
    After establishing the reference flow-to-load or GHR value, an 
evaluation of the flow-to-load ratio or GHR would be required for each 
primary and redundant backup flow monitor on a quarterly basis. The 
owner or operator would be required to evaluate the flow-to-load ratio 
in each ``QA operating quarter'' (i.e., each quarter in which the unit 
or stack operates for at least 168 hours). At the end of each QA 
operating quarter, the owner or operator would calculate the flow-to-
load ratio for every hour during the quarter in which: (1) the unit (or 
combination of units, for a common stack) operated within 
10.0 percent of Lavg, the average load during 
the most recent normal-load flow

[[Page 28063]]

RATA; and (2) a quality assured hourly average flow rate was obtained 
with a certified flow rate monitor. The owner or operator would have 
the option of using either bias-adjusted flow rates or unadjusted flow 
rates in the hourly flow-to-load ratios, provided that all of the 
ratios were calculated the same way. EPA had originally considered 
proposing that only unadjusted flow rates should be used to calculate 
the flow-to-load ratios. However, in response to comments received from 
CEMS Utility Workgroup members, the Agency is proposing to allow either 
unadjusted or bias-adjusted flow rates to be used, on the condition 
that the acceptance criteria for the flow-to-load test would be more 
stringent if bias-adjusted flow rates are used (see Docket A-97-35, 
Item II-D-82).
    For a common stack, the ``load'' in each hourly flow-to-load ratio 
would be the sum of the hourly operating loads of all units that 
discharge through the stack. For a unit that discharges its emissions 
through multiple stacks (or for a unit that monitors total flow rate in 
multiple ducts or breechings), the ``flow'' in the flow-to-load ratio 
would be the combined hourly volumetric flow rate through all of the 
stacks (or ducts). Each hourly flow-to-load ratio would be rounded off 
to 2 decimal places.
    Alternatively, the owner or operator could calculate the hourly 
gross heat rate (GHR) values in lieu of the hourly flow-to-load ratios. 
However, an hourly GHR could only be determined for those hours within 
10.0 
 
  
for which quality assured flow rate and diluent gas (CO2 or 
O2) concentration data are available from a certified CEMS 
or reference method. The owner or operator could use either bias-
adjusted flow rates or unadjusted flow rates to determine the hourly 
GHR values.
    The calculated hourly flow-to-load ratios (or gross heat rates) 
would be analyzed at the end of the quarter. A separate data analysis 
would be performed for each primary and each redundant backup flow rate 
monitor used to record and report data during the quarter. Each 
analysis would be based on a minimum of 168 hours of data. If two RATA 
load levels are designated as normal, the analysis would be performed 
at the higher load unless fewer than 168 data points were available at 
that load, in which case, the analysis would be performed at the lower 
load. If, for a particular flow monitor, fewer than 168 hourly flow-to-
load ratios (or GHR values) were available at any normal load level, a 
flow-to-load (or GHR) evaluation would not be required for that monitor 
for that calendar quarter.
    For each flow monitor, Eh, the difference (absolute 
value) between each hourly flow-to-load ratio and Rref, 
would be expressed as a percentage of Rref (or, if the GHR 
is used, the absolute difference between each hourly GHR value and 
(GHR)ref would be expressed as a percentage of 
(GHR)ref). Then, Ef, the arithmetic average of 
all of the Eh values, would be calculated. Note that 
Rref would always be based upon the most recent normal-load 
RATA, even if that RATA was performed in the calendar quarter being 
evaluated.
    The owner or operator would be required to report the results of 
each quarterly flow-to-load (or GHR) evaluation in the electronic 
quarterly report required under Sec. 75.64. The results of a quarterly 
flow-to-load (or GHR) evaluation would be considered acceptable, and no 
further action would be required if the average absolute percentage 
difference (Ef) did not exceed the following limits:
    (i) 15.0 percent, if Lavg for the most recent normal 
load flow RATA is  50 megawatts (or  500 klb/hr 
of steam) and if unadjusted flow rates were used in the calculations;
    (ii) 10.0 percent, if Lavg for the most recent normal 
load flow RATA is  50 megawatts (or  500 klb/hr 
of steam) and if bias-adjusted flow rates were used in the 
calculations;
    (iii) 20.0 percent, if Lavg for the most recent normal 
load flow RATA is < 50 megawatts (or < 500 klb/hr of steam) and if 
unadjusted flow rates were used in the calculations;
    (iv) 15.0 percent, if Lavg for the most recent normal 
load flow RATA is < 50 megawatts (or < 500 klb/hr of steam) and if 
bias-adjusted flow rates were used in the calculations.
    If Ef exceeded the applicable limit, the owner or 
operator would have two available options: (1) perform a RATA, as 
described in proposed section 2.2.5.2 of Appendix B, unless a monitor 
malfunction is diagnosed and corrected, in which case an abbreviated 
flow-to-load test could be performed, in lieu of a RATA, in accordance 
with section 2.2.5.3 of Appendix B and discussed below; or (2) re-
examine the hourly data used for the flow-to-load or GHR analysis and 
recalculate Ef, after excluding all non-representative 
hourly flow rates. If the owner or operator were to choose option (2), 
i.e., to recalculate Ef, only the flow rates for the 
following hours would be considered non-representative and could be 
excluded from the data analysis:
    (1) Any hour in which the type of fuel combusted was different from 
the fuel burned during the most recent normal-load RATA. The type of 
fuel would be different if the fuel is in a different state of matter 
(i.e., solid, liquid, or gas) or is a different classification of coal 
(e.g., bituminous versus sub-bituminous) than the fuel burned during 
the RATA;
    (2) Any hour in which an SO2 scrubber was bypassed;
    (3) Any hour in which ``ramping'' occurred, i.e., the hourly load 
differed by more than + 15.0 percent from the load during the preceding 
hour or the subsequent hour;
    (4) If a normal-load flow RATA was performed and passed during the 
quarter being analyzed, any hour prior to completion of that RATA; and
    (5) If a problem with the accuracy of the flow monitor was 
discovered during the quarter and corrected, any hour prior to 
completion of the subsequent diagnostic test described in proposed 
section 2.2.5.3 of Appendix B, confirming that the corrective actions 
were successful.
    After identifying and excluding any non-representative hourly data 
in accordance with (1) through (5) above, the owner or operator could 
analyze the remaining data a second time. At least 168 representative 
hourly ratios or GHR values at normal load would have to remain in 
order to perform the analysis; otherwise, the flow-to-load (or GHR) 
analysis would not be required for that monitor for that calendar 
quarter.
    If, after re-analyzing the data, Ef is found to be 
within the applicable limit in (i), (ii), (iii), or (iv), above, then 
no further action would be required. However, if Ef is still 
outside the applicable limit, the monitor would be declared out-of-
control as of the first hour of the quarter following the quarter in 
which the flow-to-load test was failed. The owner or operator would 
then perform a RATA as described in proposed section 2.2.5.2 of 
Appendix B, unless, as the result of an investigation, an instrument 
malfunction is discovered and corrected as described in proposed 
section 2.2.5.1 of Appendix B.
    If a problem with the monitor is identified, all corrective actions 
(e.g., non-routine maintenance, repairs, major component replacements, 
re-linearization of the monitor, etc.) would have to be documented in 
the operation and maintenance records for the monitor. Data from the 
monitor would remain invalid until a ``probationary'' calibration error 
test of the monitor was passed following completion of all corrective 
actions, at which point data from the monitor would be assigned a 
``conditionally valid'' status. The owner or operator would then 
perform an abbreviated flow-to-load test (found in proposed section 
2.2.5.3 of Appendix B) to verify that the corrective actions were

[[Page 28064]]

effective, unless the linearity of the flow monitor was affected by the 
corrective actions (e.g., by the changing of its polynomial 
coefficients). If the flow monitor linearity was affected, the owner or 
operator would no longer have the option of performing the abbreviated 
flow-to-load test in section 2.2.5.3 of Appendix B, but would instead 
be required to perform a 3-load recertification RATA in accordance with 
the recertification test period and data validation procedures of 
Sec. 75.20(b)(3).
    The abbreviated flow-to-load test in proposed section 2.2.5.3 of 
Appendix B is based on a recertification policy developed jointly by 
EPA, several utility representatives, and one flow monitor vendor (see 
Docket A-97-35, Items II-B-1, II-D-70, II-I-9, and II-I-16). Use of the 
abbreviated flow-to-load test would not be limited to situations in 
which a quarterly flow-to-load test has been failed. Rather, the test 
could be performed after any documented repair, component replacement, 
or other corrective maintenance to a flow monitor (except for changes 
affecting the linearity of the flow monitor, such as adjusting the flow 
monitor coefficients) to demonstrate that the repair, replacement, or 
other corrective maintenance has not significantly affected the 
monitor's ability to accurately measure the stack gas volumetric flow 
rate. Data from the monitoring system would be considered invalid from 
the hour of commencement of the repair, replacement, or other 
corrective maintenance until the hour in which a ``probationary'' 
calibration error test is passed following completion of the repair, 
replacement, or other corrective maintenance and any associated 
adjustments to the monitor. The abbreviated flow-to-load test would 
have to be completed within 168 unit operating hours of the 
probationary calibration error test (or, for peaking units, within 30 
unit operating days, if that is less restrictive). Data from the 
monitor would be considered ``conditionally valid'' (as defined in 
Sec. 72.2) beginning with the hour of the probationary calibration 
error test.
    Following a flow-to-load test failure, the abbreviated flow-to-load 
test could be performed if the investigation into the cause of the test 
failure revealed a problem with the flow monitor and the problem was 
subsequently corrected without having to re-linearize the flow monitor. 
The test procedures would be as follows. The unit(s) would be operated 
in such a way as to reproduce, as closely as practicable, the exact 
conditions at the time of the most recent normal load flow RATA. To 
achieve this, the load should be held constant to within  
5.0 percent of the average load during the RATA, and the diluent gas 
(CO2 or O2) concentration should be maintained 
within  0.5 percent CO2 or O2 of the 
average diluent concentration during the RATA. For common stacks, to 
the extent possible, the same combination of units and load levels that 
were used during the RATA should be used. When the process parameters 
have been set, a minimum of 6 and a maximum of 12 consecutive hourly 
average flow rates would be recorded using the flow monitor(s) for 
which Ef was outside the applicable limit. For peaking 
units, a minimum of 3 and a maximum of 12 consecutive hourly average 
flow rates would be required. The corresponding hourly load values and, 
if applicable, the hourly diluent gas concentrations would also be 
recorded. The flow-to-load ratio or the GHR would be calculated for 
each hour in the test hour period using proposed Equation B-1 or B-1a 
in Appendix B. Then, Eh would be determined for each hourly 
flow-to-load ratio or GHR using proposed Equation B-2 in Appendix B. 
Finally, Ef , the arithmetic average of the Eh 
values, would be determined.
    The results of the abbreviated flow-to-load test would be 
considered acceptable, and no further action would be required if the 
value of Ef did not exceed the applicable limit specified in 
proposed section 2.2.5.1 of Appendix B. All conditionally valid data 
recorded by the flow monitor would then be considered quality assured, 
beginning with the hour of the probationary calibration error test that 
preceded the abbreviated flow-to-load test. However, if Ef 
was found to be above the applicable limit, all conditionally valid 
data recorded by the flow monitor would be considered invalid back to 
the hour of the probationary calibration error test that preceded the 
abbreviated flow-to-load test, and a single-load RATA would be 
required, in accordance with proposed section 2.2.5.2 of Appendix B.
    When a single-load RATA is performed because the owner or operator 
is unable to reconcile a quarterly flow-to-load test failure, either by 
excluding non-representative hours and recalculating Ef or 
by passing the abbreviated flow-to-load test after performing component 
replacement or other corrective maintenance on the flow monitor, then 
data from the monitor would remain invalid until the hour of successful 
completion of the single-load RATA.
Rationale
    EPA believes that the proposed methodology for the quarterly flow-
to-load test is fundamentally sound. It has been developed through a 
series of teleconferences and face-to-face meetings between EPA, 
members of the regulated community, and State and local agency 
personnel (see Docket A-97-35, Items II-D-77, II-D-80, II-D-81, II-D-
82, II-D-85, II-E-23, II-E-24, II-E-25, II-E-26, and II-E-28). In 
addition, some provisions of the flow-to-load test were revised 
following pre-proposal comment. Specifically, the proposal reflects, in 
section 2.2.5.1 (b) of Appendix B to part 75, a commenter's request 
that if a quarterly flow-to-load test is failed and the monitor 
malfunction is discovered and corrected (without the need to 
relinearize the monitor), the correction could be verified using the 
abbreviated flow-to-load test in lieu of performing a single load RATA 
(see Docket A-97-35, Item II-D-42).
    The proposed tolerance limits set forth in paragraphs (i), (ii), 
(iii), and (iv) of section 2.2.5 of Appendix B are believed to be both 
reasonable and achievable. When these tolerance limits are met, it 
provides a strong indication that the flow monitor is still accurate to 
within 10.0 percent of the reference method baseline established during 
the last normal-load flow RATA and would, therefore, appear to be in 
control with respect to the relative accuracy requirements of part 75. 
An extra tolerance of 5.0 percent has been incorporated into the limits 
to account for imprecision in the flow-to-load methodology. An extra 
5.0 percent tolerance has also been added for smaller units (i.e., 
normal load less than 50 megawatts or 500 klb/hr of steam), because the 
flow-to-load ratio or GHR for such units is very sensitive to small 
variations in load (see Docket A-97-35, Item II-B-7).
    To test the viability of the proposed tolerance limits, EPA 
analyzed quarterly flow rate and load data from the third quarter of 
1996 for 21 units and stacks, including 9 single units, 11 common 
stacks, and 1 multiple-stack unit (see Docket A-97-35, Items II-A-1, 
II-A-2, II-A-3). The units chosen for this analysis were selected as a 
representative sample of units that would be affected by this QA test 
requirement and included various operational circumstances (e.g., 
baseloaded and peaking units, single fuel units, and units that burn 
multiple fuels). The flow-to-load test was applied to each unit or 
stack in the manner described above, except that no hours within 
 10.0 percent of Lavg were excluded from the 
data analysis. The data from these same units plus one additional 
multiple-stack unit were

[[Page 28065]]

analyzed a second time, with each flow-to-load ratio being multiplied 
by the diluent gas concentration. This is similar, but not identical, 
to calculating the GHR. Once again, no hours within  10.0 
percent of Lavg were excluded. In both analyses, unadjusted 
flow rates were used in the ratios. The results of the two data 
analyses were nearly the same. Only one failure of the quarterly flow-
to-load test was observed in each analysis (i.e., the failure rate was 
< 5.0 percent). The average value of Ef was 6.1 percent for 
the analysis without the diluent gas corrections and 6.4 percent for 
the analysis with the diluent gas corrections. A few units and stacks 
had a much lower Ef value when the diluent correction was 
applied, but in most cases, the diluent correction had relatively 
little effect. These results suggest that the flow-to-load test can 
provide EPA with the necessary assurance that flow monitors continue to 
generate accurate data from one RATA to the next. The results also 
indicate that the test should be relatively easy to pass if flow 
monitors are properly maintained and operated.
    Because of the added quality assurance that would be provided by 
performing the flow-to-load or GHR test each quarter, EPA has 
reconsidered the scope of the other quality assurance tests for flow 
monitors. In today's proposed rule, the Agency is proposing to reduce 
the annual 3-load flow RATA requirement to a 2-load RATA and to reduce 
the frequency of 3-load RATAs to once every five years (and whenever a 
flow monitor is re-linearized). In addition, single-load flow RATA 
testing would be allowed in lieu of the annual 2-load test if the 
facility could demonstrate that a unit has operated at a single load 
level for at least 85.0 percent of the time in the four ``QA operating 
quarters'' prior to the scheduled RATA. (See Section N.2 of this 
preamble, below, for further discussion.) The Agency believes that, 
taken together, these proposed changes will reduce the cost and burden 
of quality assurance testing for flow monitors, while ensuring high 
data quality. The proposed reduction in the amount of required RATA 
testing is considered feasible because of the increased quality 
assurance provided by the quarterly flow-to-load test. EPA requests 
comment on the proposed revisions to flow monitor quality assurance 
requirements.

N. RATA and Bias Test Requirements

Background
    Section 6.5 of Appendix A to the January 11, 1993 rule, as amended 
on May 17, 1995 and November 20, 1996, requires relative accuracy test 
audits of all primary and redundant backup SO2, 
NOX, CO2, and flow monitoring systems to be 
performed during the initial certification of the CEMS. A RATA consists 
of a series of 9 or more simultaneous test runs, comparing measurements 
made by the continuous monitoring system against an EPA reference test 
method. The procedures for conducting RATAs are found in section 6.5 of 
Appendix A to part 75.
    Following the initial certification of a CEMS, section 2.3 of 
Appendix B to part 75 requires that periodic RATAs of gas and flow 
monitors be performed to quality assure the data from the CEMS on an 
on-going basis. The frequency at which relative accuracy testing is 
required depends upon the results of the last RATA of a monitoring 
system. Part 75 currently requires RATAs to be performed semiannually, 
unless a monitoring system achieves a low enough relative accuracy to 
qualify for an annual test frequency. The Agency has always interpreted 
``semiannually'' to mean that the deadline for the next RATA is the end 
of the second calendar quarter following the quarter in which a RATA is 
successfully completed, and ``annually'' to mean that the next RATA is 
due by the end of the fourth calendar quarter following the quarter in 
which a RATA is successfully completed. For monitors installed on 
peaking units and bypass stacks, however, the RATA deadlines are based 
on operating quarters, not calendar quarters. That is, the next RATA is 
due either at the end of the second or fourth unit operating quarter 
(for peaking units) or bypass stack operating quarter following the 
quarter in which a RATA is successfully completed.
    For SO2, NOX, and CO2 monitors, 
the RATAs are to be conducted while the unit is operating at normal 
load and while combusting the fuel that is normal for the unit. Flow 
monitor RATAs are to be conducted at three different loads, evenly 
spaced over the operating range of the unit. When a flow monitor is on 
a semiannual RATA frequency, a normal-load RATA rather than a 3-load 
RATA may be conducted to satisfy the semiannual test requirement, but a 
3-load RATA is still required annually. Note that for flow monitors 
installed on peaking units and bypass stacks, 3-level flow RATAs are 
not required; RATAs are performed only at the normal load.
    For SO2, NOX, and flow monitoring systems, 
section 7.6 of Appendix A requires that each time a RATA is 
successfully completed, a bias test be performed to determine if the 
system has a low measurement bias. If a monitoring system fails the 
bias test, a ``bias adjustment factor'' (BAF) must be applied to all 
subsequent emission data reported from that monitoring system. For 3-
load flow RATAs, the bias test is done at the normal load. If a flow 
monitor fails the normal-load bias test, then a BAF must be calculated 
at each of the three load levels, and the highest of the three BAFs is 
applied to all flow data reported from the monitor.
    When a RATA is due, section 2.3.1 in Appendix B of the rule allows 
the owner or operator two attempts to achieve an annual RATA frequency 
and/or a favorable BAF. If a second attempt is made, the RATA frequency 
and BAF obtained in the second RATA supersede the results of the first 
RATA. Once the RATA frequency has been established as semiannual or 
annual, section 2.3.1 of Appendix B specifies that (to the extent 
practicable) the next RATA of the CEMS may not be done until at least 
four months have elapsed.
    Finally, Sec. 75.21(a)(6) of the November 20, 1996 rule provides an 
exemption from the RATA requirements of part 75 for SO2 
monitors installed on units that burn only natural gas or fuel with a 
sulfur content no greater than natural gas. For units that burn both 
gas and higher-sulfur fuel, such as oil, as primary or backup fuels, 
Sec. 75.21(a)(5) requires that the RATA of the SO2 monitor 
be done when the higher-sulfur fuel is burned. Section 75.21(a)(7) 
further states that calendar quarters in which only fuel with a sulfur 
content no greater than natural gas is burned are to be excluded in 
determining the deadline for the next SO2 monitor RATA.
    Two utility groups, UARG and the Class of '85, have requested that 
EPA consider revising the RATA requirements of part 75 to make them 
more flexible, easier with which to comply, and less costly. Some of 
the possible changes suggested by these groups are as follows: (1) 
reduce the frequency of required RATAs; (2) determine RATA deadlines 
based on the amount of unit operation since the last RATA, rather than 
the number of calendar quarters that have elapsed; (3) remove the 
requirement to achieve a more stringent relative accuracy standard in 
order to obtain an annual RATA frequency; (4) except for initial 
certification, allow flow RATAs to be done at a single load; (5) allow 
single-point sampling during gas RATAs; and (6) allow a grace period in 
which to complete a RATA whenever a deadline is not met (see Docket A-
97-35, items II-D-20, II-D-30, II-D-65, II-E-13, II-E-14).

[[Page 28066]]

Discussion of Proposed Changes
    EPA is proposing revisions to the RATA requirements of part 75 
based upon experience gained through implementation of the rule and in 
light of the recommendations made by the utility groups. Today's 
rulemaking sets forth the proposed changes, which are intended to make 
the RATA requirements less burdensome without sacrificing data quality.
1. RATA Frequency
    EPA does not propose to revise the basic semiannual and annual RATA 
requirements of part 75 or the incentive system by which to obtain an 
annual RATA frequency (i.e., to obtain the reduced frequency, a better 
percentage relative accuracy is required). Instead, the Agency proposes 
to re-define the terms ``semiannual RATA frequency'' and ``annual RATA 
frequency,'' and to change the method by which RATA deadlines are 
determined.
    Today's rule proposes to amend section 2.3 of Appendix B so that 
the deadline for the next RATA is determined on the basis of ``quality 
assurance operating quarters,'' rather than calendar quarters. This 
change would apply, with few exceptions, to all primary and redundant 
backup monitoring systems, including monitors installed on peaking 
units and bypass stacks. A ``QA operating quarter'' would be defined as 
a calendar quarter in which a unit operates for at least 168 hours or, 
for common-stacks and bypass stacks, a quarter in which flue gases 
discharge through the stack for at least 168 hours.
    Any calendar quarter that does not qualify as a QA operating 
quarter would be excluded in determining the deadline for the next 
RATA. EPA therefore proposes to re-define the term ``semiannual RATA 
frequency'' to mean that the next RATA is due at the end of the second 
QA operating quarter following the quarter in which a RATA is 
successfully completed. Similarly, ``annual RATA frequency'' would mean 
that the next RATA is due at the end of the fourth QA operating quarter 
following the quarter in which a RATA is successfully completed.
    The QA operating quarter methodology has been proposed principally 
for the benefit of cycling and peaking units to make the part 75 RATA 
requirements easier to meet. The proposed methodology will not greatly 
affect base-loaded units, since they seldom operate for less than 168 
hours in a quarter. For base-loaded units, the QA operating quarter 
method is, in most instances, equivalent to the familiar calendar 
quarter scheme for determining RATA deadlines. Note, however, that on 
occasion a base-loaded unit may obtain an extended RATA deadline by the 
QA operating quarter methodology, e.g., when the unit goes into an 
extended outage (planned or forced) and experiences one or more 
quarters in which the unit operates for less than 168 hours.
    Although the QA operating quarter method allows RATA deadlines to 
be extended by the exclusion of quarters in which the unit(s) operate 
for less than 168 hours, such exclusion of calendar quarters is not 
without limit. Section 2.3.1.1 of Appendix B proposes to allow a 
maximum of eight consecutive calendar quarters to elapse following the 
quarter in which the last RATA was performed. A RATA would either have 
to be performed by the end of the eighth consecutive elapsed calendar 
quarter since the last RATA or within a 720 unit operating hour ``grace 
period'' following the end of the eighth consecutive elapsed quarter. 
Failure to complete a RATA within the grace period would cause data 
from the monitoring system to become invalid from the hour of 
expiration of the grace period until the hour of completion of a 
successful RATA.
    Although the proposed QA operating quarter methodology would serve 
as the basis for determining the RATA deadline for most routine quality 
assurance RATAs, there are five notable instances in the current rule 
or in today's proposal where the RATA deadline is either not determined 
solely on that basis or is determined entirely on another basis. The 
first instance is for a unit that burns both natural gas (or fuel with 
equivalent total sulfur content) and other higher-sulfur fuels as 
primary or backup fuels and that uses an SO2 monitor to 
account for SO2 mass emissions. Section 75.21(a)(7) of the 
current part 75 (redesignated as Sec. 75.21(a)(9) in today's proposal) 
specifies that irrespective of the number of hours of unit operation in 
the quarter, any calendar quarter in which natural gas (or fuel with a 
total sulfur content no greater than the total sulfur content of 
natural gas) is the only fuel combusted in the unit (i.e., a ``gas-
only'' quarter) is to be excluded in determining the deadline for the 
next RATA of the SO2 monitoring system. Section 75.21(a)(5) 
of the current rule further states that for such units, the RATA of an 
SO2 monitoring system is to be performed only when the 
higher-sulfur fuel is being combusted. Second, as discussed in section 
III.N.6 of this preamble, Sec. 75.21(a)(7) of today's proposed rule 
would conditionally exempt from SO2 RATA requirements any 
unit certified by the designated representative to burn fuel(s) with a 
sulfur content greater than natural gas only as emergency backup fuel 
or for short-term testing, provided that the annual usage of the 
higher-sulfur fuel(s) is kept below 480 hours. However if, during any 
quarter, the annual usage of the higher-sulfur fuel exceeded 480 hours, 
an SO2 RATA would be required either in that quarter or 
during a subsequent grace period. Thus, for RATAs of SO2 
monitoring systems, it is evident that the number of unit operating 
hours in a calendar quarter is not the only consideration that 
determines the deadline for the next RATA; the total sulfur content of 
the fuel being combusted must also be considered. Third, as discussed 
in section III.O.6 of this preamble, for certain non-redundant backup 
monitoring systems, Sec. 75.20(d) of today's proposal would require a 
periodic RATA every eight calendar quarters (rather than QA operating 
quarters). Fourth, as discussed in section III.N.2 of this preamble, 
under section 2.3.1.3 of Appendix B in today's proposal, 3-level flow 
RATAs would have to be performed once in every period of five 
consecutive calendar years (e.g., prior to permit renewal) and whenever 
a flow monitor is re-linearized. Fifth, as discussed in section III.O.4 
of this preamble, for recertification RATAs, which are not regularly 
scheduled tests, but are done on an ``as-required'' basis, 
Sec. 75.20(b)(3) of today's proposal specifies that the deadline for 
completing such RATAs would be 720 unit operating hours after the start 
of the recertification test period.
2. RATA Load Levels
    Today's proposed rule would more clearly define the load levels at 
which RATAs are done in order to provide greater consistency in the way 
that RATAs are performed. The current provisions of part 75 are neither 
sufficiently standardized nor clear in defining the appropriate RATA 
load levels, particularly for flow RATAs. For example, section 6.5.2 of 
Appendix A specifies that the ``low'' load audit point for a 3-level 
flow RATA can be located anywhere from the minimum safe, stable load to 
50.0 percent of the maximum load. Also, there is no minimum required 
load separation between the audit points at adjacent load levels. If 
adjacent audit points are too close together, a 3-level flow evaluation 
loses its significance. Finally, while the current rule requires gas 
and flow RATAs to be conducted at normal

[[Page 28067]]

load, no definition of normal load is provided. It could be inferred 
from the current section 6.5.2 of Appendix A that the ``mid'' load 
level is considered normal because it requires the 3-load RATA to be 
done at a frequently used low load, a frequently used high operating 
load, and a normal load. However, experience in implementing the 
program has shown that for many units, the high load level is 
considered normal by the facility. For a few units, low load is 
considered normal, and for still others, the normal load can depend 
upon the time of day or the season of the year.
    Proposed section 6.5.2.1 of Appendix A would therefore require the 
owner or operator first to define the ``range of operation'' for each 
unit or common stack equipped with hardware CEMS. The range of 
operation would extend from the minimum safe, stable load to the 
``maximum sustainable load,'' which is the higher of: (a) the nameplate 
capacity of the unit (less any physical or regulatory deratings), or 
(b) the highest sustainable load, based on at least four quarters of 
representative historical data. For a common stack, the lower boundary 
of the range of operation would be the lowest minimum safe, stable load 
for any of the individual units using the stack. The upper boundary of 
the range would be obtained by adding together the maximum sustainable 
loads of all units using the stack, or if that combined load is 
unattainable in practice, by using the highest sustainable combined 
load based on at least four quarters of representative historical data. 
Three load levels would then be defined in terms of the range of 
operation. The ``low'' level would be the lower 30.0 percent of the 
range; the ``mid'' level would be the central portion (30.0 percent to 
60.0 percent) of the range; and the ``high'' level would be 60.0 
percent to 100.0 percent of the range. Proposed section 6.5.2 of 
Appendix A would specify that for multi-level flow RATAs, the audit 
points at adjacent load levels (e.g., low and mid, or mid and high) 
must be separated by no less than 25.0 percent of the range of 
operation. The owner or operator would be required to report the upper 
and lower boundaries of the range of operation in the electronic 
quarterly report required under Sec. 75.64.
    Section 6.5.2.1 of Appendix A in today's proposal would further 
require the owner or operator to determine, for each unit or common 
stack on which CEMs are installed (except for peaking units), the two 
load levels (low, mid, or high) that are the most frequently used. The 
two-fold purpose of this determination, which would be required, at a 
minimum, annually (just prior to the annual quality assurance RATAs and 
in the same calendar quarter as the RATAs), would be to identify the 
normal load level(s) and to identify the two load levels that are the 
most appropriate for annual 2-level flow monitor audits and for flow 
monitor bias adjustment factor calculations. To make the determination, 
the owner or operator would construct an historical load frequency 
distribution (e.g., histogram), depicting the relative number of 
operating hours at each of the three load levels, low, mid, and high. 
The frequency distribution would be based upon all available data from 
the four most recent QA operating quarters, as defined in proposed 
section 2.3.1.1 of Appendix B. The load frequency distribution would be 
used to determine the percentage of the time (to the nearest 0.1 
percent) that each load level (low, mid, and high) has been used in 
recent history and thereby to identify the two most frequently used 
load levels. A summary of the data used for these determinations would 
be maintained on-site in a format suitable for inspection, and the 
results of the determinations would be included in the electronic 
quarterly report under Sec. 75.64. The proposed revisions discussed in 
this paragraph would become effective as of January 1, 2000.
    The owner or operator would be required under proposed section 
6.5.2.1 of Appendix A to designate the most frequently used load level 
(low, mid, or high) as the normal load level for each unit or common 
stack (except for peaking units). The owner or operator would also have 
the option of designating the second most frequently used load level as 
an additional normal load level. Today's proposal would, therefore, not 
limit normal load to a single load level. This way of defining normal 
load is particularly appropriate for units that operate on a diurnal 
cycle and units that operate at distinctly different load levels during 
different seasons of the year due to ambient conditions, electrical 
demand, etc. EPA believes that the added flexibility in the definition 
of normal load (i.e., not confining it to a single load level) will 
allow the normal-load RATA requirements of part 75 to be more easily 
met. The owner or operator would be required to identify the selected 
normal load level(s) in the electronic quarterly report required under 
Sec. 75.64. For peaking units, the entire range of operation would, for 
simplicity, be considered normal.
    Revisions to section 2.3.1.3 of Appendix B are proposed in today's 
rule, requiring the routine quality assurance RATAs of flow monitors to 
be done as follows. For flow monitors installed on peaking units and 
bypass stacks, no changes are proposed; the requirement to perform only 
single-load flow RATAs at normal load would be retained. For all other 
flow monitors, the routine semiannual and annual RATAs would be done at 
2 loads (i.e., the two most frequently used load levels, as identified 
in section 6.5.2.1 of Appendix A), with two exceptions: (1) the 2-load 
flow RATA could be performed alternately with a single-load flow RATA 
at the most frequently used (normal) load level, if the flow monitor is 
on a semiannual RATA frequency; and (2) a single-load flow RATA at the 
most frequently used load level could be performed in lieu of the 2-
load RATA if, for the four QA operating quarters prior to the quarter 
in which the RATA is conducted, the historical load frequency 
distribution constructed under section 6.5.2.1 of Appendix A shows that 
the unit has operated at the most frequently used load level for 
 85.0 percent of the time. For all units, the requirement to 
perform periodic 3-load flow RATAs would be retained, but the frequency 
would be changed from annual to once every five calendar years. A 3-
load RATA would also be required whenever a flow monitor is re-
linearized (i.e., when its polynomial coefficients are changed). EPA is 
proposing to reduce the required frequency of 3-load RATAs and to allow 
limited use of single-load flow RATA testing principally because of the 
added assurance of data quality that will be provided by the proposed 
quarterly flow-to-load test.
3. Flow Monitor Bias Adjustment Factors
    Today's rulemaking proposes to change the method of determining the 
bias adjustment factor for multiple-load flow RATAs. For 2-load RATAs 
(which would be done at the two most frequently used load levels as 
identified in proposed section 6.5.2.1 of Appendix A), the bias test 
would be done at the load level (or levels) designated as normal. If 
the monitor were to fail the bias test at any load level designated as 
normal, a bias adjustment factor (BAF) would be calculated at both load 
levels, and the higher of the two BAFs would then be applied to the 
subsequent flow data. For 3-load RATAs, the bias test would be required 
at each load level designated as normal under proposed section 6.5.2.1 
of Appendix A. If the bias test were failed at any load level 
designated as normal, BAFs would be calculated only at the two most 
frequently used load levels (not all three

[[Page 28068]]

levels), and the higher of the two BAFs would be applied to subsequent 
flow data. Thus, for all multiple-load flow RATAs, the appropriate BAF 
would be determined in the same way. For 3-load RATAs, this methodology 
for determining the BAF when the normal-load bias test is failed 
differs from the current rule, which requires the highest BAF from any 
of the three levels to be applied to subsequent data. Experience gained 
in the first few years of program implementation has shown that in many 
instances, the highest BAF has been from a load level that is seldom 
used (generally the low load level), which can result in an 
unrepresentatively high BAF being applied to the normal-load flow rate 
data.
4. Number of RATA Attempts
    Section 2.3.1.4 of Appendix B to today's proposed rule would remove 
the restriction limiting to two the number of RATA attempts that may be 
done to achieve an annual RATA frequency. In addition, the requirement 
that successive RATAs be conducted no less than 4 months apart would be 
removed from section 2.3.1 of Appendix B. The proposed rule would 
conditionally allow the owner or operator to perform as many RATAs as 
are necessary to achieve a better relative accuracy percentage or a 
more favorable bias adjustment factor, the condition being that the 
data validation procedures for RATAs in proposed section 2.3.2 of 
Appendix B would have to be followed (these procedures are discussed in 
detail in Section II.O of this preamble, ``CEM Data Validation''). The 
Agency believes that this extra flexibility will provide an incentive 
for owners or operators to optimize CEMS performance and to eliminate 
bias from their monitoring systems and to reduce the frequency of the 
required RATAs.
5. Concurrent SO2 and Flow RATAs
    Today's proposed rulemaking would delete the requirement for 
concurrent SO2 and flow RATA testing from Sec. 6.5 of 
Appendix A. This requirement was included in the January 11, 1993 rule 
in order to generate a data base from which EPA could determine the 
appropriateness of setting a combined flow rate-SO2 system 
relative accuracy specification. Section 3.3.5 of Appendix A was 
reserved for this future standard, which, if promulgated, would have 
become effective on January 1, 2000. After three years of program 
implementation, data collection, and evaluation, however, the Agency 
believes it is not appropriate or necessary to propose a combined flow 
rate-SO2 system relative accuracy standard. Instead, EPA 
believes it would be more appropriate to retain the individual relative 
accuracy specifications for the SO2 and flow monitors. 
Because the historical relative accuracy percentages of the individual 
component monitors have proven to be so low (i.e., average relative 
accuracy less than 5.0 percent for the period from the first quarter of 
1995 through the second quarter of 1996), the Agency believes that it 
is not necessary to promulgate the combined standard (see Docket A-97-
35, Item II-I-27). Data analysis from an EPA study (see Docket A-97-35, 
Item II-I-14) indicates that quality assuring the individual component 
monitors to 7.5 percent relative accuracy (the RA value needed to 
qualify for an annual RATA frequency) effectively ensures that a 
combined flow rate-SO2 standard of 10.0 to 15.0 percent 
relative accuracy will be consistently achieved. That same study also 
indicates that meeting a combined flow rate-SO2 standard of 
10.0 percent does not necessarily ensure that the individual component 
monitor relative accuracies will be  10.0 percent. In view 
of this and given that flow monitors are also used to calculate heat 
input and CO2 mass emissions, the Agency believes it is 
appropriate to maintain individual relative accuracy standards for the 
flow monitor and SO2 monitor. EPA solicits comment on its 
proposed treatment of this issue.
6. SO2 RATA Exemptions and Reduced Requirements
    Today's proposed rulemaking would clarify the RATA requirements for 
units that burn principally natural gas and other very low-sulfur 
fuels. In Sec. 75.21(a)(6) of the November 20, 1996 rule, an exemption 
from SO2 RATA requirements was provided for units that have 
SO2 monitors and exclusively burn natural gas (or fuels with 
a sulfur content no greater than natural gas). Today's proposed rule 
would clarify this exemption from SO2 RATAs by interpreting 
the term ``fuel with a total sulfur content no greater than the total 
sulfur content of natural gas'' to mean any type of fuel that has a 
total sulfur content of less than or equal to 0.05 percent sulfur by 
weight. The rationale for this is as follows. In order to meet the 
definition of natural gas in Sec. 72.2, the total sulfur content of the 
gas cannot exceed 20 grains/100 scf. When this sulfur content is 
converted to a weight percentage, it comes out slightly higher than 
0.05 percent sulfur by weight (see Docket A-97-35, Item II-B-14). 
Consequently, for a unit that has an SO2 monitor and for 
which the designated representative certifies that the unit burns only 
fuels (whether solid, liquid, or gaseous) with a total sulfur content 
of > 0.05 percent sulfur by weight, the SO2 monitor would be 
exempted from the part 75 RATA requirements. The Agency takes comment 
on this approach and on whether 0.05 percent sulfur by weight is an 
appropriate applicability threshold for fuels other than natural gas.
    Finally, Sec. 75.21(a)(7) of today's rule proposes reduced RATA 
requirements for units with SO2 monitors for which the 
designated representative certifies that the units burn fuel(s) with a 
total sulfur content greater than the total sulfur content of natural 
gas (e.g., distillate oil) only as emergency backup fuel(s) and/or for 
short-term testing. For such units, RATA testing of the SO2 
monitor would only be required if fuel with a total sulfur content 
greater than the total sulfur content of natural gas (i.e., > 0.05 
percent sulfur by weight) is combusted for more than 480 hours in a 
calendar year. If the higher-sulfur fuel usage were to exceed 480 hours 
in a particular year, then an SO2 RATA, conducted while 
burning the higher-sulfur fuel, would be required either by the end of 
the quarter in which the exceedance occurred or within a 720 unit 
operating hour grace period following that calendar quarter. In this 
instance, if the grace period were used, proposed section 2.3.3 in 
Appendix B would specify that it would begin with the first unit 
operating hour in which the higher-sulfur fuel is combusted in the 
unit, following the calendar quarter in which the annual usage of the 
higher-sulfur fuel exceeded 480 hours. The 480-hour criterion for 
maintaining an SO2 RATA exemption is consistent with many 
state and local air permits which contain a similar exemption from 
particulate emission testing for gas-fired units that burn oil for only 
400 to 500 hours per year (see Docket A-97-35, Item II-E-23). EPA 
believes that these provisions would effectively eliminate the need to 
start up a unit and/or to burn an infrequently used, uneconomical, and 
higher-emitting fuel solely for the purpose of performing a RATA of the 
SO2 monitor.
7. QA Provisions for SO2 Monitors, for Natural Gas Firing or 
Equivalent
    In Sec. 75.11(e) of the November 20, 1996 revisions to part 75, 
three SO2 compliance options were promulgated for units with 
SO2 CEMS during hours in which only natural gas (or gaseous 
fuel with a total sulfur content no greater than the total sulfur 
content of natural gas) is burned. One of the compliance options was to 
allow the use of an SO2 monitoring system, subject to

[[Page 28069]]

certain restrictions and quality assurance provisions. The restrictions 
and QA provisions, which are found at Secs. 75.11(e)(3)(i) through 
(iv), are as follows: (i) a calibration gas with a concentration of 0.0 
percent of span must be used for daily calibration error tests of the 
CEMS; (ii) the response of the monitoring system to the 0.0 percent 
calibration gas must be adjusted to read exactly 0.0 ppm each time that 
a daily calibration error test is passed; (iii) any hourly average of 
less than 2.0 ppm recorded by the SO2 monitor while fuel is 
being combusted in the unit(s) (including zero and negative averages) 
must be reported as a default value of 2.0 ppm; and (iv) if a unit 
combusts only natural gas (or gaseous fuel with a total sulfur content 
no greater than the total sulfur content of natural gas) and never 
combusts any other type of fuel, the SO2 monitor span must 
be set to a value not exceeding 200.0 ppm. Compliance with conditions 
(i) through (iv) is required by January 1, 1999, except that conditions 
(i) and (ii) are always optional for units that combust natural gas 
only during unit startup.
    The provisions in Secs. 75.11(e)(3)(i) through (iv), as presently 
codified, apply only to the combustion of gaseous fuel with a total 
sulfur content no greater than the total sulfur content of natural gas. 
However, as noted above (under ``SO2 RATA Exemptions and 
Reduced Requirements''), today's proposed rulemaking would add an 
interpretation of the term ``fuel with a total sulfur content no 
greater than the total sulfur content of natural gas'' to 
Sec. 75.21(a)(6). The term would include any fuel (whether solid, 
liquid, or gaseous) with a total sulfur content of  0.05 
percent by weight. EPA believes that it is appropriate to apply the 
quality assurance and reporting provisions in Secs. 75.11(e)(3)(i) 
through (iv) to the combustion of all fuels with a total sulfur content 
 0.05 percent by weight. Therefore, in today's proposed 
rule, a new section, Sec. 75.21(a)(8) would be added, extending the QA 
provisions of Secs. 75.11(e)(3)(i) through (iv) to the combustion of 
all types of fuels with a total sulfur content no greater than the 
total sulfur content of natural gas. The new requirements would become 
effective on January 1, 2000.
    Note that EPA has reconsidered one of the four QA provisions for 
the use of an SO2 monitor during natural gas (or fuel with 
equivalent total sulfur content) combustion in Secs. 75.11(e)(3)(i) 
through (iv). Specifically, the Agency believes that 
Sec. 75.11(e)(3)(ii), which requires a daily adjustment of the 
monitor's calibration to read exactly 0.0 ppm, may be too stringent 
because in practice it can be very difficult to attain a reading of 
exactly 0.0 ppm with a zero-level calibration gas, particularly when 
manual calibration adjustments are made. Therefore, today's rulemaking 
proposes to revise Sec. 75.11(e)(3)(ii) as follows. Rather than 
requiring a daily adjustment of the SO2 monitor's 
calibration, an adjustment would only be required when the ``as-found'' 
response of the monitor to the zero gas during a daily calibration 
error test exceeded the performance specification of the instrument 
(i.e., 2.5 percent of span). And instead of requiring the 
calibration to be adjusted to exactly 0.0 ppm, the procedures for 
routine calibration adjustments in proposed section 2.1.3 of Appendix B 
would be followed, to bring the ``as-left'' response of the instrument 
(i.e., the response during the additional calibration error test 
required by proposed section 2.1.3 of Appendix B) ``as close as 
practicable'' to the true value of the zero gas (0.0 ppm).
    The Agency solicits comment on the proposed approach for QA 
provisions for SO2 CEMS for gas-firing or equivalent.
8. General RATA Test Procedures
    Under today's proposal, sections 6.5, 6.5.1, and 6.5.2 of Appendix 
A, which describe the general requirements for RATAs, would be 
extensively revised. Some of the proposed changes are simply 
structural, but others are substantive. For instance, as previously 
discussed above under ``Concurrent SO2 and Flow RATAs,'' the 
requirement to perform concurrent SO2 and flow RATAs would 
be deleted from the regulation. Further, section 6.5 would now 
recognize that more than one type of fuel and more than one monitor 
range may be considered normal for a particular unit. Also, the 
requirement to complete each RATA within 7 consecutive calendar days 
would be modified to require that the RATA be completed within 168 unit 
operating hours (for single-load flow RATAs and, to the extent 
practicable, for 2-load and 3-load flow RATAs). However, for the 
multiple-load flow RATAs, up to 720 unit operating hours would be 
allowed, if necessary, to complete the testing. This is consistent with 
Agency guidance published in March, 1995, Policy Question 8.15 of the 
Acid Rain Policy Manual, which discusses allowing up to 30 calendar 
days to complete all three levels of a 3-load flow RATA (see Docket A-
97-35, Item II-I-9). Even though the policy says the RATAs at the 
individual load levels should be completed within 7 days, thirty days 
are acceptable to complete the 3-load RATA in order to account for the 
possibility that the unit might shut down in between levels of the RATA 
or that certain load levels may be difficult to attain and to hold. 
Today's proposal would allow 720 unit operating hours (irrespective of 
the number of calendar days) to complete a multiple-load flow RATA. EPA 
believes that this proposed requirement provides greater flexibility 
than currently allowed.
    Sections 6.5.1 and 6.5.2 of Appendix A would be re-titled ``Gas 
Monitoring Systems (Special Considerations)'' and ``Flow Monitor RATAs 
(Special Considerations),'' respectively. Proposed section 6.5.1 
contains a recommendation that, for initial monitor certifications, the 
RATA not be commenced until all of the other certification tests have 
been completed. Section 6.5.2 would be amended, as previously discussed 
under ``Flow RATA Load Levels.'' The definition of normal load would be 
revised and the number of loads and the load levels at which flow RATAs 
are to be performed would be more clearly defined.
    Today's rule proposes changes to section 6.5.6 of Appendix A, which 
pertains to RATA traverse point selection. Proposed section 6.5.6 would 
allow the following alternative reference method measurement point 
locations. For all moisture determinations, a single reference method 
point, located at least 1.0 meter from the stack wall, could be used. 
For gas RATAs, the owner or operator would have four options: (1) at 
any location (including locations where stratification is expected), a 
minimum of six traverse points along a diameter, located in accordance 
with Method 1 in Appendix A to part 60, could be used; (2) at locations 
where stratification is not expected and section 3.2 of Performance 
Specification No. 2 (``PS No. 2'') in Appendix B to part 60 allows the 
use of a short reference method measurement line (with three points 
located at 0.4, 1.0, and 2.0 meters from the stack wall), the owner or 
operator could use an alternative 3-point measurement line, locating 
the three points 4.4 percent, 14.6 percent and 29.6 percent of the way 
across the stack, in accordance with Method 1 in Appendix A to part 60; 
(3) at locations where stratification is expected (i.e., after a wet 
scrubber or when dissimilar gas streams are combined), the short 
measurement line from section 3.2 of PS No. 2 (or the alternative line 
described in option (2) above) could be used in lieu of the ``long'' 
measurement line prescribed in section 3.2 of PS No. 2, provided that a 
stratification test is performed prior to each RATA at the location and 
certain acceptance criteria

[[Page 28070]]

are met; and (4) a single reference method measurement point, located 
no less than 1.0 meter from the stack wall, could be used at any test 
location if a stratification test is performed prior to each RATA at 
the location and certain acceptance criteria are met. EPA's Office of 
Air Quality Planning and Standards (OAQPS) has endorsed the use of the 
Method 1 traverse points as an alternative to the points prescribed by 
PS No. 2 (see Docket A-97-35, Item II-C-22).
    Regarding option (3) above, one utility and one stack testing firm 
have requested that EPA allow the short measurement line to be used at 
scrubbed unit stacks, citing logistical difficulties and safety 
concerns associated with using the long measurement line prescribed by 
PS No. 2 for sampling locations following wet scrubbers (see Docket A-
97-35, Items II-D-66, II-D-78). Both parties appeared willing to 
perform stratification testing to demonstrate that the gas streams are 
not significantly stratified. EPA responded to these requests by 
issuing policy guidance which discusses allowing the short measurement 
line to be used for scrubbed units, provided that stratification test 
results show the stratification at the sampling location to be minimal 
(see Docket A-97-35, Item II-I-9, Policy Manual, Question 8.25). 
Regarding single-point RATA testing (option (4), above), which utility 
groups asked EPA to consider, today's proposed rule would allow it on 
the condition that a stratification test at the sampling location 
demonstrates stratification to be essentially absent.
    Sections 6.5.6.1 and 6.5.6.2 of Appendix A in today's proposed rule 
provide two stratification test protocols which may be used to 
demonstrate that a sampling location qualifies for the alternative RM 
measurement point locations allowed under proposed section 6.5.6 (i.e., 
options (3) and (4), above). The first stratification test protocol, in 
proposed section 6.5.6.1, is based upon technical guidance issued by 
OAQPS (see Docket A-97-35, Item II-I-3) and would consist of measuring 
the SO2, NOX, and diluent gas concentrations at a 
minimum of 12 traverse points, located in accordance with Method 1 in 
Appendix A to part 60. The gas concentration measurements would be made 
using Reference Methods 6C, 7E, and 3A in Appendix A to part 60. The 
average NOX, SO2, and CO2 (or 
O2) concentration at each of the individual traverse points 
would be determined, and the arithmetic average NOX, 
SO2, and CO2 (or O2) concentrations 
for all traverse points calculated. This 12-point test would have to be 
passed one time at the sampling location under consideration. Once the 
12-point test has been passed at the candidate sampling location, the 
second (abbreviated) stratification test protocol, in proposed section 
6.5.6.2, could be done prior to subsequent RATAs at the location in 
lieu of the 12-point test. The abbreviated test would be done either at 
3 points (located in accordance with the long measurement line in PS 
No. 2) or at 6 points along a diameter (located according to EPA Method 
1 in Appendix A to part 60).
    The acceptance criteria for the stratification test results are 
given in proposed section 6.5.6.3 of Appendix A. For each pollutant or 
diluent gas, the short 3-point reference method measurement line 
specified in section 3.2 of PS No. 2 (or the alternative 3-point line 
described in proposed section 6.5.6 of Appendix A) could be used for 
that pollutant or diluent gas in lieu of the long measurement line in 
section 3.2 of PS No. 2, if the concentration at each individual 
traverse point differed by no more than 10.0 percent from 
the arithmetic average concentration for all traverse points. The 
results would also be acceptable if the concentration at each 
individual traverse point differed by no more than 5.0 ppm 
or 0.5 percent CO2 (or O2) from the arithmetic 
average concentration for all traverse points. Further, for each 
pollutant or diluent gas, a single reference method measurement point 
located at least 1.0 meter from the stack wall could be used for that 
pollutant or diluent gas, if the concentration at each individual 
traverse point differed by no more than 5.0 percent from 
the arithmetic average concentration for all traverse points. The 
results would also be acceptable if the concentration at each 
individual traverse point differed by no more than 3.0 ppm 
or 0.3 percent CO2 (or O2) from the arithmetic 
average concentration for all traverse points. Finally, proposed 
section 6.5.6.3 would require the owner or operator to keep the results 
of all stratification tests on-site, suitable for inspection, as part 
of the supplementary RATA records required under Sec. 75.56(a)(7) and 
Sec. 75.59(a)(7).
    Today's rule also proposes to clarify the sampling strategy for 
RATAs in section 6.5.7 of Appendix A. The proposed revisions make it 
clear that for gas monitor RATAs, the minimum time per run is 21 
minutes, and all of the necessary data for each run (i.e., pollutant 
concentration measurements and, if applicable, diluent concentration 
data and moisture measurements) would have to be collected, to the 
extent practicable, within a 60-minute period. The proposed revisions 
would also require the pollutant and diluent concentration measurements 
to be made simultaneously during RATAs of SO2/diluent and 
NOX/diluent monitoring systems. For flow monitor RATAs, the 
minimum time per run would be 5 minutes. A requirement to properly 
account for flow pulsations (e.g., by sight-weighted averaging) at each 
velocity traverse point would be added, as well as a clear statement 
that successive flow RATA runs may be done as rapidly as practicable, 
with no required waiting period between runs. Proposed section 6.5.7 of 
Appendix A states that a minimum of one set of auxiliary data (moisture 
and diluent gas measurements) would have to be collected for every 
three RATA runs or for every clock hour of a flow RATA (whichever is 
less restrictive). A related change to Sec. 75.22(a)(4) is also 
proposed, which would allow the alternative moisture measurement 
techniques described in section 1.2 of Method 4 in Appendix A to part 
60 to be used for stack gas molecular weight determinations.
9. Reference Method Testing Issues
Discussion of Proposed Changes
    Currently, Sec. 75.22 specifies several reference methods 
(Reference Methods 2, 2A, 2C, or 2D) as appropriate methods for 
determining volumetric flow under part 75. The Agency is currently 
conducting a study of the accuracy of Reference Method 2 to determine 
whether changes to Method 2 or the addition of other alternatives to 
the Method are appropriate. Thus, the Agency anticipates that, in the 
future, revisions to Method 2 in part 60 may create alternatives beyond 
the specific reference methods specified in Sec. 75.22(a)(2). 
Therefore, in Sec. 75.22(a)(2), EPA proposes to add: ``or its allowable 
alternatives, except for 2B and 2E'' to Method 2 to automatically 
incorporate into part 75 anticipated future revisions to the Method 2 
requirements in Appendix A to part 60.
    Section 75.22 specifies a number of instrumental reference methods 
from Appendix A to part 60 (Reference Methods 3A, 6C, 7E, and 20) as 
appropriate test methods for conducting CEMS performance tests under 
part 75. These methods require the use of calibration gases to 
calibrate the reference analyzers. Currently, however, part 60 does not 
require that EPA protocol gas be used when performing instrumental 
reference methods. The Agency believes that protocol gas should be used 
when performing instrumental reference methods in order

[[Page 28071]]

to achieve accurate results. Therefore, proposed Sec. 75.22(c)(1) would 
state that, for purposes of part 75, instrumental reference methods 
must be performed using calibration gases as defined in section 5 of 
Appendix A to part 75.
10. Alternative Relative Accuracy Specifications and Specifications for 
Low-Emitters
    One utility group has suggested to EPA (see Docket A-97-35, Item 
II-E-13) that there is inconsistency and apparent inequity in the 
relative accuracy specifications for units that qualify as low emitters 
of NOX and SO2 (i.e., sources with average 
SO2 concentrations of 250.0 ppm or less and/or average 
NOX emission rates of 0.20 lb/mmBtu or less). Specifically, 
they have questioned the appropriateness of the alternative relative 
accuracy specifications used to determine the RATA frequency (i.e., 
semiannual or annual). Under section 3.3 of Appendix A and section 
2.3.1 of Appendix B to the current part 75 rule, the RATA frequency for 
an SO2 monitor installed on a low-emitting SO2 
source may be determined in either of two ways: by the normal relative 
accuracy specification (i.e. the RATA frequency is semiannual if the 
relative accuracy is > 7.5 percent but  10.0 percent, and 
annual if  7.5 percent relative accuracy is achieved), or by 
the alternative specification (i.e., the RATA frequency is semiannual 
if the reference method mean value and CEMS mean value differ by > 8.0 
ppm but  15.0 ppm, and annual if the two mean values differ 
by  8.0 ppm). For low-emitting NOX sources, the 
RATA frequency for the NOX monitoring system is determined 
in the identical manner to SO2 when the normal specification 
is applied. For the alternative specification, the NOX RATA 
frequency is semiannual if the CEMS and reference method mean values 
differ by  0.01 lb/mmBtu but  0.02 lb/mmBtu, and 
annual if the mean values differ by > 0.01 lb/mmBtu. The 8.0 ppm value 
for SO2 was originally determined based on the performance 
of a single set of monitors at a facility regulated under subpart Da of 
the NSPS in part 60. However, in the first few years of Acid Rain 
Program implementation, many part 75 utilities with wet scrubbers have 
found it difficult to consistently meet the 8.0 ppm criterion for 
obtaining an annual RATA frequency.
    The utility group maintains that since, when the normal relative 
accuracy (RA) specification is applied, the criterion for obtaining an 
annual RATA frequency is to achieve a relative accuracy 25.0 percent 
below the RA specification in section 3.3 of Appendix A (i.e., 7.5 
percent RA is 25.0 percent below the specification of 10.0 percent), 
the criterion for an annual RATA frequency should be essentially the 
same when the alternative specification is applied. Under the current 
rule, the alternative SO2 specification requires that the 
mean CEMS and reference method values differ by no more than 8.0 ppm in 
order to obtain an annual RATA frequency. This is 47.0 percent below 
the 15.0 ppm alternative RA specification. Similarly for 
NOX, the alternative NOX specification for an 
annual RATA frequency requires the difference between the CEMS and 
reference method mean values to be  0.01 lb/mmBtu, or 50.0 
percent below the 0.02 lb/mmBtu alternative RA specification.
    EPA agrees that the alternate RA specifications for low emitters of 
SO2 and NOX appear to be somewhat inequitable, 
and today's rulemaking proposes changes to these specifications. In 
proposed section 2.3.1 of Appendix B, the alternative relative accuracy 
specification for low emitters of SO2, (i.e., the difference 
between the reference method and CEMS mean values) that must be met by 
an SO2 monitor in order to obtain an annual RATA frequency 
would be changed from 8.0 ppm to 12.0 ppm. For low emitters of 
NOX, the alternative low emitter relative accuracy 
specification that must be met by a NOX-diluent monitoring 
system in order to obtain an annual RATA frequency would be changed 
from 0.01 lb/mmBtu to 0.015 lb/mmBtu.
    In today's rule, EPA is also proposing an alternative relative 
accuracy specification of 0.025 lb/mmBtu for SO2-diluent 
monitoring systems to obtain an annual RATA frequency and an 
alternative relative accuracy specification of 0.7 percent 
CO2 or O2, by which CO2 and 
O2 monitors could obtain an annual RATA frequency. During 
the investigation of the alternative RA specifications for the 
SO2 and NOX-diluent monitoring systems, the 
Agency noted that for SO2-diluent systems, part 75 specifies 
only an alternative RA criterion of 0.030 lb/mmBtu for a semiannual 
RATA frequency, but fails to specify a corresponding alternative RA 
criterion for obtaining an annual RATA frequency. Similarly, for 
CO2 and O2 monitors, EPA noted that an 
alternative relative accuracy specification of 1.0 percent 
CO2 or O2 (in terms of the mean difference 
between the reference method and CEM values during the RATA) is given 
for obtaining a semiannual RATA frequency, but no corresponding 
alternative criterion is given for obtaining an annual frequency.
    EPA notes that in order to make the annual RATA frequency criteria 
for NOX-diluent and SO2-diluent monitoring 
systems more equitable, a third decimal place is required. However, 
Secs. 75.54 and 75.55 currently require NOX and 
SO2 emission rates in lb/mmBtu to be reported only to 2 
decimal places. Therefore, revisions are being proposed, see 
Secs. 75.57(d)(6) and 75.58(a)(1)(iv), to require that, beginning on 
January 1, 2000, all NOX emission rates in lb/mmBtu must be 
reported to three decimal places. Prior to January 1, 2000, the owner 
or operator would have the option of reporting NOX emission 
rates to either two or three decimal places. Note that no corresponding 
change is being proposed for the reporting of SO2 emission 
rates in lb/mmBtu, since such emission rates will only be reported to 
EPA by units that have installed Phase I Qualifying Technologies for a 
three-year period (1997-1999), and are not required to be reported 
thereafter. EPA solicits comments on the appropriateness of requiring 
all NOX lb/mmBtu emission rates to be reported to three 
decimal places. The Agency favors this approach, particularly for 
quality assurance purposes, due to increased precision in the 
calculation of RATA results. The Agency notes that this proposed change 
would not affect the way in which compliance with the NOX 
emission limits under part 76 is determined. Compliance with part 76 
NOX limits, in lb/mmBtu, would still be based on two decimal 
places.
    All of the proposed revisions to the part 75 relative accuracy 
specifications in today's rulemaking are summarized in proposed Figure 
2 of Appendix B.
    11. Bias Adjustment Factors for Low Emitters
    As discussed in the preceding section, sources that qualify as low 
emitters of SO2 and/or NOX have two ways to 
evaluate the relative accuracy of SO2 and NOX 
monitoring systems: (a) by the normal relative accuracy specification 
(i.e., 10.0 percent RA), and (b) by the alternative RA specification 
(i.e., the difference between the mean CEMS and reference method values 
is within 15.0 ppm for SO2 low emitters, or 
within 0.02 lb/mmBtu for NOX low emitters).
    The normal RA is determined by a statistical analysis of the 
reference method and CEMS data from the RATA. Mathematically, the 
normal RA is the sum of the absolute values of the mean difference 
(dmean) and the confidence coefficient (cc), expressed as a 
percentage of the mean reference method value (RM)avg. The 
mean difference indicates how closely the CEMS measurements agree with 
the

[[Page 28072]]

reference method and is generally the principal contributor to the 
percentage relative accuracy in the RA equation. The confidence 
coefficient (cc) is a statistical term related to the standard 
deviation and is an indicator of the amount of scatter in the data.
    Section 7.6 of Appendix A requires a bias test of each 
SO2 and NOX monitoring system whenever a RATA of 
the CEMS is performed. If the mean difference is greater than the 
absolute value of the confidence coefficient, the CEMS measurements are 
systematically lower than the corresponding references method 
measurements, i.e., the monitoring system has a low bias. In such 
cases, sources are given two options. The first, preferred by EPA, is 
to locate and eliminate the source of the measurement bias in the 
instrument. The second option is to apply a bias adjustment factor 
(BAF). This alternative was developed in response to an industry 
request to provide an alternative for sources that choose not to expend 
the effort to locate and eliminate the technical problem causing the 
systematic measurement error. The BAF is equal to 1.000 + 
|dmean| /(CEM)avg, where (CEM)avg is 
the mean value of the CEMS measurements from the RATA.
    At least one utility has questioned whether it is appropriate for 
low emitters to calculate a BAF in the usual way when a CEMS fails a 
RATA by the normal RA specification, but passes by the alternative 
specification, because in such cases the BAF can become inordinately 
high, particularly at very low emission levels (see Docket A-97-35, 
Items II-D-62 and II-E-23). Since both the percent relative accuracy 
and the BAF are based upon the same statistical terms (dmean 
and cc), the utility questions whether the standard calculation 
procedure for the BAF is adequate to determine a meaningful BAF for low 
emitters. Just as the value obtained from the standard relative 
accuracy equation tends to become large for low emitters, so, too, the 
BAF is seen as becoming inordinately large for low emitters which use 
the current BAF equation.
    As this comment suggests, it is not uncommon for an SO2 
or NOX CEMS installed on a low-emitting unit to fail a RATA 
by the normal specification of 10.0 percent RA and to pass the same 
RATA by the alternative RA specification. For instance, suppose that 
the mean RM and CEMS values during an SO2 RATA of a low 
emitter are 51.0 ppm and 40.0 ppm, respectively, and that 
dmean is 11.0 ppm and the confidence coefficient is 0.50. 
Suppose further that the bias test is failed. Then, the percent RA by 
the normal specification (i.e.,  |dmean| + |cc |  / 
(RM)avg) would exceed 20.0 percent, indicating a failed 
RATA, but the alternative RA specification would indicate a pass (i.e., 
(CEMS)avg is within 15.0 ppm of 
(RM)avg). In this same illustration, the BAF would be 1 + 11 
/ 40 = 1.275.
    In fact, if it is assumed that the difference between the CEMS and 
the reference method measurements does not decrease as emissions 
decline, then the lower the SO2 or NOX emissions, 
the more likely it is for the CEMS to fail the normal relative accuracy 
specification because the mean difference becomes a larger percentage 
of the average reference method value. It was precisely in response to 
such concerns that the alternative relative accuracy specifications 
were originally included in part 75.
    Today's rule proposes to provide an option in the way the BAF is 
determined for low emitters of SO2 and NOX. Low 
emitters of SO2 and NOX would be given the choice 
of using either: (a) the normal BAF calculation procedure described 
above and found in Equation A-12, section 7.6.5 of Appendix A, or (b) 
an alternative default bias adjustment factor of 1.111.
    The justification is as follows: for units that meet the normal 
relative accuracy standard of RA   10.0 percent, the 
theoretically maximum possible Bias Adjustment Factor is 1.111 (see 
Docket A-97-35, Item II-B-2). Therefore, low-emitting units meeting the 
alternative relative accuracy standards (|dmean|  
15.0 ppm for SO2 low emitters and |dmean| 
 0.02 lb/mmBtu for NOX low emitters) should not 
have to apply a bias adjustment any higher than the maximum BAF value 
applicable to units meeting the normal relative accuracy standard. EPA 
solicits comment on allowing the alternative BAF of 1.111 for low-
emitting units.
12. Clarification of Diluent Monitor Certification Requirements
    Today's proposed rule would clarify the certification requirements 
for diluent gas (CO2 and O2) monitors, in 
response to comments received on the pre-proposal draft of the rule 
(see Docket A-97-35, Item II-D-52). Section 75.20(c)(1)(iii) of the 
current rule requires a RATA of each NOX continuous 
monitoring system to be done for initial certification. Even though the 
NOX system consists of two component monitors 
(NOX concentration and diluent gas), the required RATA is 
done on a system basis in units of lb/mmBtu. Separate RATAs of the 
individual component monitors are not required, except when the diluent 
component monitor is also used as a CO2 pollutant 
concentration monitor or to account for unit heat input, in which case 
Sec. 75.20(c)(5)(iii) in the current rule requires a RATA of the 
diluent monitor. To be sure that this is clear, today's proposed rule 
would add a statement to Sec. 75.20(c)(1)(iii), indicating that the 
RATA for the NOX-diluent system shall be done on a system 
basis (i.e., individual component RATAs are unnecessary for 
certification of a NOX-diluent system). Therefore, units 
that have installed NOX monitoring systems, but that use 
Appendix D for SO2 emission accounting and Appendix G for 
CO2 accounting, would not be required to submit separate 
RATA results for the diluent monitor.
    A second point of clarification would be added in proposed 
Sec. 75.20(c)(3), which was previously designated as Sec. 75.20(c)(4). 
The new section would make it clear that when a diluent monitor 
(O2 or CO2) is used both as a CO2 
pollutant concentration monitor and for heat input determinations, only 
one set of diluent monitor certification test results would have to be 
submitted under the component and system ID codes of the CO2 
monitoring system. This is appropriate because there is no such thing 
as a ``heat input monitoring system'' or an ``oxygen monitoring 
system'' under part 75.
13. Daily Calibration Requirements for Redundant Backup Monitors
    Section 75.20(d)(1) of the current rule requires redundant backup 
(``hot-standby'') monitoring systems to be operated during all periods 
of unit operation and to meet all of the quality assurance requirements 
of Appendix B, including daily calibrations and interference checks, 
quarterly linearity checks and leak checks, and semiannual or annual 
RATAs. One commenter on a pre-proposal draft of today's proposed rule 
requested that EPA consider changing the daily calibration requirement 
for redundant backup monitors (see Docket A-97-35, Item II-D-35). The 
commenter recommended that the daily calibrations be made mandatory 
only for days on which the redundant backup monitoring system is 
actually used to report emission data to EPA. Daily calibrations would 
be optional on all other days. Fewer calibrations of redundant backup 
systems would considerably reduce calibration gas consumption. The 
commenter estimated that this change could result in an annual savings 
of more than $100,000 for his company. EPA agrees that the request is 
reasonable, provided that the redundant

[[Page 28073]]

backup systems are kept on hot-standby and are calibrated prior to each 
use for reporting. The Agency therefore proposes to amend 
Sec. 75.20(d)(1) accordingly.
14. Daily Performance Specification and Control Limits for Low-Span DP 
Flow Monitors
    Section 3.1 of Appendix A of the current rule gives the calibration 
error performance specification for flow monitors. Section 2.1.4 of 
Appendix B gives the calibration error limits for daily operation of 
flow monitors. For initial certification, a flow monitor is required to 
meet a calibration error specification of  3.0 percent of 
the span value. For daily operation of the flow monitor, the 
calibration error must not exceed 6.0 percent of span. These 
specifications are both reasonable and achievable for the vast majority 
of flow monitors. However, when a differential pressure (DP) type flow 
monitor is used to measure stack gas flow rate in a stack that has low 
exit velocities, it can be very difficult for the monitor to pass its 
daily calibration error tests. This is because the daily calibration 
span value for a DP flow monitor is expressed in units of inches of 
water. For stack exit velocities less than 2000 feet per minute, the 
calibration span value will be a very small number (0.20 inches of 
water or less). When performing a daily calibration error test of a 
flow monitor with a span value of 0.20 inches of water, the test would 
be failed (i.e., the calibration error would exceed 6.0 percent of 
span) if the response of the monitor deviated from either the zero or 
high reference signal by 0.02 inches of water. For span values of 0.15 
inches of water or less, the calibration error test would be failed if 
the monitor's response deviated from the reference signals by 0.01 
inches of water. One utility with a DP type flow monitor with a span 
value less than 0.15 inches of water has indicated to EPA that it 
cannot pass daily calibrations unless the monitor responses exactly 
equal the reference signal values (see Docket A-97-35, Item II-E-30). 
Clearly, these daily calibration specifications are too stringent for 
low span DP-type flow monitors. In view of this, EPA is proposing 
alternative calibration error specifications for DP type flow monitors 
with low span values, with ``low'' span value meaning a span value of 
0.20 inches of water or less. The alternative performance specification 
for initial certification, given in proposed section 3.1 of Appendix A, 
would be  0.01 inches of water, rather than  
3.0 percent of span. The alternative specification for daily operation 
of the monitor, given in proposed section 2.1.4 of Appendix B, would be 
 0.02 inches of water, rather than  6.0 percent 
of span. Since the results of a calibration error test of a DP type 
flow monitor are reported to 2 decimal places, the performance 
specification of  0.01 inches of water, is the tightest 
specification that could be imposed, short of requiring the monitor to 
read exactly the reference value with zero tolerance (which is what the 
current specification of  3.0 percent of span essentially 
imposes on a DP flow monitor with very low span). The Agency solicits 
comment on this proposed approach and on the value of the alternate 
specification.

O. CEM Data Validation

Background
    The current requirements of part 75 regarding CEM data validation 
are as follows. Section 75.10 specifies that a valid hourly average 
from a CEMS must be based on a minimum of four evenly spaced data 
points (i.e., one point in each 15-minute quadrant of the clock hour), 
except that two evenly spaced data points separated by at least 15 
minutes are sufficient to validate an hourly average when daily 
calibration error tests and/or other required quality assurance 
activities are conducted during the hour. Data from a CEMS are 
considered to be quality assured, provided that the monitoring system 
has passed all of the initial certification tests required under 
Sec. 75.20(c) and provided that the CEMS is not ``out-of-control,'' as 
a result of having failed any of the daily, quarterly, semiannual, and/
or annual quality assurance tests required in sections 2.1 through 2.3 
of Appendix B. Out-of-control periods extend from the hour of failure 
of a QA test until the hour of completion of a subsequent successful QA 
test of the same type. For instance, if a linearity check of a gas 
monitor is failed, the monitor is considered out-of-control from the 
hour of completion of the failed test until the hour of completion of a 
subsequent successful linearity test.
    Finally, Sec. 75.20(b)(3) specifies that when a change is made to a 
CEMS such that recertification of a monitor becomes necessary, data 
from the CEMS are invalid from the hour in which the change is made to 
the system until the hour of completion of all required recertification 
tests.
    In the first three years of implementing part 75, EPA has received 
numerous requests from the utilities for guidance concerning CEM data 
validation. This has prompted the Agency to re-examine these provisions 
of the rule. From this re-examination, the Agency believes that the 
current data validation provisions of part 75 are neither sufficiently 
detailed nor flexible to address the complex realities of daily 
operation of utility boilers and continuous emission monitoring 
systems. Therefore, today's proposed rule would set forth more 
comprehensive data validation criteria.
Discussion of Proposed Changes
    Today's proposed rule would set forth proposed guidelines for the 
validation of CEM data, attempting to take into account the realities 
associated with the operation and maintenance of electric utility steam 
generating units and continuous emission monitoring systems. The 
proposed guidelines would govern CEM data validation as it pertains to 
six principal areas: (1) calibration error tests and adjustment of gas 
and flow monitors; (2) linearity tests of gas monitors; (3) relative 
accuracy test audits of gas and flow monitoring systems; (4) 
recertifications of gas or flow monitors; (5) data from non-redundant 
backup monitoring systems; and (6) missed QA test deadlines. These 
proposed guidelines for data validation are discussed in detail below.
1. Recalibration and Adjustment of CEMS
    Today's proposed rule would revise section 2.1.3 of Appendix B, the 
``recalibration'' section. The May 17, 1995 rule recommends (but does 
not require) the calibration of a monitor to be adjusted whenever the 
daily calibration error exceeds the performance specification in 
Appendix A. For example, if the calibration error of a gas monitor 
exceeds 2.5 percent of span, but does not exceed the daily control 
limit of 5.0 percent of span, the monitor is considered to be out-of-
adjustment but not out-of-control, and EPA recommends that calibration 
of the monitor be adjusted.
    Today's proposal would re-title section 2.1.3 as ``Additional 
Calibration Error Tests and Calibration Adjustments.'' The 
recommendation to adjust the monitor when the calibration error exceeds 
the Appendix A performance specification would be retained, but 
definitions of ``routine calibration adjustments'' and ``non-routine 
calibration adjustments'' would be added. Routine calibration 
adjustments would be defined as adjustments made to a CEMS following a 
successful calibration error test. The purpose of these adjustments 
would be to bring the monitor readings as close as practicable to the 
tag values of the reference calibration gases or to the

[[Page 28074]]

known values of the flow monitor reference signals. Non-routine 
calibration adjustments would be adjustments in either direction 
(toward or away from the reference value), but within the performance 
specifications of the monitor (i.e., within  2.5 percent of 
span for an SO2 or NOX monitor,  0.5 
percent CO2 or O2 for a diluent monitor, or 
 3.0 percent of span for a flow monitor). Non-routine 
calibration adjustments would be permitted, provided that an acceptable 
technical justification is included in the QA/QC program required under 
section 1 of Appendix B. An additional calibration error test would be 
required following non-routine adjustments, to demonstrate that the 
instrument is still operating within its performance specifications.
    In addition to the daily calibration error requirements in section 
2.1.1 of Appendix B, today's proposed rule would require a calibration 
error test in four specific instances: (1) whenever a daily calibration 
error test is failed; (2) when a CEMS is returned to service following 
routine or corrective maintenance that may affect the ability of the 
CEMS to accurately measure and record emissions data; (3) following 
routine calibration adjustments in which the monitor's calibration is 
physically adjusted, e.g., by means of a potentiometer (however, an 
additional calibration error test would not be required if a 
mathematical algorithm in the DAHS is used to make the routine 
adjustments); and (4) following non-routine calibration adjustments. 
Data from the CEMS would be considered invalid until the required 
additional calibration error test had been successfully completed.
    EPA is proposing to allow non-routine calibration adjustments 
within the performance specifications of an instrument for two 
principal reasons. First, commenters have expressed concern that 
restricting allowable adjustments to routine calibration adjustments 
would limit their ability to make adjustments within the acceptable 
plus or minus control limits of a monitor, particularly prior to 
linearity tests and RATAs. They have indicated that this flexibility is 
necessary because the tag values of reference gases are not 100.0 
percent accurate and adjustments of the analyzer may be needed to 
account for these inaccuracies (see Docket A-97-35, Item II-I-15). EPA 
agrees that this is a legitimate concern. Because there is a tolerance 
of  2.0 percent on the different reference gases used for 
daily calibration error tests, linearity tests, and RATAs, it may be 
necessary to adjust toward or away from the tag value in order to make 
sure that the test specifications are met. The Agency believes, 
however, that it is appropriate to limit the calibration adjustments to 
within the instrument's performance specifications (i.e.,  
2.5 percent of span (for SO2 and NOX), 
 3.0 percent of span (for flow rate), and  0.5 
percent CO2 or O2) in order to provide an on-
going demonstration that the CEMS can simultaneously comply with the 
applicable daily, quarterly, semiannual, or annual performance 
specifications in Appendix A. One utility has expressed concern about 
its vendor's practice of making large calibration adjustments to the 
CO2 monitor prior to RATA testing (see Docket A-97-35, Item 
II-D-63).
    The second reason for proposing to allow non-routine calibration 
adjustments is the sensitivity of dilution-extractive monitors to 
changes in barometric pressure, temperature, and molecular weight. EPA 
believes that the best way to deal with this deficiency in the 
dilution-extractive monitoring technology is to develop a mathematical 
algorithm (site-specific, if necessary) that continuously applies a 
correction to the measurement in order to compensate for pressure, 
temperature, and molecular weight, as necessary, and to program the 
algorithm into the DAHS. However, in commenting on a pre-proposal draft 
of today's proposed rule, a number of utilities indicated that they 
prefer to account for dilution probe pressure effects by manually 
adjusting the monitor's calibration in anticipation of barometric 
pressure changes (e.g., approaching weather fronts) (see Docket A-97-
35, Items II-D-41, II-D-55). After much deliberation, the Agency is 
proposing to allow such adjustments, provided that: (1) the calibration 
of the monitor is not adjusted outside of its performance 
specifications; (2) an additional calibration error test is done to 
verify that the adjustments have been properly made; and (3) the 
procedures used for the adjustments are included in the QA/QC program 
for the CEMS. Despite this, EPA still prefers that automatic pressure, 
temperature, and molecular weight compensation be used, where 
necessary, and would strongly encourage all facilities with dilution-
extractive monitors to develop and apply the necessary mathematical 
algorithm(s).
2. Linearity Tests
    Today's proposal would provide rules for data validation during 
linearity tests, in proposed section 2.2.3 of Appendix B. A routine 
quality assurance linearity test could not be commenced if the CEMS 
were operating ``out-of-control'' with respect to any of its other 
daily, semiannual, or annual quality assurance tests. Linearity tests 
would be done ``hands-off,'' as follows. Prior to the test, both 
routine and non-routine calibration adjustments, as defined in proposed 
section 2.1.3 of Appendix B, would be permitted. During the linearity 
test period, however, no adjustment of the monitor would be permitted 
except for routine daily calibration adjustments following successful 
daily calibration error tests (the Agency notes that it is unlikely for 
calibration error tests to be done during a linearity test period 
except when two or more operating days are required to complete the 
test, e.g., for a peaking unit).
    Proposed section 2.2.3 of Appendix B would specify that when a 
linearity check is failed or aborted due to a problem with the monitor, 
the monitor would be declared out-of-control as of the hour in which 
the test is failed or aborted. Data from the monitor would remain 
invalid until the hour of completion of a subsequent successful hands-
off linearity test. This proposed requirement is not substantially 
different from the out-of-control provision in the current rule. It 
would merely extend the definition of out-of-control to include 
linearity tests that are aborted prior to completion due to a problem 
with the monitor. The underlying assumption is that the aborted 
linearity test would not have been passed if all nine gas injections 
had been completed. However, a linearity test that is aborted for a 
reason unrelated to a monitor malfunction (e.g., an unplanned or forced 
unit outage) would not trigger an out-of-control period.
    Finally, a new section, 2.2.4, would be added to Appendix B, 
providing a linearity test grace period of 168 unit operating hours. 
The purpose of the grace period would be to give the owner or operator 
a window of opportunity in which to perform a linearity test, when 
either: (1) the required linearity test cannot be completed within the 
QA operating quarter in which it is due, or (2) four consecutive 
calendar quarters have elapsed since the end of the calendar quarter in 
which a linearity test of a monitor (or range) was last done. Data 
validation during a grace period would be done according to the 
applicable provisions of proposed section 2.2.3 of Appendix B. Proposed 
section 2.2.4 of Appendix B would specify that if the required 
linearity test has not been completed within the grace period, data 
from the monitor would become invalid, beginning with the first hour 
following the expiration of the grace period and would remain invalid 
until the hour of completion of a

[[Page 28075]]

subsequent successful, hands-off linearity test. Proposed section 2.2.4 
would further specify that a linearity test done during a grace period 
could only be used to meet the linearity test requirement of a previous 
QA operating quarter, not the requirement of the quarter in which the 
grace period is used. Note that proposed sections 2.2.3 and 2.2.4 of 
Appendix B would also extend the 168 unit operating hour grace period 
to apply to the quarterly leak checks of differential pressure-type 
flow monitors.
3. RATAs
    Today's proposal would provide rules for data validation during gas 
and flow monitor RATA tests, in section 2.3.2 of Appendix B. Proposed 
section 2.3.2 would specify that a routine quality assurance RATA could 
not be commenced if the monitoring system is out-of-control with 
respect to any of its daily quality assurance assessments, including 
the additional calibration error test requirements of proposed section 
2.1.3 of Appendix B. All RATAs would be done ``hands-off,'' as follows. 
Prior to the RATA , both routine and non-routine calibration 
adjustments would be permitted, in accordance with proposed section 
2.1.3 of Appendix B. During the RATA test period, however, only routine 
calibration adjustments (as defined in proposed section 2.1.3 of 
Appendix B) would be permitted. For 2-level and 3-level flow RATAs, no 
linearization of the monitor would be permitted between load levels.
    Note that EPA is proposing to allow pre-RATA adjustments and 
linearization of a CEMS, principally to encourage facilities to 
optimize the performance of their CEMS by achieving the best possible 
relative accuracy results in a cost-effective manner with little or no 
data loss. The Agency believes that there is no significant risk in 
allowing pre-RATA adjustments, provided that the monitor's continued 
accuracy between successive RATAs can be reasonably established. For 
gas monitors, EPA believes that the daily calibration error tests and 
quarterly linearity tests, which challenge the analyzers with protocol 
gases of known concentration, provide that assurance. For flow 
monitors, however, the daily calibration error tests, which check the 
internal electronics of the flow monitor but do not evaluate the actual 
flow measurement capability of the instrument, do not provide the 
necessary assurance. Therefore, in today's rulemaking, EPA is proposing 
a new flow monitor quality assurance requirement, the ``flow-to-load 
test,'' to provide a reasonable indicator of continued flow monitor 
accuracy between successive RATAs. The flow-to-load test has been 
discussed in detail under section III.M. of this preamble.
    If a RATA is failed or aborted due to a problem with the CEMS, 
proposed section 2.3.2 of Appendix B would specify that the monitoring 
system is out-of-control as of the hour in which the test is failed or 
aborted. Data from the monitoring system would remain invalid until the 
hour of completion of a subsequent successful hands-off RATA. This 
proposed requirement is essentially the same as the out-of-control 
provision in the current rule, except that it would extend the 
definition of out-of-control to include RATAs that are aborted prior to 
completion due to a problem with the CEMS. Note, however, that a RATA 
which is terminated for a reason unrelated to monitor malfunction 
(e.g., process operating problems or unit outage) would not trigger an 
out-of-control period.
    For multiple-load flow RATAs, each load level would be treated as a 
separate RATA. Therefore, if a flow RATA is failed at a particular load 
level, previously-passed RATAs at the other loads would not have to be 
repeated unless the flow monitor has to be re-linearized. In that case, 
a subsequent 3-load RATA would be required.
    If a daily calibration error test is failed during a RATA test 
period, proposed section 2.3.2 of Appendix B would require invalidation 
of the RATA, and an out-of-control period would begin with the hour of 
the failed calibration error test. The RATA could not to be re-started 
until a subsequent calibration error test had been passed, following 
corrective actions.
    Proposed section 2.3.2 of Appendix B further specifies that when 
the RATA of a CO2 pollutant concentration monitor (or an 
O2 monitor used to measure CO2 emissions) is 
failed and that same CO2 (or O2) monitor also 
serves as the diluent component in a NOX-diluent (or 
SO2-diluent) monitoring system, then both the CO2 
(or O2) monitor and the associated NOX-diluent (or 
SO2-diluent) system would be considered to be out-of-control 
until the hour of completion of subsequent hands-off RATAs which 
demonstrate that both systems are in-control and have met the 
applicable relative accuracy specifications in sections 3.3.2 and 3.3.3 
of Appendix A. The beginning of the out-of-control period for each 
monitoring system would be the hour of completion of the failed or 
aborted RATA of the CO2 (or O2) monitor. The 
lengths of the out-of-control periods would, therefore, be determined 
from the same reference point for both the CO2 (or O2) 
monitoring system and the NOX-diluent (or SO2-
diluent) monitoring system.
    Today's proposal would clarify the way in which RATA results are to 
be reported to EPA in the electronic quarterly report required under 
Sec. 75.64. Proposed section 2.3.2 of Appendix B specifies that only 
the results of completed and partial RATAs that affect data validation 
would have to be reported. That is, all completed passed RATAs, all 
completed failed RATAs, and all RATAs aborted due to a problem with the 
CEMS would have to be included in the quarterly report. Therefore, 
aborted RATA attempts followed by corrective maintenance, re-
linearization of the monitor, or any other adjustments other than those 
allowed under proposed section 2.1.3 of Appendix B would have to be 
reported. RATAs which are aborted or invalidated due to problems with 
the reference method or due to operational problems with the affected 
unit(s) would not need to be reported, because such runs do not affect 
the validation status of emission data recorded by the CEMS. In 
addition, aborted RATA attempts which are part of the process of 
optimizing a monitoring system's performance would not have to be 
reported, provided that in the period from the end of the aborted test 
to the commencement of the next RATA attempt: (1) no corrective 
maintenance or re-linearization of the CEMS is performed, and (2) no 
adjustments other than the calibration adjustments allowed under 
proposed section 2.1.3 of Appendix B are made. However, such RATA runs 
would still have to be documented and kept on-site as part of the 
official test log.
    Whenever a required RATA has not been completed by its deadline, 
section 2.3.3 of Appendix B of today's proposed rulemaking would 
provide a grace period of 720 unit operating hours in which to complete 
the test. Data validation during a grace period would be done according 
to the applicable provisions of proposed section 2.3.2 of Appendix B. 
Proposed section 2.3.3 would specify that if the RATA is not completed 
by the end of the grace period, data from the CEMS would become invalid 
upon expiration of the grace period and remain invalid until the hour 
of completion of a subsequent successful hands-off RATA.
    EPA has proposed a 720 unit operating hour RATA grace period 
because the Agency believes this will allow the facility sufficient 
time to schedule the RATA, to provide all required test notifications, 
and to complete the testing. The proposed grace period would be based 
on unit

[[Page 28076]]

operating hours rather than clock hours, because this is believed to be 
more equitable for peaking and cycling units. Data validation during 
the grace period would be prospective, i.e., data from the monitoring 
system would be considered valid during the grace period until the time 
of the RATA. If the RATA is failed or aborted due to a problem with the 
CEMS, data would be invalidated from the hour in which the test is 
failed or aborted, forward. Data would not be invalidated 
retrospectively back to the beginning of the grace period. Several 
utilities have expressed a preference for a grace period with 
prospective data invalidation, because it is simple to implement and is 
consistent with other part 75 provisions for which data invalidation is 
prospective when a test is failed (see Docket A-97-35, Item II-E-23).
4. Recertification of Gas and Flow Monitors
    Today's proposed rule would revise Sec. 75.20(b)(3) concerning data 
validation during recertification test periods. In the January 11, 1993 
rule, as amended on May 17, 1995, Sec. 75.20(b)(3) specifies that for 
any replacement, change, or modification to a monitoring system 
requiring recertification of the CEMS, all data from the CEMS are 
considered invalid from the hour of that replacement, change, or 
modification until the hour of completion of all required 
recertification tests. Today's rulemaking proposes to conditionally 
allow emission data generated by the CEMS during a recertification test 
period to be used for part 75 reporting, provided that the required 
tests are successfully completed in a timely manner and that certain 
data validation rules are followed during the recertification test 
period. Proposed sections 6.2, 6.3.1, and 6.5 of Appendix A would allow 
these new data validation procedures to also be applied to the initial 
certification of monitoring systems. The proposed revisions are based, 
in part, on policy guidance issued by EPA to address the initial 
certification of CEMS when a wet scrubber is installed on an affected 
unit (see Docket A-97-35, Item II-I-9, Policy Manual, Question 16.10). 
The intent of that policy guidance and of today's proposal is to 
minimize the number of hours of substitute data or maximum potential 
values that must be reported during a monitor certification or 
recertification period.
    In proposed Sec. 75.20(b)(3), specific rules are provided for data 
validation during the recertification test period. The recertification 
test period would begin with the first successful calibration error 
test after making the change to the CEMS and completing all necessary 
post-change adjustments, re-programming, linearization, etc. of the 
CEMS. The post-change activities could also include preliminary tests 
such as trial RATA runs or a challenge of the monitor with calibration 
gases. The first successful calibration error test following all of 
these activities would be known as a probationary calibration error 
test. Data from the CEMS would be considered invalid from the hour in 
which the replacement, modification, or change to the system is 
commenced until the hour of completion of the probationary calibration 
error test, at which point, the data status would become conditionally 
valid.
    Today's proposal would place a specific time limit on the length of 
the recertification test period, depending upon the type(s) of test(s) 
required. If a linearity test or cycle time test is required, the test 
would have to be completed within 168 unit operating hours of the hour 
in which the probationary calibration error test was passed, marking 
the beginning of the recertification test period. If a RATA is 
required, it would have to be completed within 720 unit operating 
hours. If a 7-day calibration error test were required, it would have 
to be completed within 21 unit operating days. Routine daily 
calibration error tests would continue to be done as required by part 
75 throughout the recertification test period. If a particular 
recertification test is not completed within the specified number of 
hours, data validation would be done as follows. For a late linearity 
test, RATA, or cycle time test that is passed on the first attempt, or 
for a late 7-day calibration error test (whether or not it is passed on 
the first attempt), data from the monitoring system would be 
invalidated from the hour of expiration of the recertification test 
period until the hour of completion of the late test. However, for a 
late linearity test, RATA, or cycle time test that is failed on the 
first attempt or aborted on the first attempt due to a problem with the 
monitor, all conditionally valid data from the monitoring system would 
be invalidated from the hour of the probationary calibration error test 
that initiated the original recertification test period to the hour of 
completion of the late recertification test. Data would remain invalid 
until successful completion of the failed/aborted test and any 
additional recertification or diagnostic tests that are required as a 
result of changes made to the monitoring system to correct the 
problem(s) that caused failure of the late recertification test.
    A conditionally valid status would be assigned to emission data 
generated by a CEMS during a recertification test period. The 
conditionally valid data status would begin with the first hour of the 
recertification test period (i.e., the hour in which the probationary 
calibration error test is passed, following completion of all necessary 
monitor adjustments, preliminary tests, etc.). The conditionally valid 
status of the CEMS data would continue throughout the recertification 
test period, provided that the required recertification tests are done 
``hands-off'' (i.e., with no adjustments, reprogramming, etc. of the 
CEMS other than the calibration adjustments allowed under proposed 
section 2.1.3 of Appendix B) and provided that the recertification 
tests and required daily calibration error tests continue to be passed. 
If all of the required recertification tests and calibration error 
tests are passed hands-off, with no failures and within the required 
time period, then all of the conditionally valid emission data recorded 
by the CEMS during the recertification test period would be considered 
quality assured and suitable for part 75 reporting. Note, however, that 
if a required recertification test has not been completed by the end of 
a calendar quarter, the owner or operator would indicate this by using 
a suitable conditional data flag in the electronic quarterly report for 
that quarter. The owner or operator would be required to resubmit the 
report for that quarter if the required recertification test is 
subsequently failed. In the resubmitted report, the owner or operator 
would use the appropriate missing data routine in Sec. 75.31 or 
Sec. 75.33 to replace each hour of conditionally valid data that was 
invalidated by the failed recertification test with substitute data. In 
addition, if conditionally valid data is submitted to the Agency in any 
quarterly report, the owner or operator would have to indicate in the 
end of the year compliance report required under Sec. 72.90 whether the 
final status of the conditionally valid data has been determined. Note 
that in certain instances where a recertification test period spans two 
calendar quarters, it may be possible to avoid use of the conditional 
data flag and quarterly report resubmittal. If a required 
recertification test(s) is completed no later than 30 days after the 
end of a calendar quarter (i.e., prior to the quarterly report 
submittal deadline), the test data and results may be submitted

[[Page 28077]]

with the quarterly report, even though the test dates are from the next 
calendar quarter. If the recertification test(s) is passed, this would 
allow the ``conditionally valid'' data to be reported as quality 
assured, in lieu of using a conditional data flag. If the test(s) is 
failed, conditionally valid data could be replaced with substitute 
data, as appropriate, and resubmittal of the quarterly report would not 
be necessary.
    If a recertification test is failed or aborted due to a problem 
with the CEMS or if a routine daily calibration error test is failed 
during a recertification test period, proposed Sec. 75.20(b)(3) 
specifies that data validation would be done as follows:
    (1) If any required recertification test is failed, the test would 
have to be repeated. If any recertification test, other than a 7-day 
calibration error test, is failed or aborted due to a problem with the 
CEMS, the original recertification test period would end and any 
necessary maintenance activities, adjustments, linearizations, and 
reprogramming of the CEMS would need to be completed before a new 
recertification test period could begin. The new recertification test 
period would begin with a probationary calibration error test. The 
tests that would be required in this new recertification test period 
would include any tests that were required for the initial 
recertification event which were not successfully completed and any 
recertification or diagnostic tests required as a result of changes 
that were made to the monitoring system to correct the problems that 
caused failure of the recertification test;
    (2) If a linearity test, RATA, or cycle time test is failed or 
aborted due to a problem with the CEMS, all conditionally valid 
emission data recorded by the CEMS would be invalidated from the hour 
of commencement of the original recertification test period to the hour 
in which the test is failed or aborted. Data from the CEMS would remain 
invalid until the hour in which a new probationary calibration error 
test is passed following all of the necessary maintenance procedures, 
diagnostic tests, etc., at which time the conditionally valid status of 
emission data from the CEMS would begin;
    (3) If a 7-day calibration error test is failed within the 
recertification test period, the test would have to be re-started. 
Previously-recorded conditionally valid emission data from the CEMS 
would not be invalidated by a failed 7-day calibration error test 
unless the calibration error on the day of the failed 7-day calibration 
error test exceeded twice the performance specification in section 3 of 
Appendix A (causing the monitor to be considered out-of-control); and
    (4) If a calibration error test is failed during a recertification 
test period, the CEMS would be considered out-of-control as of the hour 
in which the calibration error test is failed. Emission data from the 
CEMS would be invalidated prospectively from the hour of the failed 
calibration error test until the hour of completion of a subsequent 
successful calibration error test following corrective action, at which 
time the conditionally valid data status would resume. Failure to 
perform a required daily calibration error test during a 
recertification test period would also cause data from the CEMS to be 
invalidated prospectively from the hour in which the calibration error 
test was due until the hour of completion of a subsequent successful 
calibration error test. Following a failed or missed calibration error 
test, no recertification tests could be performed until the required 
subsequent calibration error test had been passed.
5. Recertification and QA
    In today's proposed rule, a new section, 2.4, entitled 
``Recertification, Quality Assurance, and RATA Deadlines'' would be 
added to Appendix B. The purpose of this section would be to clarify 
the inter-relationship between normal quality assurance testing of CEMS 
and recertification events and to further clarify how RATA deadlines 
are determined. Appendix B to part 75 currently requires periodic 
(daily, quarterly, and semiannual or annual) quality assurance tests of 
all CEMS. The required daily QA tests include calibration error tests 
of all monitors and interference checks of flow monitors. Quarterly QA 
tests include linearity checks of gas monitors and leak checks of 
differential pressure-type flow monitors. The required semiannual or 
annual QA tests for all types of CEMS are RATAs.
    Under the current rule, when a significant change is made to a CEMS 
which affects the ability of the monitoring system to accurately read 
and record emissions data, Sec. 75.20(b) specifies that the CEMS must 
be recertified. To recertify a monitoring system, one or more of the 
following tests that were performed for initial certification of the 
CEMS must be repeated. That is, depending upon the nature of the change 
made to a CEMS, one or more of the following tests may be required for 
recertification: (1) calibration error test, (2) cycle time test, (3) 
linearity check, (4) RATA, or (5) DAHS verification. Notice that 
recertification tests (1), (3), and (4) are the same types of tests 
that are done for routine daily, quarterly, and semiannual or annual 
QA. There is, therefore, a connection between routine QA tests and 
recertification tests. Proposed Sec. 75.20(b) would further clarify 
that any change to a CEMS that does not require a RATA would not be 
considered a recertification event, and, therefore, would not require a 
recertification application. In such cases, the required tests would be 
considered diagnostic tests.
    Routine QA tests are generally planned and scheduled in advance, 
while recertification tests are performed on an as-required basis. 
Despite this, it is sometimes possible to coordinate component 
replacements or other changes to a CEMS with the QA test schedule for 
the CEMS. For instance, suppose that in a particular quarter, a CEMS 
component is replaced, and a RATA is required to recertify the 
monitoring system. Suppose, further, that in the quarter of the 
component replacement, the annual RATA is due, but has not yet been 
conducted. In this case, the recertification RATA could serve a dual 
purpose, i.e., to recertify the CEMS and to meet the annual RATA 
requirement. For this reason, EPA proposes to recommend in today's rule 
that, to the extent practicable, component replacements, system 
upgrades, and other events that require recertification be coordinated 
with the periodic (daily, quarterly, and semiannual or annual) QA 
testing required under Appendix B. Proposed section 2.4 of Appendix B 
clarifies that when a particular test is done for the dual purpose of 
recertification and routine QA, the data validation rules in 
Sec. 75.20(b)(3) pertaining to recertification would take precedence 
and would be followed. In a similar manner, a required diagnostic test 
(e.g., linearity check) could also be used to satisfy a quarterly 
linearity test requirement.
    Proposed section 2.4 of Appendix B emphasizes that, in general, 
whenever a RATA is performed, whether for QA purposes, recertification 
purposes, or both, the projected deadline for the next RATA (i.e., 
whether the next test is due in 2 or 4 QA operating quarters) would be 
established based upon the percentage relative accuracy obtained. For 
2-load and 3-load flow RATAs, the projected deadline for the next RATA 
would be established according to the highest relative accuracy at any 
of the loads tested. There would, however, be two important exceptions 
to this for single-load flow RATAs. Irrespective of

[[Page 28078]]

the relative accuracy percentage obtained, the results of a single-load 
flow RATA could only be used to establish an annual RATA frequency if: 
(1) the single-load flow RATA is specifically required under section 
2.3.1.3(b) of Appendix B for flow monitors installed on peaking units 
and bypass stacks, or (2) the single-load RATA is allowed under 
proposed section 2.3.1.3(c) of Appendix B for  85.0 percent 
historical unit operation at a single-load level. No other single-load 
flow RATA could be used to establish an annual frequency; however, a 2-
load flow RATA could be performed in place of any required single-load 
RATA, in order to achieve an annual frequency.
6. Data From Non-Redundant Backup Monitors
    Today's rule proposes to revise the quality assurance and data 
validation requirements in Sec. 75.20(d) for non-redundant backup 
monitoring systems. Under the May 17, 1995 rule, a ``non-redundant 
backup monitoring system'' is defined as a ``cold'' backup monitoring 
system which is brought into service on an as-needed basis, rather than 
being operated continuously. Non-redundant backup monitors must be 
initially certified at each location at which they are to be used, but 
unlike ``redundant backup'' monitors which are operated continuously 
and kept on ``hot-standby,'' non-redundant backup systems are not 
required to meet the daily and quarterly quality assurance requirements 
of Appendix B, except when they are actually used for data reporting. A 
linearity test of each non-redundant backup gas monitor is required 
before it is placed in service, and each non-redundant backup flow 
monitor must pass a calibration error test before being used to report 
data. The use of non-redundant backup monitors is restricted to 720 
hours a year at a particular unit or stack, unless a 7-day calibration 
error test is passed. A periodic recertification RATA of each non-
redundant backup monitor is required at least once every two years, at 
each location where it is to be used.
    Section 75.20(d) of today's proposal would clarify and expand the 
definition of a non-redundant backup monitoring system. Under the 
proposal, two distinct types of non-redundant backup systems would be 
defined: (1) type-1 is a system that has its own separate probe, sample 
interface, and analyzer (e.g., a portable gas monitoring system), and 
(2) type-2 is a system consisting of one or more like-kind replacement 
analyzers that use the same sample probe and interface as the primary 
monitoring system. This would include non-redundant backup analyzers 
that are used to meet the dual span and range requirements for 
SO2 or NOX under proposed sections 2.1.1.4 and 
2.1.2.4 of Appendix A.
    The ``type-1'' system is the familiar non-redundant backup system 
described in the current version of part 75. However, the ``type-2'' 
system is a new kind of non-redundant backup monitoring system. EPA 
believes that allowing limited use of type-2 monitoring systems will 
encourage facilities that do not have redundant backup monitors to 
perform better maintenance on their primary analyzers. The Agency is 
concerned that primary analyzers with excessive, recurring daily 
calibration drift (i.e., monitors that fail calibration error tests 
more often than expected) are sometimes kept in service to avoid using 
substitute data, when the analyzers should be in the shop for 
maintenance. If the monitor readings tend to drift low from day to day, 
this can result in under-reporting of emissions, because data 
validation for daily calibrations under part 75 is prospective. That 
is, data are invalidated from the hour of a failed calibration error 
test forward, while data recorded from the hour of the previous 
successful calibration to the hour of the failed calibration are 
considered valid. EPA believes that allowing limited use of type-2 non-
redundant backup monitoring systems would provide a simple way (i.e., 
like-kind analyzer replacement) for primary analyzers to be properly 
maintained and repaired with minimal data loss.
    Today's proposal would retain the requirement for type-1 non-
redundant backup monitoring systems to be initially certified (except 
for a 7-day calibration error test) at each location at which they are 
to be used. However, type-2 systems would require no initial 
certification. Both types of systems would have to pass a linearity 
test (for gas monitors) or a calibration error test (for flow monitors) 
each time that they were used to report emission data. For a type-2 
``mix-and-match'' NOX monitoring system consisting of one 
primary analyzer and one like-kind replacement analyzer, only the like-
kind replacement analyzer would have to pass a linearity test, provided 
that the primary analyzer is operating and not out-of-control with 
respect to any of its quality assurance requirements. When a non-
redundant backup monitoring system is brought into service, emission 
data from the non-redundant backup system could be deemed conditionally 
valid during the linearity test period, as follows. After making the 
like-kind replacement and prior to conducting the linearity test, a 
probationary calibration error test could be done to begin the period 
of conditionally valid data. If the linearity test is then passed 
within 168 unit operating hours of the probationary calibration error 
test, the conditionally valid data would be validated. However, if the 
linearity test is either failed, aborted due to a problem with the 
CEMS, or not completed as required, then all of the conditionally valid 
data would be invalidated beginning with the hour of the probationary 
calibration error test, and data from the non-redundant backup CEMS 
would remain invalid until the hour of completion of a successful 
linearity test.
    Under today's proposal, when a non-redundant backup system is used 
for part 75 reporting, the bias adjustment factor (BAF) from the most 
recent RATA of the system would be applied to the data generated by the 
system. If no RATA results were available for a type-2 system, the 
primary monitoring system BAF would be applied to the data generated by 
the type-2 system.
    Today's proposal would retain the restrictions of the current rule, 
which limit the annual usage of a non-redundant backup monitoring 
system to 720 hours at a particular location (unit or stack). To use a 
non-redundant backup system for more than 720 hours per year at a 
particular location would require a RATA of the system at that 
location. For type-1 systems, a recertification RATA would be required 
at least once every eight calendar quarters at each location at which 
the system is to be used. All non-redundant backup monitoring systems 
(type-1 and type-2) would have to be assigned unique system and 
component identification numbers and would have to be included in the 
monitoring plan for the unit or stack.
7. Missed QA Test Deadlines
    As discussed above under the subsections on ``Linearity Tests'' and 
``Relative Accuracy Test Audits,'' proposed sections 2.2.4 and 2.3.3 of 
Appendix B to today's rulemaking would allow a grace period in which to 
perform required linearity tests and RATAs whenever a test cannot be 
completed by the end of the quarter in which it is due. EPA believes it 
is appropriate to allow a grace period because circumstances beyond the 
control of the owner or operator (e.g., unplanned unit outages) 
sometimes arise which prevent the deadline for a quality assurance test 
from being met.
    The proposed linearity grace period is 168 unit operating hours, 
and the proposed RATA grace period is 720 unit operating hours. A 
linearity grace period

[[Page 28079]]

could only be used to satisfy the linearity requirement from a previous 
quarter. For any RATA (or RATAs, if more than one attempt is made) 
conducted during a grace period, the deadline for the next RATA would 
be calculated from the quarter in which the RATA was originally due, 
not from the quarter in which the RATA is actually completed.
    Data validation during a grace period would be done according to 
the applicable provisions in proposed section 2.2.3 of Appendix B (for 
linearities) or section 2.3.2 of Appendix B (for RATAs). Data from a 
CEMS would become invalid upon expiration of a grace period if the 
required linearity test or RATA had not been completed. Data from the 
CEMS would remain invalid after the expiration of the grace period 
until the required test is successfully completed.

P. Appendix D

1. Pipeline Natural Gas Definitions
Background
    Appendix D provides an optional protocol by which oil-fired and 
gas-fired units may account for their SO2 mass emissions. 
Under the definitions of ``oil-fired'' and ``gas-fired'' in Sec. 72.2, 
Appendix D may be used to measure SO2 emissions from gaseous 
fuels only if the gaseous fuel's sulfur content is less than or equal 
to that of natural gas.
    In developing Appendix D, EPA assumed that virtually all of the 
gaseous fuel combusted by affected units in the Acid Rain Program would 
be pipeline natural gas. Section 2.3 of Appendix D of the January 11, 
1993 rule allowed for accounting for SO2 emissions from 
gaseous fuel using EPA's ``National Allowance Database (NADB) emission 
rate.'' The NADB was used to establish a baseline of historical 
SO2 emissions in order to allocate allowances. For the vast 
majority of units combusting pipeline natural gas, NADB used the 
historical heat input from gas and an emission rate of 0.0006 pounds of 
SO2 per measured million British thermal units (lb/mmBtu) 
(see Docket A-92-06; Docket A-94-16, Item II-F-2). This default factor 
is derived from EPA Publication AP-42 and is based on a sulfur content 
of 0.2 grains per 100 standard cubic feet of gaseous fuel (gr/100 scf) 
(see Docket A-97-35, Item II-I-1). Use of this default SO2 
emission rate factor for pipeline natural gas was clarified by EPA in 
its Acid Rain Policy Manual (see Docket A-97-35, Item II-I-9, Policy 
Manual, Question 2.4).
    Section 2.3.2 of Appendix D, as revised by the May 17, 1995 direct 
final rule, explicitly allows owners or operators to use a default 
emission factor of 0.0006 (lb/mmBtu) to estimate SO2 
emissions during hours in which pipeline natural gas is combusted. 
Alternatively, section 2.3.1 of Appendix D, also as revised by the May 
17, 1995 direct final rule, allows for determining SO2 
emissions from any gaseous fuel with a sulfur content no greater than 
natural gas by performing daily fuel sampling, analyzing the sulfur 
content of the gaseous fuel, and multiplying that sulfur content in 
grains per 100 standard cubic feet (gr/100scf) times the volume of 
gaseous fuel combusted. Units combusting gaseous fuels with a total 
sulfur content greater than natural gas (i.e., > 20 gr/100scf) are not 
allowed to use the procedures of Appendix D and must instead use an 
SO2 CEMS and a flow monitor to determine SO2 mass 
emissions. This limitation is explicitly stated in Sec. 75.11(e)(4), as 
revised on November 20, 1996.
    The definition of ``natural gas'' in Sec. 72.2, as revised by the 
May 17, 1995 direct final rule, indicates that the sulfur content of 
natural gas is ``1 grain or less hydrogen sulfide per 100 standard 
cubic feet, and 20 grains or less total sulfur per 100 standard cubic 
feet.'' This definition was taken from Requirements of the Federal 
Energy Regulatory Commission (FERC) for regulation of the transmission 
of natural gas. ``Pipeline natural gas'' is also defined in Sec. 72.2. 
However, the definition is simply ``natural gas that is provided by a 
supplier through a pipeline,'' and provides no specifications for 
sulfur content or hydrogen sulfide content.
    Section 2.3.2.2 of Appendix D requires documentation of the 
contractual sulfur content of pipeline natural gas from the supplier. 
This documentation was intended to demonstrate that the natural gas is 
supplied through a pipeline, as well as that it meets the sulfur 
content definition for natural gas.
    Questions over the applicability of Appendix D and the apparent 
inconsistencies between the definitions ``natural gas'' and ``pipeline 
natural gas'' in Sec. 72.2 and the provisions of section 2.3 of 
Appendix D have caused confusion during program implementation since 
the May 17, 1995 direct final rule. Some utilities have interpreted 
section 2.3.2.2 of Appendix D to allow pipeline natural gas to have a 
sulfur content as high as 20 gr/100 scf, which is one hundred times 
higher than the sulfur content upon which the 0.0006 lb/mmBtu emission 
factor is based. During the process of applying for certification of 
monitoring equipment for six gas-fired units, one utility indicated to 
the Agency that it intended to use a default emission rate of 0.0006 
lb/mmBtu and heat input to account for SO2 mass emissions 
from propane liquefied petroleum gas (see Docket A-97-35, Item II-D-6). 
Based upon the information provided by the utility in its monitoring 
plan for the units, the sulfur content of propane was several times 
higher than that of pipeline natural gas, with a range of sulfur 
content between 0.08 and 2.72 gr/100 scf, compared to a typical sulfur 
content of 0.2 gr/100 scf for pipeline natural gas, upon which the 
default SO2 emission rate of 0.0006 lb/mmBtu is based. Later 
information submitted by the utility indicated that during the previous 
three years, the sulfur content of propane combusted at that plant had 
an average value of 0.83 gr/100 scf and a maximum value of 2.20 gr/100 
scf (see Docket A-97-35, Item II-D-60). EPA rejected the utility's 
monitoring approach using the default emission rate for pipeline 
natural gas because it would have resulted in an underestimation of 
SO2 emissions, as well as not following the procedures of 
Appendix D (see Docket A-97-35, Item II-C-2).
    Other utilities have tried to use the default SO2 
emission rate of 0.0006 lb/mmBtu for higher sulfur gaseous fuels, such 
as digester gas (see Docket A-94-16, Item II-D-71). EPA issued policy 
guidance to ensure that other utilities were aware that the default 
SO2 emission rate of 0.0006 lb/mmBtu should only be used for 
pipeline natural gas with a low sulfur content of 0.2 gr/100 scf (see 
Docket A-97-35, Item II-I-9, Policy Manual, Question 2.15, as 
originally published in March 1996). However, several utilities were 
concerned that this excluded some pipeline natural gas (see Docket A-
97-35, Items II-B-3, II-E-16). As stated in the technical support 
document for the May 17, 1995 direct final rule, EPA had intended that 
all pipeline natural gas would qualify for use of the default 
SO2 emission rate of 0.0006 lb/mmBtu. Therefore, the Agency 
revised its guidance to clarify that a facility needed only to document 
that it was using pipeline natural gas, without documenting a sulfur 
content of 0.2 gr/100 scf (see Docket A-97-35, Item II-I-9, Policy 
Manual, Question 2.15, as revised in June 1996). During this process, 
the Agency became concerned that the definition of pipeline natural gas 
in Sec. 72.2 was not clear enough and that the sulfur content 
documentation required for pipeline natural gas in section 2.3.2.2 of 
Appendix D was confusing and possibly inappropriate.

[[Page 28080]]

Discussion of Proposed Changes
    For the definition of pipeline natural gas in Sec. 72.2, today's 
proposal includes a revised definition that would indicate pipeline 
natural gas is low in the sulfur-bearing compound hydrogen sulfide 
(H2S). The proposed revised definition would specifically 
include the maximum hydrogen sulfide content for pipeline natural gas 
permitted by fuel purchase or transportation contracts. The hydrogen 
sulfide content of pipeline natural gas is proposed to be up to 0.3 gr/
100 scf.
    In addition, section 2.3 of Appendix D would be revised. As under 
the current rule provisions, sources would be allowed to use a default 
SO2 emission rate of 0.0006 lb SO2/mmBtu in 
conjunction with unit heat input to calculate the SO2 mass 
emission rate during the combustion of pipeline natural gas. In order 
to demonstrate that the pipeline natural gas qualifies to use the 
default SO2 emission rate of 0.0006 lb/mmBtu, it would be 
necessary for the designated representative to provide information in 
the monitoring plan on the gas's maximum hydrogen sulfide content from 
the facility's purchase contract with the pipeline gas supplier or from 
the pipeline natural gas supplier's transportation contract. In such 
contracts, or in the tariff sheets associated with them, the pipeline 
gas supplier typically agrees to provide natural gas with a maximum 
hydrogen sulfide content of 0.25 gr/100 scf or 0.30 gr/100 scf. If a 
facility has previously submitted contract information from its 
pipeline gas supplier containing a limit on the sulfur content, this 
information typically also verifies the limit on the hydrogen sulfide 
content. For pipeline natural gas, it would not be necessary to provide 
sampling information to verify that the hydrogen sulfide content 
actually meets the quality specification limit on the hydrogen sulfide 
content stated in the definition of pipeline natural gas.
    If a facility wanted to demonstrate that another gaseous fuel had 
an SO2 emission rate no greater than pipeline natural gas, 
and thus, could use the default emission rate factor of 0.0006 lb/
mmBtu, the designated representative would provide sulfur content and 
GCV information in the monitoring plan for the unit or could petition 
under Sec. 75.66(i) after initial certification for the unit. It would 
be necessary for the designated representative to demonstrate that the 
gaseous fuel has an SO2 emission rate no greater than 0.0006 
lb/mmBtu. The designated representative would need to provide at least 
720 hours of data for the demonstration. The data could come from the 
fuel supplier, if the fuel came from a gas supplier.
    For all units using Appendix D, proposed section 2.3.3 would 
require the designated representative to provide information to the 
Agency demonstrating that the total sulfur content of the gaseous fuel 
meets the requirements of Appendix D and that the unit meets the 
Sec. 72.2 definition of ``gas-fired'' or ``oil-fired.'' Additionally, 
the gas-fired definition would be revised to indicate that the 
restriction of burning gaseous fuels containing no more sulfur than 
natural gas is actually a restriction on the total sulfur in the fuel. 
The gaseous fuel's total sulfur content would have to be shown to be 
less than or equal to 20 grains total sulfur per 100 standard cubic 
feet of gaseous fuel.
Rationale
    The Agency proposes to introduce specific hydrogen sulfide content 
values into the definition of pipeline natural gas in order to provide 
a guideline that will separate gaseous fuels with a higher sulfur 
content from low sulfur pipeline natural gas. The maximum hydrogen 
sulfide content of 0.3 gr/100 scf is being proposed for two reasons. 
First, hydrogen sulfide contents of 0.25 or 0.3 gr/100 scf are 
typically required under pipeline gas transmission contracts, and 
should be relatively easy to document (see Docket A-97-35, Item II-E-
19). In addition, 0.2 gr/100 scf is the sulfur content equivalent to 
the default emission rate factor of 0.0006 lb/mmBtu from the Agency's 
AP-42 emission factors that may be used by units combusting pipeline 
natural gas under section 2.3.2 of Appendix D (see Docket A-97-35, Item 
II-A-6). A maximum hydrogen sulfide content of 0.3 gr/100 scf 
corresponds to this default emission rate far more closely than a total 
sulfur content of 20.0 gr/100 scf or a hydrogen sulfide content of 1.0 
gr/100 scf and, yet, would allow for some variability in the hydrogen 
sulfide content above a 0.2 gr/100 scf average. EPA believes that all 
or virtually all pipeline natural gas that is supplied through a 
pipeline for commercial use can meet these qualifications.
    Pipeline natural gas is composed predominantly of methane 
(CH4). Hydrogen sulfide is the predominant molecule 
containing sulfur in pipeline natural gas. Therefore, restricting the 
hydrogen sulfide content of pipeline natural gas to 0.3 gr/100 scf 
serves as a proxy for a limit on the total sulfur content, while being 
relatively easy to document. This revised definition of pipeline 
natural gas would also serve to restrict the default emission rate 
factor from being inappropriately applied to higher sulfur gaseous 
fuels, such as liquefied petroleum gas (see Docket A-97-35, Item II-D-
6) or digester gas (see Docket A-94-16, Item II-D-71).
    Appendix D of today's proposed rule would be revised to clarify the 
documentation requirements for sulfur content and hydrogen sulfide 
content of gaseous fuel, including pipeline natural gas. The original 
wording of section 2.3.2.2 implied that pipeline natural gas only need 
to have a total sulfur content of 20 gr/100 scf, roughly 100 times the 
sulfur content associated with the default emission rate of 0.0006 lb/
mmBtu. Some utilities found this confusing (see Docket A-97-35, Items 
II-D-6, II-E-10). Therefore, EPA issued guidance to clarify that the 
default emission rate factor was only intended to apply to lower sulfur 
pipeline natural gas (see Docket A-97-35, Item II-I-9, Policy Manual, 
Question 2.15).
    However, some utilities using pipeline natural gas were concerned 
that because their fuel suppliers were not willing to certify or agree 
to a sulfur content of 0.3 gr/100 scf by contract, they might be 
required to perform daily gas sampling (see Docket A-97-35, Items II-B-
3, II-E-15, II-E-16). This was not the Agency's intent. The Agency 
merely wishes to ensure that facilities provide adequate documentation 
to demonstrate that the unit will not be underestimating SO2 
emissions for a high sulfur gaseous fuel by using an inappropriate 
default emission rate factor that applies to extremely low sulfur gas. 
Similar to EPA's Policy Manual Question 2.15 referred to above, a 
facility would need only to provide the fuel quality specification for 
total sulfur content and hydrogen sulfide from the pipeline supplier, 
or from the tariff sheet for the pipeline, in order to qualify to use 
the default emission rate.
    If a facility intends to use the default emission rate factor for a 
gaseous fuel other than pipeline natural gas, sulfur content and GCV 
data would have to be provided and analyzed to demonstrate that the 
fuel has an SO2 emission rate no greater than 0.0006 lb/
mmBtu. A minimum of 720 hours of data would be required for the 
demonstration. Each hourly value of the total sulfur content (in gr/100 
scf) would be divided by the GCV value (in Btu/100 scf) and then 
multiplied by a conversion factor of 106 Btu/mmBtu. This 
would provide a ratio of the number of grains of sulfur in the fuel to 
the heat content of the fuel. For pipeline natural gas with an assumed 
SO2 emission rate of 0.0006 lb/mmBtu, a sulfur content of 
0.2 gr/100 scf and a

[[Page 28081]]

GCV value of 100,000 Btu per hundred scf, the value of the ``sulfur-to-
heat content'' ratio is 2.0 gr/mmBtu. Therefore, a candidate gaseous 
fuel would qualify to use the default SO2 emission rate of 
0.0006 lb/mmBtu for part 75 reporting purposes if the 720 hours of 
historical data demonstrate that the mean value of the sulfur-to-heat 
content ratio is 2.0 gr/mmBtu or less.
    To demonstrate that a unit qualifies to use Appendix D when 
combusting a gaseous fuel, the designated representative for the 
facility would be required to show that the gaseous fuel has a total 
sulfur content of 20 grains/100 scf or less. This demonstration would 
apply to all gaseous fuels. For gaseous fuels other than pipeline 
natural gas, the sulfur content information could come either from 
contractual information on the sulfur content based on routine vendor 
sampling and analysis or from historic fuel sampling data to show the 
gaseous fuel's sulfur content (see Docket A-97-35, Item II-I-9, Policy 
Manual, Question 2.15). For gaseous fuels that are produced in batches 
or lots with a relatively uniform sulfur content, such as liquefied 
petroleum gases, it would be sufficient to provide historical 
information on each batch over the past year. This approach was 
accepted by the Agency for six units combusting liquefied petroleum gas 
(see Docket A-97-35, Items II-C-14 and II-D-22).
    In addition to documenting the total sulfur content of the fuel, 
the owner or operator would be required to submit certain other fuel-
specific information. As previously noted, for units combusting 
pipeline natural gas, a designated representative would be required to 
provide contractual information to demonstrate that the natural gas is 
supplied under specification and has a hydrogen sulfide content less 
than or equal to 0.3 gr/100 scf. And historical data would have to be 
provided, as described above, to obtain permission to use the default 
SO2 emission rate of 0.0006 lb/mmBtu for a fuel other than 
pipeline natural gas. For other gaseous fuels that are not produced in 
batches with relatively uniform sulfur content, such as gaseous fuel 
generated through an industrial process (e.g., digester gas from a 
paper mill), since the sulfur content of the gaseous fuel could be 
highly variable, section 2.3.3.4 of today's proposed revisions to 
Appendix D would require a minimum of 720 hours of historical data 
documenting the sulfur content of the fuel under representative 
operating conditions. This information would allow the Agency to 
determine how variable the sulfur content is and if the daily sampling 
procedure under section 2.3.1 of Appendix D is sufficient to capture 
this variability without allowing the underestimation of sulfur 
content. If the sulfur variability were too great, continuous sampling 
using a gas chromatograph and hourly reporting of sulfur content would 
be required under today's proposed rule.
2. Fuel Sampling
    (a) Fuel Oil.
Background
    Diesel fuel is distillate fuel oil of grades No. 1 or 2. Diesel 
fuel is heavily refined and has a much lower sulfur content and greater 
consistency than other grades of fuel oil. Section 2.2 of Appendix D to 
the May 17, 1995 direct final rule provides three options for sampling 
of diesel fuel and two options for sampling of other fuel oils. First, 
for all fuel oils, including diesel fuel, daily manual sampling is 
allowed. Second, diesel fuel and other fuel oils may also be sampled 
continuously using an automated sampler according to ASTM D4177-82 
(Reapproved 1990), either using continuous drip sampling or flow 
proportional sampling. The samples would then be mixed to form a daily 
composite sample. Third, diesel fuel may be sampled ``as-delivered,'' 
upon receipt of a shipment. These sampling approaches were selected to 
ensure that sulfur content values would be as accurate as possible, 
would not underestimate SO2 mass emissions, and would 
account for any variability in the sulfur content of fuel.
    Many utilities have expressed concern about the cost of daily oil 
sampling (see Docket A-97-35, Items II-D-18, II-D-20, II-E-13, II-E-
14). Some utilities indicated that for a unit that burns oil every day, 
the cost of daily oil sampling is greater than the cost of 
SO2 CEMS and flow monitors. Furthermore, industry 
representatives provided information indicating that within a given 
shipment of fuel oil from a supplier, the variability in sulfur content 
is low (see Docket A-97-35, Items II-D-18 and II-D-59). Many companies 
already have state or Federal requirements for sampling of fuel from 
each truck delivery or in a storage tank on site at the plant whenever 
fuel is added to the storage tank (see Docket A-97-35, Item II-D-93). 
The storage tank is a tank at a plant that holds oil that is actually 
combusted by the unit on that day. In other words, no fuel will be 
blended between the time when a fuel lot is transferred to the storage 
tank and when the fuel is combusted in the unit. In other cases, such 
as EPA's NSPS regulations for industrial boilers under 40 CFR part 60, 
subpart Db, companies keep copies of fuel receipts from the supplier to 
indicate the sulfur content is below the required sulfur content. Based 
upon this information, EPA is proposing to reduce the required sampling 
frequency for fuel oil. This would be a significant reduction in burden 
and cost of using Appendix D, without causing underestimation of 
SO2 emissions.
Discussion of Proposed Changes
    Several utilities suggested that the Agency propose to allow 
sampling of each delivery of oil (see Docket A-97-35, Items II-D-18, 
II-D-20, II-E-13, II-E-22). Under this approach, either a facility or 
its supplier would sample each truck or barge containing oil before the 
fuel is transferred into a tank at the plant. If a delivery shipped in 
a group of trucks were purchased under the same order and were 
specified to have the same gross calorific value, density, and sulfur 
content, then only one sample would be necessary for the group of 
trucks. Samples taken by the supplier would not need to be split and 
kept on hand at the site. This approach is currently allowed only for 
diesel fuel under section 2.2.1.2 of Appendix D, but would be extended 
to apply to all fuel oils under today's proposed rule. This approach 
would be particularly useful to a facility that receives large, 
infrequent deliveries of fuel or to a facility that already has other 
State or Federal regulations requiring sampling of each truck or barge 
delivered to the plant.
    A similar approach suggested by another industry representative, 
allowing facilities to use a sample of oil taken from a tank belonging 
to the supplier before the oil is delivered, is also proposed in 
today's rulemaking. The supplier could take the sample and the facility 
would be able to use that value as long as it keeps records of the fuel 
analysis results from the supplier. This approach would be particularly 
useful to a facility that receives a delivery of oil from a single 
supplier's tank that is shipped in many different trucks. This approach 
also would be useful for a small facility that would prefer to rely on 
samples taken by the supplier rather than taking its own samples and 
paying for their analysis.
    Finally, the Agency proposes a third sampling approach, allowing a 
facility to sample oil manually from its storage tank at the plant 
whenever oil is added to the tank. This approach would yield samples 
that are more representative of the oil combusted because it would 
include any fuel remaining in the tank as well as all fuel added. 
Sampling from the storage tank at the plant would be

[[Page 28082]]

useful to a facility that burns oil infrequently and adds oil to its 
storage tank infrequently. It also would be helpful where a facility 
already has other State or Federal regulations requiring sampling after 
adding fuel to the storage tank.
    Both the ``before delivery'' and ``as delivered'' sampling 
approaches would require a sample for each ``lot'' of oil; 
consequently, a suitable definition of a ``lot'' is needed. For 
purposes of determining when an oil sample should be taken for the NSPS 
applicable to utility boilers, section 5.2.2.2 of Method 19 in Appendix 
A to 40 CFR part 60 relies on a definition of fuel ``lot'' developed by 
the American Society for Testing and Materials (ASTM). This definition 
states that ``the lot size of a product oil is the weight of product 
oil from one pretreatment facility and intended as one shipment (ship 
load, barge load, etc.).'' In essence, a lot is a single batch of oil 
that has uniform properties and is purchased from a single supplier and 
delivered to a buyer. Among those uniform fuel properties are gross 
calorific value, density, sulfur content, and viscosity. In today's 
rulemaking, EPA proposes to adopt this definition of a lot of oil for 
use in the Acid Rain Program.
    The Agency also considered whether it is appropriate to keep the 
current approach of daily manual oil sampling as an option. Although it 
seems unlikely that facilities would choose daily sampling option if 
they have the three options of sampling by lot, sampling upon addition 
of fuel to a storage tank, or continuous sampling, a utility group has 
requested that EPA retain daily manual sampling as an option. The 
agency is, therefore, proposing to retain daily manual oil sampling as 
an option in Appendix D to allow facilities this additional 
flexibility. An industry representative suggested that EPA could define 
the oil combusted during a 24-hour period as a lot. For the reasons 
discussed below and in the section addressing sulfur content, density, 
and gross calorific values used in calculations, EPA is not 
incorporating this suggestion in today's proposed rule.
    EPA also reconsidered whether it is necessary to require daily 
composite samples when samples are taken continuously with an automatic 
sampler. In today's proposal, the Agency is proposing that continuous 
samples may be composited on a weekly basis rather than daily. The 
Agency also considered allowing an even longer compositing period, such 
as a month, but is not proposing this option for the reasons discussed 
below. A weekly composite sample of oil that is sampled continuously 
would be an attractive option for a facility that wants the most 
representative and accurate sulfur content data possible. This also 
would be a useful option for those few facilities that receive oil via 
a pipeline, rather than in discrete lots.
Rationale
    Facilities wish to be able to perform less frequent fuel sampling 
in order to save money. From the information EPA has examined over the 
previous year, the Agency believes that less frequent oil sampling can 
be technically justified. Based upon information provided by utilities, 
the sulfur content of a lot of oil varies from sample to sample, with a 
standard deviation of 0.036 percent S to 0.063 percent S, or 5.62 to 
6.85 percent of the average sulfur content for all daily samples 
between deliveries (see e.g., Docket A-97-35, Item II-D-18). Density 
and gross calorific value of oil in a lot should vary even less than 
sulfur content, because sulfur is an impurity in the composition of the 
fuel and not an essential physical property of the oil, as is density. 
Furthermore, the difference between the sulfur content, density, gross 
calorific value, and carbon content of a fuel during the first daily 
sample after a new delivery is received and the average sulfur content, 
density, gross calorific value, and carbon content for all daily 
samples from between two deliveries is extremely small (see Docket A-
97-35, Items II-B-18 and II-D-18 for supporting information). 
Therefore, the Agency expects that the variability of fuel 
characteristics within a lot is low enough that only a single 
representative sample is necessary for the lot. Data have indicated 
that there could be a significant difference in sulfur content between 
shipments, however (see Docket A-97-35, Items II-B-12, II-B-18 and II-
D-18). The Agency believes that differences between lots, which could 
potentially result in the underestimation of SO2 emissions, 
can be dealt with by selecting a conservative sulfur content, density, 
or gross calorific value that would not be exceeded in any sample, 
rather than retaining more frequent sampling requirements. Therefore, 
today's proposal incorporates this approach.
    Prior to drafting today's proposed rule revisions, EPA requested 
comments on removing the option to perform daily manual oil sampling 
for Appendix D units. At least one utility group expressed interest in 
retaining the option to allow flexibility. The prime benefit to a 
facility from continuing to use daily manual sampling would appear to 
be that the facility could continue to use the same daily operating 
procedures and that reprogramming of a DAHS would not be necessary. 
Note that when using the approach of daily manual oil samples, a 
facility calculates SO2 mass emissions using the highest 
sulfur content in the previous 30 daily oil samples. Therefore, this 
approach requires more frequent analysis than either the proposed 
weekly composite sample for continuous samples or the proposed sampling 
by lot, and provides less accurate and more conservative results. The 
Agency believes it would be simpler and less confusing for both the 
Agency and for the regulated community to deal with a smaller number of 
approaches to sampling and calculating SO2 emissions. 
However, the Agency is retaining this option since at least some 
affected utilities want the flexibility to continue to use this option.
    EPA also considered the suggestion to define a 24-hour period as a 
lot in order to allow facilities to continue to perform daily manual 
sampling. EPA is not proposing this approach because of the added 
complexity, compared to keeping the current language in section 2.2.4 
of Appendix D concerning manual daily sampling of oil. If a lot were 
defined as an arbitrary 24-hour period, the other requirements in the 
current rule (e.g., conservative sulfur, gross calorific value, and 
density values used to calculate SO2 mass emission rate and 
heat input rate) would need to be retained to ensure that 
SO2 emissions were not underestimated. Furthermore, using 
the terminology of a ``lot'' for both a delivery and a period of time, 
while requiring different treatment of sample data from the two 
different types of ``lots,'' could potentially be confusing. It seems 
preferable to keep the current language for daily manual samples.
    Because the Agency now believes it is appropriate to sample each 
fuel lot instead of sampling daily, the Agency reconsidered whether 
daily composite samples are necessary when a facility performs 
automated continuous sampling. Because continuous samplers take fuel 
samples multiple times each hour, they are highly representative of the 
oil being burned. Flow proportional samplers take samples automatically 
when a certain volume or mass of fuel has passed by, rather than during 
a particular time period. Generally, automatic samplers take multiple 
samples each hour; however, only one sample per hour is required under 
section 2.2.3 of Appendix D of the current rule. Even if the 
compositing time period is extended, the composite sample will be 
representative of the sulfur content, density, and gross calorific 
value of the oil between samples. Therefore, the Agency believes

[[Page 28083]]

that the compositing period could be extended from a day to as long a 
period as a month. However, EPA believes that it is unlikely that any 
container for taking samples from an automatic sampler would be large 
enough to accommodate all automatic samples taken during a month. In 
addition, at least one industry representative suggested that weekly 
composite samples were appropriate (see Docket A-97-35, Item II-D-30). 
Therefore, in section 2.2.3 of today's proposed rule, EPA would extend 
the allowable length of the compositing period for automatic samples to 
one week. The Agency believes this will make automatic sampling less 
costly, while taking into account the physical limitations of sampling 
equipment.
    (b) Gaseous Fuels.
Background
    Section 2.3 of Appendix D, as revised in the May 17, 1995 direct 
final rule, provides only one approach for sampling gaseous fuel: under 
section 2.3.1, gaseous fuel sampling must be performed daily. 
Relatively few utilities perform daily sampling upon gaseous fuels, 
choosing instead to use a default SO2 emission rate for 
pipeline natural gas. In part, this is because the vast majority of 
gaseous fuel used by power plants is pipeline natural gas. Under 
section 2.3.2 of Appendix D, facilities may calculate SO2 
mass emissions from pipeline natural gas using a default emission rate 
instead of performing fuel sampling. Because of the difficulty and 
potential danger of sampling gaseous fuel, gas sampling is generally 
conducted by the supplier, rather than by the facility.
    Those few utilities combusting gaseous fuels other than pipeline 
natural gas have expressed concern about the difficulty and expense of 
daily sampling, particularly in comparison to the value of 
SO2 allowances for low SO2 emissions from 
relatively clean fuel (see, e.g., Docket A-97-35, Items II-E-11, II-E-
20). For gaseous fuels that are delivered in discrete batches or 
``lots,'' one would expect the gaseous fuel to behave like an ideal 
gas; sulfur should be evenly distributed throughout the batch. On this 
principle, the Ohio Environmental Protection Agency allowed a plant to 
take propane samples from each discrete delivery, rather than on a 
daily basis (see Docket A-97-35, Items II-C-14 and II-D-22).
Discussion of Proposed Changes
    Today's proposal incorporates three different sampling approaches 
for gaseous fuels: sampling by lot, daily sampling, and continuous 
sampling with a gas chromatograph. For gaseous fuel that is delivered 
in discrete lots, such as liquefied petroleum gas, the gaseous fuel 
could be sampled either daily or for each lot delivered. Any gaseous 
fuels other than pipeline natural gas that are not delivered in 
discrete lots, such as digester gas or sour natural gas pumped directly 
from a field, would, at a minimum, need to be sampled daily. The 
samples could be taken either by the supplier or by the facility. 
However, if the average sulfur content and sulfur variability of such a 
fuel were too high (i.e., mean sulfur content > 7 gr/100 scf and 
standard deviation from the mean > 5 gr/100 scf, based on 720 hours of 
representative historical data), continuous sampling with a gas 
chromatograph and hourly reporting of sulfur content would be required.
Rationale
    The approach of sampling upon a lot or discrete delivery of gaseous 
fuel is being incorporated into today's proposed rule for the following 
reasons. The Agency believes that discrete deliveries are sufficiently 
different from pipeline transmission of fuel that a different sampling 
approach is appropriate. According to the ideal gas law, all gas within 
an enclosed volume is mixed with a consistent composition; therefore, a 
single sample should be representative of all gas in the volume. 
Although gaseous fuels delivered by lot, such as liquefied petroleum 
gas, are higher in sulfur content and have a wider range of sulfur 
contents than pipeline natural gas, they still have relatively low 
sulfur contents compared to liquid and solid fuels. Thus, less frequent 
gas sampling appears appropriate, based on the small difference in the 
accuracy of calculated SO2 mass emissions. For this same 
reason, the Agency allowed as-delivered sampling for diesel fuel in the 
May 17, 1995 direct final rule (see Docket A-94-16, Item II-F-2). 
Finally, because of the difficulty of sampling gaseous fuels, EPA 
believes that it is less burdensome and less dangerous if gas sampling 
is conducted by the gas supplier. It is the Agency's understanding that 
the sampling for a gas in a discrete delivery or lot is typically 
conducted once for the lot, rather than on a daily basis. Through a 
petitioning process, EPA has already allowed one utility to perform 
sampling upon a lot or discrete delivery of gaseous fuel (see Docket A-
97-35, Items II-C-14 and II-D-22).
    EPA is proposing to require daily or continuous sampling of gaseous 
fuels other than pipeline natural gas or the equivalent that are not 
shipped in discrete lots, such as sour natural gas pumped directly from 
a field, landfill gas, or digester gas. Such gaseous fuels cannot be 
guaranteed to be stable in sulfur content. Therefore, proposed section 
2.3.3.4 in Appendix D would require a minimum of 720 hours of 
representative historical data to characterize the sulfur variability 
of such fuels. For the 720 hours of demonstration data, the mean value 
and standard deviation of the fuel sulfur content would be calculated. 
If the mean value does not exceed 7 gr/100 scf (equivalent to about 10 
ppm of SO2 emissions to the atmosphere), daily sampling 
would suffice. If the mean value is greater than 7 gr/100 scf, however, 
the variability of the sulfur content would be assessed in terms of the 
standard deviation. If the standard deviation exceeds 5 gr/100 scf, the 
sulfur variability would be considered too high and continuous sampling 
of the fuel with a gas chromatograph would be required. If continuous 
sampling were required, the owner or operator would have to implement a 
quality assurance program for the gas chromatograph. A copy of the QA 
plan would be kept on-site, suitable for inspection. For fuel with a 
low average sulfur content or a low sulfur variability, daily sampling 
would be sufficient. However, for gaseous fuel with a higher sulfur 
content, if the sulfur variability were too great, continuous sampling 
of the fuel with a gas chromatograph and hourly reporting of sulfur 
content would be required.
3. Sulfur, Density and Gross Calorific Value Used in Calculations
    (a) Fuel Oil.
Background
    The hourly SO2 mass emissions rate due to combustion of 
oil is calculated using the mass flow rate of oil combusted and a 
sulfur content value from a sample. If a unit's oil flow rate is 
measured with a volumetric fuel flowmeter rather than a mass fuel 
flowmeter, then it will be necessary to determine the mass flow rate of 
oil from the volume of fuel and a density value from an oil sample. The 
heat input rate is calculated using the flow rate of oil multiplied by 
the gross calorific value (GCV) of a sample.
    The sulfur content, density, and GCV used to calculate emissions 
and heat input depend upon the oil sampling method used. Some sampling 
methods are more accurate than others. For example, for flow 
proportional or continuous drip sampling, the actual sulfur content 
from a sample is used to calculate SO2 mass emissions. 
However,

[[Page 28084]]

when daily manual samples are taken under section 2.2.4 of Appendix D, 
a facility must use the highest fuel sulfur content recorded at that 
unit from the most recent 30 daily samples, which is not necessarily 
the sulfur content of the fuel being burned at any particular time. For 
units where diesel fuel is sampled upon delivery, section 2.2.1.2 
instructs a facility to calculate SO2 emissions using the 
highest sulfur content of any oil supply combusted in the previous 30 
days that the unit combusted oil. In daily manual sampling and as-
delivered sampling, conservative sulfur values are used to avoid the 
possibility of underestimating SO2 mass emissions due to 
variations in sulfur content. Gross calorific values are taken from the 
most recent sample, rather than using the highest value in the previous 
30 days, because, for natural gas, GCV is more consistent than sulfur 
content.
    Today's proposed rule includes changes to the sampling frequency 
for oil. Therefore, it is also necessary to make corresponding changes 
to the sulfur content, density, and GCVs to be used in calculations. 
For example, where oil samples would no longer be taken daily, it would 
be inappropriate to calculate SO2 mass emissions based upon 
a certain number of daily samples. In developing today's proposal, EPA 
considered what fuel analysis data values for sulfur content, density, 
and GCV would be appropriate and consistent with the approaches for 
taking manual samples. The appropriate sulfur content, density, and GCV 
values were considered for manual samples taken from a storage tank at 
the facility whenever fuel is added to the tank, for samples taken from 
each lot before the delivery is transferred from tank trucks or barges, 
and for samples taken from the fuel supplier's storage tank.
Discussion of Proposed Changes
    EPA has re-evaluated the sulfur content, density, and GCVs to be 
used to calculate SO2 mass emissions and heat input based 
upon the new oil sampling approaches. For daily manual oil sampling, a 
facility would continue to use the highest sulfur content from previous 
30 daily samples, and the actual density and GCV. For continuous oil 
sampling with an automatic sampler, a facility would continue to use 
the actual sulfur content, density, and GCV. For the two new methods of 
manual sampling, EPA considered whether conservative or actual values 
should be used to calculate emissions and heat input. EPA also 
considered whether the same type of calculational value should be used 
for sulfur content, density, and GCV. For example, if conservative 
sulfur content and density values are used to calculate the 
SO2 mass emission rate, should a conservative or an actual 
measured GCV be used to calculate the heat input rate?
    For manual samples taken from a storage tank at a plant whenever 
fuel is added to the tank, EPA considered the following options: (1) 
using the highest sulfur content and density from the previous three 
samples, and the actual GCV, (2) using the highest sulfur content from 
the previous three samples, and the actual density and GCV, (3) using 
the actual sulfur content, density, and GCV, (4) using the highest 
sulfur content, density, and GCV from the previous calendar year, and 
(5) using the maximum sulfur content, density, and GCV allowed by fuel 
purchase contract with the fuel supplier. The third, fourth, and fifth 
options are incorporated into today's proposal in section 2.2.4.2. 
Under this approach, a facility would take a sample from the storage 
tank whenever fuel is added to the tank. No blending of fuel would be 
allowed from the time the oil is sampled until the fuel is combusted by 
the unit. The sample would be analyzed for sulfur content, density, and 
GCV. Based on the selected option (3, 4, or 5), the appropriate values 
would then be used to calculate the SO2 mass emission rate 
and the heat input rate from the date and hour in which the transfer of 
oil is complete until the date and hour when oil is again added to the 
tank.
    EPA considered several different options for the case where a 
facility or its supplier would sample each oil delivery (or the 
supplier's storage tank) before the fuel is transferred into a tank at 
the plant. EPA considered whether or not these values needed to be 
conservative and concluded that there was a real possibility of 
underestimating SO2 emissions by using the fuel analysis 
values from a delivery. The options that EPA considered to avoid the 
underestimation were: (1) using the highest sulfur content and density 
from all samples taken from oil combusted during the previous 30 days, 
and the actual GCV, (2) using the maximum sulfur content, density, and 
GCV in the fuel purchase contract specifications, (3) using the highest 
sulfur content, density, and GCV from a sample taken in the previous 
calendar year, and (4) using the highest sulfur content, density, and 
GCV ever recorded for the unit. The second and third options are 
incorporated into today's proposed rule in section 2.2.4.3 of Appendix 
D.
    Under the selected options, a facility or its supplier would need 
to sample a delivery of fuel before it is transferred into a storage 
tank. The facility would then need to keep records of the fuel 
analytical results for three years. The facility would use the 
conservative value it selected under option (2) or (3), above, in order 
to calculate the SO2 mass emission rate and the heat input 
rate. If an as-delivered sample were ever analyzed and found to have a 
sulfur content, density, or GCV that exceeded the value being used in 
calculations (i.e., the contract specification, or the maximum value 
measured in the previous calendar year), then the new sampled value 
would be used to calculate the SO2 mass emission rate or the 
heat input rate, as follows. For a unit using a default value of the 
maximum value measured during the previous calendar year, that new 
sample value would become the new default value and would be reported 
for the remainder of the current year and the next year, unless 
superseded by a higher sampled value. For a unit using a default value 
of a contract specification, the new sample value would continue to be 
used as the new default value instead of the contract specification 
value, unless superseded by a higher sampled value or by a new 
contract.
Rationale
    EPA considers continuous sampling and the measurement of fuel from 
a storage tank at a plant after each addition of fuel to the tank to be 
highly accurate methods that will be representative of the fuel 
combusted in a unit. However, if samples are taken from the truck or 
barge used to ship the fuel, or if samples are taken ``as-delivered,'' 
the sample values will not necessarily accurately reflect the oil being 
combusted by the unit at any particular time (see Docket A-97-35, Item 
II-E-22). For example, a storage tank could contain oil with an average 
sulfur content of 0.6 percent. Then a new delivery with a sulfur 
content of 0.4 percent is received and transferred to the tank. The 
``as-delivered'' sample value from the delivery truck would 
underestimate the emissions at that time, since the fuel actually 
combusted will combine a mixture of the old fuel supply in the storage 
tank and the new fuel that is added. Thus, a more conservative sulfur 
value should be used to calculate SO2 emissions if samples 
are taken from the delivery containers or from a container used by the 
oil supplier.
    For density and GCV, today's proposal, at the suggestion of some 
industry representatives, uses conservative values determined by the 
same method for both parameters (see Docket A-97-35, Item II-E-24). 
This

[[Page 28085]]

has the advantage of being easy to remember and to program. However, if 
greater accuracy is desired, a facility would always have the option of 
using actual sulfur content, density, and GCVs if it took samples from 
its storage tank after each addition of fuel to the tank, or if it took 
continuous, automatic samples.
    EPA considered which conservative values would be appropriate for 
sulfur, density, and GCV. EPA at first considered using the maximum 
value from all oil supplies combusted in the previous 30 days. This is 
similar to the current wording of section 2.2.1.2 of Appendix D for 
calculation of SO2 emissions from diesel fuel as-delivered 
sampling. However, in the process of implementing this provision of 
part 75, EPA found this wording was somewhat confusing and issued 
policy guidance to clarify section 2.2.1.2 of Appendix D (see Docket A-
97-35, Item II-I-9, Policy Manual, Question 2.9). This policy 
essentially directs facilities to keep track of the amount of fuel used 
as well as its sulfur content. Because of the more complicated nature 
of this accounting, some industry representatives suggested that it 
would be simpler to use a conservative default value that would not 
require tracking fuel usage (see Docket A-97-35, Item II-E-24). Of the 
default values considered, EPA felt that the most appropriate default 
values would be the maximum values established by agreement with the 
fuel supplier through a contract or the maximum measured value from all 
samples in the previous calendar year. Contractual limits should be 
higher than or equal to the actual sulfur content, density, or GCV. 
Because not all units would necessarily have a fuel contract limiting 
oil sulfur content, density, or GCV, EPA is also proposing to provide 
the option of using the maximum oil sulfur content, density, or GCV in 
the previous calendar year.
    The Agency also considered whether the current provisions of 2.2.4 
of Appendix D should be retained for calculation of SO2 
emissions using the highest sulfur from the previous 30 daily samples 
when performing daily manual sampling. As discussed above in Section 
III.P.2(a) of this preamble on oil sampling frequency, the Agency is 
proposing to retain the option as requested by at least one utility 
representative.
    (b) Gaseous Fuels.
Background
    The vast majority of Acid Rain units which burn gaseous fuels 
combust pipeline natural gas. Section 2.3.2 of Appendix D contains a 
provision for calculation of SO2 mass emissions from 
pipeline natural gas using a default SO2 emission rate in 
lb/mmBtu and the heat input rate of pipeline natural gas. However, if a 
facility or its supplier is sampling gaseous fuel for sulfur content, 
either because it is not pipeline natural gas or because the facility 
chooses to use a sampled value, then Appendix D requires the facility 
to calculate the SO2 mass emission rate using the sulfur 
content of the sample and the volume of gas combusted, and to calculate 
the heat input using the GCV of the sample and the volume of gas 
combusted (see Equations D-5 and F-20). Because of the nature of 
gaseous fuels, they are always measured with a volumetric fuel 
flowmeter. The formulas for calculating the SO2 mass 
emission rate and the heat input rate use volume directly and do not 
require information on gas density. The current provisions of Appendix 
D allow a facility to calculate the SO2 mass emission rate 
and the heat input rate using the actual value from a daily sample of 
gaseous fuel.
    When the provisions of section 2.3 of Appendix D were added to part 
75 in the May 17, 1995 direct final rule, EPA presumed that virtually 
every utility combusting gaseous fuel was combusting pipeline natural 
gas. However, the Agency found that utilities were combusting other 
types of gaseous fuels. One utility submitted a monitoring plan and a 
certification application for fuel flowmeter monitoring systems that 
indicated the utility was also using propane liquefied petroleum gas 
(LPG) (see Docket A-97-35, Item II-D-6). The utility indicated that it 
wished to use the default emission rate factor reserved for pipeline 
natural gas in its monitoring plan and later petitioned the Agency 
specifically for permission to use the default emission rate factor of 
0.0006 lb/mmBtu. In conversations with utility staff, EPA found that 
the utility wanted to avoid the expense of additional daily samples and 
the trouble of entering daily sulfur values manually into its data 
acquisition and handling system (see Docket A-97-35, Items II-E-11, II-
E-20). The Agency eventually approved a revised petition for the 
utility that allowed the utility to take propane samples from each 
discrete delivery, rather than on a daily basis, where the utility 
calculates sulfur dioxide emissions from propane by using the highest 
sulfur content recorded during the previous 365 days and reports these 
data in its quarterly electronic data report (see Docket A-97-35, Items 
II-C-14 and II-D-22).
    The Agency found that there were also some utilities burning 
gaseous fuels that were by-products of an industrial process (see 
Docket A-94-16, Item II-D-71). EPA had concerns that such ``digester 
gas'' might have a more variable sulfur content than pipeline natural 
gas, since the gaseous fuel would begin with a higher sulfur content 
than pipeline natural gas and would not necessarily go through a 
process that would reduce and stabilize the sulfur content.
Discussion of Proposed Changes
    In today's proposed rule, the provisions for sampling gaseous fuels 
are found in section 2.3.1 of Appendix D. For gaseous fuels that are 
delivered in discrete lots, a facility would use conservative values 
for sulfur content and GCV to calculate the SO2 mass 
emission rate and the heat input rate. For the sulfur content value, 
the highest sampled sulfur content from the previous calendar year or 
the maximum value allowed by contract would be used to calculate the 
SO2 mass emission rate. For GCV, the highest of all sampled 
values in the previous calendar year or the maximum value allowed by 
contract would be used to calculate the heat input rate. If, for any 
gas sample, the assumed sulfur content or GCV were exceeded, the 
sampled value would become the new assumed value. For units using the 
contract value, the sampled value would continue to be used unless a 
new (higher) contract specification were put in place or unless an even 
higher sampled value is obtained. For units using the maximum value 
from the previous year, the sampled value would continue to be used for 
the remainder of the current year and for the next calendar year unless 
it was superseded by an even higher sampled value.
    For any gaseous fuel where daily fuel sampling is required, a 
facility would use the highest sulfur in the previous 30 daily samples. 
For gaseous fuels other than pipeline natural gas, where daily sampling 
of sulfur content is required, the highest GCV from the previous 30 
daily samples would be used. For pipeline natural gas, where monthly 
sampling of GCV only is required, the actual measured GCV, the highest 
of all sampled values in the previous calendar year, or the maximum 
value allowed by contract would be used.
    For a gaseous fuel that is not produced in batches and that has a 
relatively high sulfur content and a high sulfur variability, 
continuous sampling with a gas chromatograph would be required. Sulfur 
content would be reported as actual measured hourly average values. The 
GCV would also be determined on an hourly basis, or,

[[Page 28086]]

alternatively, the highest value in the previous 30 unit operating days 
could be reported.
Rationale
    For gaseous fuel supplied in discrete deliveries, EPA is proposing 
to take the same approach as for fuel oil that is being delivered to a 
plant by barge or truck. EPA has already approved this approach with 
one utility that combusts liquefied petroleum gas (see Docket A-97-35, 
Items II-C-14 and II-D-22). Because a discrete delivery of gaseous fuel 
would be maintained in an enclosed chamber with a relatively constant 
temperature and pressure, one would expect the gaseous fuel to behave 
like an ideal gas. Thus, sulfur and other constituents of the fuel 
should be evenly distributed throughout the delivery of fuel. Using 
conservative values to calculate the SO2 mass emission rate 
and the heat input rate should account for any variability between 
deliveries. Furthermore, this reduces the number of changes that would 
be made to a data acquisition and handling system to add fuel supply 
data.
    For gaseous fuel other than pipeline natural gas, where daily fuel 
sampling is required, EPA considered leaving unchanged the current 
provisions of section 2.3.1 of Appendix D that would allow a utility to 
use the actual value from a day's sample to calculate the 
SO2 mass emission rate and the heat input rate. However, the 
Agency believes that it is appropriate to change the sulfur content 
value to be a somewhat conservative historical value. This is because 
the Agency has concerns that there may be some gaseous fuels other than 
natural gas, such as digester gas, that may have significant 
variability in their sulfur content over the course of a day or a 
longer period of time. This might result in the underestimation of the 
SO2 mass emission rate.
    In the case of fuel oil, some industry representatives suggested it 
was simplest to determine the appropriate conservative values for 
sulfur content, density, and GCV by the same method (see Docket A-97-
35, Item II-E-24). With one exception (for fuels with relatively high 
sulfur content and high sulfur variability), today's proposal follows 
this suggestion for gaseous fuels. The proposal uses the highest sulfur 
content and the highest GCV from the previous 30 daily samples. This is 
currently the procedure used to determine the sulfur value used in 
calculations from daily manual oil samples. Since this algorithm for 
daily manual oil sample calculations is already being used by many 
software programmers, it is a good conservative value to use for daily 
samples in this case. The Agency notes that currently, the heat input 
is calculated using the actual sampled GCV and that this change would 
require software reprogramming for units where gaseous fuel is sampled 
daily. However, for pipeline natural gas that is sampled monthly for 
GCV, facilities could continue to use the actual GCV measured in a 
monthly sample. The other two options are more conservative and would 
require software changes. The Agency requests comment on the proposal 
to use the more conservative GCV value to determine the heat input rate 
for gas combustion when gaseous fuel is sampled daily (which differs 
from the current procedure in section 2.3.1.3 of Appendix D and section 
5.5.2 of Appendix F).
    For gaseous fuel that has a relatively high sulfur content and high 
sulfur variability, daily sampling is not considered adequate to ensure 
that SO2 emissions will not be underestimated. Therefore, 
for such fuels, continuous sampling with a gas chromatograph and hourly 
reporting of sulfur content would be required. For GCV, which is 
expected to be less variable than sulfur content, either the actual 
hourly measured value or the highest GCV value obtained in the last 30 
unit operating days could be reported.
4. Missing Data Procedures for Sulfur, Density, and Gross Calorific 
Value
Background
    (a) Fuel Oil. The May 17, 1995 direct final rule included missing 
data procedures for missing analytical information on sulfur content, 
density, and GCV in section 2.4 of Appendix D. These procedures are 
based on a daily sampling frequency. For example, missing sulfur 
content, density, or GCV data are to be calculated using the highest 
measured sulfur content, oil density, or GCV during the previous thirty 
days when the unit burned oil. This was intended to mean that the 
substitute data values are to be based on the previous thirty daily oil 
samples for which data are available.
    In order to ensure that a DAHS is capable of implementing the 
missing data procedures required by the rule, Sec. 75.20(c)(7) and 
Sec. 75.20(g)(1)(ii) require testing of each DAHS. EPA issued policy 
guidance discussing how facilities should report the results of these 
tests for units measured with fuel flowmeters. This policy guidance 
provided a form checklist that facilities could use to show the results 
of their own tests of the missing data substitution procedures (see 
Docket A-97-35, Item II-I-9, Policy Manual, Question 15.9). Some 
utilities objected to testing the DAHS missing data procedures on the 
grounds that they should never miss sample data. In part, this would be 
because the facility is required, under section 2.2.5 of Appendix D, to 
split its sample and keep a portion. One utility offered to substitute 
the maximum potential sulfur content, which would require less 
complicated DAHS programming than using the maximum sulfur content of 
the previous 30 daily samples.
    (b) Gaseous Fuels. Section 2.4.1 of Appendix D, as revised by the 
May 17, 1995 direct final rule, provides missing data substitution 
procedures for missing sulfur data from daily samples of gaseous fuel. 
The DAHS is required to substitute the highest measured sulfur content 
recorded during the previous 30 days when the unit combusted gaseous 
fuel. As for oil, this was intended to be the highest sulfur value from 
the previous 30 daily samples with available sulfur values. Section 
2.4.2 of Appendix D requires the substitution of the highest measured 
GCV recorded during the previous three months that the unit burned 
gaseous fuel when data are missing from a monthly gaseous fuel sample. 
As for fuel oil, the missing data procedures for gaseous fuels are 
linked to the frequency of fuel sampling.
    A utility indicated to EPA that because it receives gas sampling 
information from its supplier, it should never have missing data for 
GCV. The utility suggested that it should not have to go to the expense 
of programming its DAHS for missing data procedures that should never 
need to be used. This argument was similar to that used by another 
utility when referring to missing data procedures for manual samples of 
fuel oil taken upon each delivery.
Discussion of Proposed Changes
    EPA proposes to revise the missing data substitution procedures for 
both fuel oil and gaseous fuel, in order to simplify them. For any 
instance in which the sulfur content, GCV, or density value is missing, 
the maximum potential value would be reported until the results of a 
subsequent valid sulfur content analysis, GCV determination, or density 
measurement are obtained. The proposed appropriate maximum potential 
values are specified in the table below. The default values for sulfur 
content, GCV, and density of residual oil and diesel fuel were taken 
from handbook values (see Docket A-97-35, Item II-A-7). The default 
maximum sulfur content values for gaseous fuel are consistent with the 
maximum sulfur content allowed under

[[Page 28087]]

the definition of natural gas and the de facto maximum sulfur content 
of pipeline natural gas, based on the proposed definition. Thus, any 
gas with a sulfur content that did not allow it to qualify as pipeline 
natural gas (i.e., greater than 0.30 gr/100 scf) but still allowed it 
to be measured following Appendix D procedures (i.e., total sulfur 
content not exceeding 20.0 gr/100 scf) would have a default maximum 
potential sulfur content of 20.0 gr/100 scf. The default values for GCV 
of gaseous fuels were taken from handbook values (see Docket A-97-35, 
Item II-I-1). For pipeline natural gas, it is assumed that the gas is 
primarily methane (GCV of 1050 Btu/scf) with a small amount of other 
hydrocarbons with a higher GCV (see Docket A-97-35, Item II-E-19). For 
other gaseous fuels, it is assumed that they are primarily butane (GCV 
of 2100 Btu/scf), the hydrocarbon gas with the highest GCV of gases 
commercially used for fuel.

                   Maximum Potential Default Values for Sulfur Content, Density, and GCV Data                   
----------------------------------------------------------------------------------------------------------------
                Parameter                             Fuel                  Maximum potential  default value    
----------------------------------------------------------------------------------------------------------------
Sulfur content..........................  residual oil...............  3.5 percent by weight.                   
                                          diesel fuel................  1.0 percent by weight.                   
                                          pipeline natural gas.......  0.30 gr/100 scf.                         
                                          gaseous fuels with sulfur    20.0 gr/100 scf.                         
                                           content greater than                                                 
                                           pipeline natural gas.                                                
GCV/heat content........................  residual oil...............  19,500 Btu/lb.                           
                                          diesel fuel................  20,000 Btu/lb.                           
                                          pipeline natural gas.......  1100 Btu/scf.                            
                                          gaseous fuels with sulfur    2100 Btu/scf.                            
                                           content greater than                                                 
                                           pipeline natural gas.                                                
Oil Density.............................  residual oil...............  8.5 lb/gal,                              
                                          diesel fuel................  7.4 lb/gal.                              
----------------------------------------------------------------------------------------------------------------

Rationale
    (a) Fuel Oil. It seems possible that a facility might occasionally 
miss a sample taken with an automatic sampler, and thus, would have 
missing data. Therefore, today's proposal includes a provision for 
substitution of missing sulfur content, density, and GCV data from 
continuous, automatic sampling.
    Based upon comments from some utilities, it seems relatively 
unlikely that both a facility and its supplier would miss performing a 
sample during a delivery. Both a facility and its fuel supplier will 
want to verify that the fuel delivered is actually supplying the heat 
content that it is supposed to, either under a contract or a fuel 
specification; thus, both a facility and its fuel supplier will have an 
incentive to ensure sampling takes place for a delivery. Furthermore, 
if samples taken by a facility are split, then there should generally 
be the ability to provide analytical data for that fuel, even if test 
results were somehow lost. Because the event of missing fuel samples is 
unlikely for as-delivered samples, EPA believes that it would be 
appropriate to establish a simple, conservative value that could easily 
be substituted in a data acquisition and handling system. This would be 
easier to program than using historical values that require tracking 
fuel usage over an extended period of time.
    EPA is specifically proposing the most conservative (maximum 
potential) values for missing data purposes. This would ensure that 
substituted missing data values would be less advantageous to a 
facility than taking samples and using sulfur content, density, and GCV 
data from samples. In addition, several utilities suggested to EPA that 
this was a reasonable approach (see Docket A-97-35, Item II-E-24).
    (b) Gaseous Fuels. As mentioned previously, gas sampling is 
generally performed by fuel suppliers because of the difficulty and 
potential danger of opening up a pressurized pipe containing a highly 
flammable gas. It seems extremely unlikely that a fuel supplier would 
not have information available on the sulfur content or GCV of gaseous 
fuel, since industrial customers will purchase fuel or agree to a 
contract based upon these characteristics. The exception to this might 
be gaseous fuel manufactured through an industrial process that is not 
produced specifically for sale as a fuel, such as digester gas. In 
today's proposed rule, EPA is using the same reasoning as above for 
missing manual fuel oil sample data and is using the same basic 
substitution approach for missing sulfur content and GCV data for 
gaseous fuel.
    EPA considered keeping the existing missing data substitution 
procedures from sections 2.4.1 and 2.4.2 of Appendix D for missing data 
from gaseous fuel. This would have the advantage of requiring no 
reprogramming of software for facilities already following the existing 
procedures. EPA also considered using the maximum sulfur content or GCV 
from the previous calendar year, the same procedure proposed in today's 
rule for calculation of SO2 mass emission rate or heat 
input, for discrete deliveries of gas or for manual samples of oil 
taken from a delivery truck or barge. However, using the proposed 
maximum value would require little reprogramming and would greatly 
simplify the missing data procedures. In policy guidance, the Agency 
has indicated it would accept a simplified DAHS for units using the 
procedures of Appendices D and E. In particular, these policies endorse 
manual entry of fuel analytical data, simplified missing data 
procedures for fuel flowmeters, and a DAHS that uses commercial 
spreadsheet software instead of a specialized custom software for 
purposes of part 75 (see Docket A-97-35, Item II-I-9, Policy Manual, 
Questions 14.72 and 14.73). In keeping with the policy of allowing 
Appendices D and E units to use commercial spreadsheet software, EPA 
has proposed what it believes to be the simplest possible missing data 
substitution procedure for missing sulfur content and GCV data. In 
addition, using the proposed maximum potential sulfur content or GCV 
would ensure that substituted missing data values are more conservative 
than the values normally used to calculate the SO2 mass 
emission rate and the heat input rate.

[[Page 28088]]

5. Installation of Fuel Flowmeters for Recirculation
Background
    The current provisions of section 2.1.1 of Appendix D require the 
use of an additional ``return'' fuel flowmeter when some fuel is 
recirculated, i.e., initially sent toward a unit and then diverted away 
from the unit without being burned. This additional fuel flowmeter is 
required, regardless of the amount of fuel being diverted.
    At least one utility has requested to use only the fuel flowmeter 
measuring fuel leaving the oil tank without a second fuel flowmeter to 
measure any fuel diverted away by the recirculation fuel line. The 
utility argued that using a single fuel flowmeter would result only in 
the overestimation of SO2 emissions, since the utility would 
measure a larger amount of fuel usage. This would allow the facility to 
avoid the expense of installation, certification, and quality assurance 
testing on a fuel flowmeter on the recirculation fuel line. Since the 
proportion of fuel being recirculated was minimal, the utility was 
willing to use a more conservative SO2 emissions calculation 
in exchange for devoting fewer resources for the testing and 
maintenance of the recirculation line fuel flowmeter.
Discussion of Proposed Changes
    In today's proposal, EPA proposes to allow facilities to use only a 
fuel flowmeter on the main fuel line from the oil tank if the amount of 
oil recirculated is demonstrated to be less than 5.0 percent of total 
fuel usage for each hour during the year.
Rationale
    EPA believes that it is reasonable not to require installation, 
certification and quality assurance of secondary fuel flowmeters in 
cases where the amount of fuel to be combusted is a small proportion of 
the total fuel used, and where knowing the exact volume of the 
recirculated fuel makes little difference in the calculation of 
emissions and heat input. EPA has allowed one utility to use an 
estimate of the maximum oil usage at start-up, rather than requiring 
the utility to install a return line oil flowmeter to measure the 
startup fuel flow rate.
    At first, EPA considered making the installation of a fuel 
flowmeter on a recirculation fuel line optional. Presumably, if the 
cost in lost SO2 allowances were greater than the cost of 
installing and maintaining a fuel flowmeter, then a facility would 
choose to use a fuel flowmeter on the recirculation fuel line. However, 
many fuel flowmeters used under Appendix D for determining the 
SO2 mass emission rate and the heat input rate are also used 
to estimate the NOX emission rate in lb/mmBtu under Appendix 
E to part 75. The Appendix E procedures estimate hourly NOX 
emission rates using a correlation between measured NOX 
emission rates and heat input rates. The correlation is established 
during a testing period. Therefore, subsequent to the test period, if 
the hourly heat input values should become less accurate, it could 
result in the estimated NOX emission rates becoming less 
accurate. Such loss in accuracy could occur if the heat input rates 
during the initial testing period were based upon subtraction of 
measured volumes or masses of recirculated fuel from the total fuel 
flow rates, and then the facility later began estimating, rather than 
measuring, the recirculated fuel volumes or masses. The potential 
inaccuracy would increase if the proportion of recirculated oil to the 
total flow rate of oil varies over time. The NOX emission 
rate can sometimes increase with increases in the heat input rate and 
can sometimes decrease with increases in the heat input rate, depending 
on the particular type of boiler; in addition, when certain types of 
control equipment are installed, the NOX emission rate may 
not have any relationship with the heat input. Thus, an overestimation 
of the heat input rate would sometimes result in the overestimation and 
sometimes result in the underestimation of the NOX emission 
rate under Appendix E. For these reasons, EPA believes that there needs 
to be some limits on the cases where a facility can choose not to use a 
return fuel flowmeter.
    In today's proposed rule, EPA is proposing that a facility may 
choose to use only a fuel flowmeter on the main fuel line from the oil 
tank and not install a return meter in those cases where the previously 
measured proportion of oil from the recirculation line is less than or 
equal to 5.0 percent of the unit's total oil usage during each hour of 
the year. EPA believes that an error of 5.0 percent in the heat input 
rate should be small enough that it will not significantly affect 
accounting for the NOX emission rate under Appendix E. An 
analysis of emissions data from a gas-fired Appendix E unit with a 
higher than average NOX emission rate for gas (0.157 lb/
mmBtu) showed that a 5.0 percent increase in heat input would change 
the quarterly average NOX emission rate by only 3.17 percent 
(0.152 vs. 0.157 lb/mmBtu) (see Docket A-97-35, Item II-B-19). At the 
same time, EPA believes that an average proportion of 5.0 percent of 
total fuel usage should provide relief for the most extreme situations 
where it might cost more to perform quality assurance testing on a 
return fuel flowmeter than the value of the allowances saved by 
monitoring with the return flowmeter.
    The Agency also considered whether it would be more appropriate to 
determine the proportion of recirculated fuel on an hourly average 
basis or on an annual average basis to determine if the returned fuel 
was less than 5.0 percent of total fuel usage. The Agency concluded 
that the proportion of fuel could be determined only if a return fuel 
flowmeter were already installed on the recirculation fuel line. Thus, 
there would appear to be little advantage to basing the proportion of 
fuel on an annual basis. Hourly average fuel flow rate would also be 
more directly related to the heat input rate used to calculate hourly 
NOX emission rate under Appendix E. EPA notes this is not 
fully consistent with the objective of revising this provision, i.e., 
to exempt facilities from installation and operation of additional fuel 
flowmeters. Therefore, the Agency believes it is better to base the 
reduced fuel flow rate monitoring requirement either on actual 
historical fuel flowmeter data or on some other method, as yet unknown, 
that would yield a reasonable estimate of the average proportion of 
fuel recirculated to the total amount of fuel used. At this time, the 
Agency is unaware of what other methods could provide a reasonable 
estimate of the average proportion of fuel recirculated to the total 
amount of fuel used, either on an hourly or an annual basis. 
Accordingly, the Agency would allow facilities to suggest methods 
through the petitioning process of Sec. 75.66.
6. Fuel Flowmeter Testing
    (a) Fuel Flowmeter Accuracy Tests.
Background
    Sections 2.1.5 and 2.1.6 of Appendix D, as revised by the May 17, 
1995 direct final rule, refer to calibration and recalibration of fuel 
flowmeters. Section 2.1.5.2 gives procedures for a test of the 
flowmeter accuracy by comparing a candidate flowmeter against another 
flowmeter that has already been calibrated according to specified 
procedures. If a flowmeter does not meet the specified accuracy, then 
it would need to be recalibrated by adjusting it, then retested to 
ensure it is reading accurately.
    Some utilities have found confusing the terminology of 
``calibration'' for a test that compares measurements from two 
different flowmeters. Generally, the

[[Page 28089]]

term ``calibration'' is used to refer to adjustments made to a 
flowmeter to ensure it is reading accurately. However, the type of test 
described in section 2.1.5.2 is more like a relative accuracy test 
audit than a calibration, in that it checks the flowmeter accuracy by 
comparing the fuel flowmeter readings against readings from an outside 
standard.
Discussion of Proposed Changes
    To alleviate the confusion surrounding flowmeter testing, today's 
proposal introduces the term ``flowmeter accuracy test.'' This 
terminology is used in sections 2.1.5 and 2.1.6 of Appendix D.
Rationale
    EPA believes that the term ``flowmeter accuracy test'' more clearly 
reflects the nature of the test that is performed. Introducing this new 
term also will clarify that the word ``calibration'' refers to 
flowmeter adjustments, rather than to a comparative test between a 
candidate flowmeter and a reference meter.
    (b) Methods for Fuel Flowmeter Accuracy Testing.
Background
    Section 2.1.5.1 of Appendix D, as revised by the May 17, 1995 
direct final rule, includes a list of standards and procedures that may 
be used to determine if a flowmeter is sufficiently accurate for use 
under the Acid Rain Program. However, because of the large number of 
different brands and kinds of fuel flowmeters, there are also many 
manufacturers' procedures that are not explicitly permitted under part 
75. Consequently, many Acid Rain certification applications for units 
with fuel flowmeters have contained petitions under Secs. 75.23 and 
75.66 for approval of other fuel flowmeter testing procedures. Among 
those methods was AGA Report No. 7 for turbine flowmeters. This method 
was incorporated by reference into part 75 in the November 20, 1996 
final rule. In addition, another standard method that EPA approved 
through petitions is American Petroleum Institute (API) Section 2, 
``Conventional Pipe Provers,'' from Chapter 4 of the Manual of 
Petroleum Measurement Standards, October 1988 edition (see reproduction 
of this document in Docket A-97-35, Item II-D-10 (Attachment B)).
    In the process of implementing part 75, many utilities have 
commented on the problems of testing and calibrating fuel flowmeters. 
Unlike CEMS or stack flow monitors, it is not always possible to 
perform an accuracy test with the fuel flowmeter remaining in the pipe 
where it is installed. Utilities have stated that certain fuel 
flowmeters are extremely difficult to remove, send out for testing, 
recalibrate, and then reinstall (see Docket A-97-35, Item II-E-22). In 
addition, removing a fuel flowmeter from in-line may require stopping 
flow of the fuel and possibly shutting down the unit, with negative 
economic consequences (see Docket A-97-35, Item II-E-8). In addition, 
if a facility needs to operate a unit while the flowmeter is being 
tested at a laboratory, then no flow data will be available for the 
fuel measured by the flowmeter unless the facility has a backup fuel 
flowmeter. Utilities have petitioned for alternative quality assurance 
procedures for fuel flowmeters in order to avoid the inconvenience and 
expense of removing the fuel flowmeter and testing it (see Docket A-97-
35, Item II-D-9). Because of this, the Agency has been evaluating 
various ways of testing a fuel flowmeter in-line (that is, still 
installed in the pipe in its regular position).
    Some utilities have suggested that an alternative way to check fuel 
flowmeter accuracy would be to compare over time the ratio of the fuel 
flowrate to unit output (``load''), measured either in electrical 
generation in MWe or in steam flow in 1000 lb/hr (see Docket A-97-35, 
Item II-E-21). A fuel flow-to-load comparison could be used to 
determine if fuel flowmeter readings are still similar to the readings 
obtained the last time the fuel flowmeter was tested against an outside 
method. A significant change in the amount of fuel used at a load level 
would call into question the validity of fuel flow readings from a 
flowmeter. A fuel flow-to-load comparison could provide this check 
without removal of the fuel flowmeter from its installed location, 
which would be of considerable benefit to facilities.
Discussion of Proposed Changes
    EPA is proposing to incorporate by reference the standard: American 
Petroleum Institute (API) Section 2, ``Conventional Pipe Provers,'' 
from Chapter 4 of the Manual of Petroleum Measurement Standards. The 
Agency also specifically requests comment on any other voluntary 
consensus standards from standard setting organizations, such as API, 
AGA, ASME, or ISO, that would be appropriate for incorporation by 
reference into part 75. Any suggested methods should also be submitted 
to the Agency as part of the comments to assist in the Agency's 
evaluation.
    Section 2.1.7 of Appendix D to today's proposed rule includes 
provisions for an optional, supplemental quality assurance test for 
fuel flowmeters using a ratio of the fuel flow rate and the unit load. 
The fuel flow rate-to-load ratio comparison test would provide an 
additional way to meet the requirement to periodically test fuel 
flowmeter accuracy. This test would serve as a supplement to more 
rigorous fuel flowmeter tests. These more rigorous tests include the 
standards incorporated by reference under section 2.1.5.1 of Appendix D 
that require the fuel flowmeter to be taken out of line and shipped to 
a laboratory, and the ``master meter'' comparison procedures under 
section 2.1.5.2 of Appendix D. For orifice-, nozzle-, and venturi-type 
flowmeters, the more rigorous tests would include an inspection of the 
primary element and an accuracy test on the transmitters or 
transducers. If a facility performed and passed regular quarterly fuel 
flow-to-load ratio testing, then it would need to perform the more 
rigorous checks on monitor performance only once every 20 calendar 
quarters (five years).
    The fuel flow-to-load ratio test would require a facility to 
establish a baseline period from a period of time when the fuel 
flowmeter is known to be operating properly. After establishing this 
baseline of accurate fuel flow data (or heat input rate data), a 
facility would calculate the fuel flow-to-load ratio (or ``gross heat 
rate'' (GHR)) during the baseline period. In each ``flowmeter operating 
quarter'' that the fuel flowmeter operates after the baseline period is 
completed, the facility would calculate the fuel flow-to-load ratio (or 
GHR) for each hour the fuel flowmeter is used to report data. The 
facility would compare the hourly fuel flow-to-load ratio (or GHR) to 
the fuel flow-to-load ratio (or GHR) during the baseline period in 
order to calculate the absolute value of the percentage difference for 
each hour. Next, the facility would calculate the average percentage 
difference for the quarter. If the percentage difference exceeded the 
specified limits for the test, the fuel flowmeter would fail the test. 
The key elements of the fuel flow rate-to-load evaluation are discussed 
in the following paragraphs.
    (1) Use of Gross Heat Rate-to-Load Ratio. Today's proposed rule 
would allow a facility the option of calculating either the ratio of 
the fuel flow rate to the gross generation in MWe or the steam flow 
rate in thousands of pounds of steam per hour (``fuel flow-to-load 
ratio'') or the ratio of the heat input rate to the gross generation in 
MWe or the steam flow rate in thousands of pounds of steam per hour 
(``GHR''). In order to allow a meaningful comparison, a facility would 
use one of these two ratios consistently, both in calculating

[[Page 28090]]

an initial baseline ratio and in calculating hourly ratios during a 
particular quarter. Equations D-1c and D-1e describe the calculation of 
the fuel flow-to-load ratio for the baseline period and for hourly 
values during a calendar quarter, respectively. For the GHR, the 
respective equations are Equations D-1d and D-1f. These equations are 
found in proposed sections 2.1.7.1 and 2.1.7.2 of Appendix D.
    (2) Baseline Period for Fuel Flow-to-Load Ratio. The provisions for 
calculating the baseline fuel flow-to-load ratio or gross heat rate are 
found in section 2.1.7.1 of today's proposed rule. EPA is proposing 
that the owner or operator of a facility would establish a baseline of 
fuel flow rate (or heat input rate) data following a flowmeter accuracy 
test under either section 2.1.5.1 or 2.1.5.2 of Appendix D, or 
following both a transmitter or transducer accuracy test under section 
2.1.6.1 of Appendix D and an inspection of a primary element for an 
orifice-, nozzle-, or venturi-type fuel flowmeter under section 
2.1.6.6. Throughout section 2.1.7 of today's proposed rule, these are 
referred to as ``the most recent quality assurance procedure(s).'' The 
baseline period of fuel flow rate (or heat input rate) data for a fuel 
flowmeter to be tested under section 2.1.7 would use the first 168 
hours of quality assured data measured by that flowmeter following the 
most recent quality assurance procedure(s) for which: (1) only the fuel 
measured by that fuel flowmeter is combusted (i.e., no co-firing of 
fuels occurs); (2) the load is relatively stable and not ``ramping'' 
rapidly up or down; and (3) the load is sufficiently above the minimum 
safe, stable operating load (unless low-load operation is normal for 
the unit).
    Today's proposal includes a limit to the length of time over which 
the baseline period could extend. The baseline period of 168 hours 
could not extend for longer than the end of the second calendar quarter 
following the calendar quarter in which the most recent quality 
assurance procedure(s) was performed. For orifice-, nozzle-, and 
venturi-type fuel flowmeters, two quality assurance procedures would be 
required: both a transmitter or transducer accuracy test under section 
2.1.6.1 of Appendix D and an inspection of a primary element, such as 
an orifice plate. For practical purposes, this means that the 
transmitter or transducer accuracy test and the primary element 
inspection would have to be completed either in the same calendar 
quarter or in consecutive calendar quarters. If there were not 168 
hours of quality-assured fuel flowmeter data from hours when a single 
fuel is combusted, then the fuel flowmeter would not be allowed to be 
tested using the fuel flow-to-load ratio as a supplement to other 
quality assurance tests.
    The 168 hours of quality-assured fuel flowmeter data next would be 
averaged and divided by the average load, in megawatts or 1000 lb 
steam/hr, during the same 168 hours to determine the baseline fuel 
flow-to-load ratio (see Equation D-1c). Alternatively, the facility 
could instead calculate the gross heat rate by averaging hourly heat 
input rate during the 168 hours of the baseline period and by dividing 
the average heat input rate by the average load during the same 168 
hours (see Equation D-1d).
    In cases where the fuel flowmeter is located on a common pipe 
header, one fuel flow rate measurement could be associated with the 
load from several units that receive fuel from the common pipe header. 
In order to analyze the fuel flow-to-load ratio for a flowmeter on a 
common pipe header, the load from all units receiving fuel from the 
common pipe header would have to be combined for each hour, averaged 
over the baseline period of 168 hours, and compared to the average fuel 
flow rate during the baseline period. If a single unit receives fuel 
from multiple pipes, each pipe with its own fuel flowmeter, then the 
flow rates from all fuel flowmeters would have to be added together to 
obtain the average fuel flowrate for the unit to be divided by the unit 
load.
    (3) Data Preparation and Analysis. In each flowmeter operating 
quarter following the final quarter of the baseline period, all hourly 
fuel flowmeter data would be compared to the load. A flowmeter 
operating quarter would be a calendar quarter in which the unit 
combusts the fuel measured by the fuel flowmeter for at least 168 
hours. For each hour in which the fuel is combusted, the owner or 
operator would calculate the fuel flow-to-load ratio (or GHR) (see 
Equation D-1e for the fuel flow-to-load ratio and Equation D-1f for the 
GHR). Hourly fuel flow rates on common pipe headers would be compared 
to the sum of the loads from all units receiving fuel from the common 
pipe header. For units with multiple pipes and multiple fuel 
flowmeters, the total hourly fuel flow rate for the fuel would be 
compared to the unit load.
    Next, the facility would compare the hourly fuel flow-to-load 
ratios (or GHRs) to the baseline fuel flow-to-load ratio (or GHR). The 
absolute value of the percentage difference would be calculated for 
each hour using Equation D-1g. Then the facility would calculate the 
average value of the percentage difference for the quarter, using each 
hourly percentage difference in Equation D-1h.
    The quarterly average of the hourly percentage difference values 
next would be compared to the limitation. For either the fuel flow-to-
load ratio or the GHR, Ef, the quarterly average of the hourly 
percentage difference values would need to be no greater than 10.0 
percent, unless the average of the hourly loads used for the analysis 
was  50 MWe (or  500 klb/hr of steam), in which 
case the limit on Ef would be 15.0 percent. If a fuel flowmeter were to 
fail to meet this limit when using all data in the flowmeter operating 
quarter, then the facility would have the option of excluding certain 
hours. Otherwise, a failure to meet the 10.0 percent (or 15.0 percent, 
if applicable) limit would be considered a failure of the fuel flow-to-
load ratio test.
    (4) Optional Data Exclusions. As mentioned above, if a fuel 
flowmeter's data would not meet the 10.0 percent (or 15.0 percent, if 
applicable) limit on the quarterly average of the percentage difference 
values, then a facility could opt to exclude certain hours of 
unrepresentative fuel flow rate (or heat input rate) data and then 
reanalyze the smaller set of data. The types of data that EPA proposes 
as non-representative would be the same as the hours excluded during 
the baseline period, including: (1) hours when the unit combusts 
multiple fuels measured by multiple fuel flowmeters, such as co-firing 
of gas and residual oil or co-firing of residual oil and diesel fuel; 
(2) hours when the unit load is rapidly rising or falling, sometimes 
referred to as ``ramping,'' to such a degree that the load in a given 
hour differs by more than  15.0 percent from the load 
during either the previous hour or the hour afterwards; or (3) hours in 
which the unit load is in the lower 10.0 percent of the unit's 
operating range, unless operation at those low levels is considered 
normal for the unit. The facility would proceed to analyze the 
remaining quarterly fuel flow rate or heat input rate values, provided 
that there are at least 168 hours remaining for the quarter after 
excluding non-representative hours. If less than 168 representative 
hours remained after excluding the allowable hours, then a flow-to-load 
or GHR test would not be required for that flowmeter for that flowmeter 
operating quarter. If the fuel flowmeter data still failed to meet the 
10.0 percent (or 15.0 percent, if applicable) limit on the quarterly 
average of the percentage difference values after excluding the 
allowable

[[Page 28091]]

hours, the flowmeter would fail the fuel flow-to-load ratio test.
    (5) Consequences of Failing Fuel Flow-to-Load Ratio or GHR Tests. 
There would be two primary consequences of failing a fuel flow-to-load 
ratio or a GHR test. First, the data from the fuel flowmeter would no 
longer be considered quality-assured. Thus, the facility would need to 
invalidate data from the fuel flowmeter following the test. Proposed 
section 2.1.7.4 of Appendix D specifies that the missing data 
procedures of section 2.4.2 of Appendix D would be used to substitute 
for the invalid data (unless a different fuel flowmeter is available 
that has been tested for accuracy and has been demonstrated to meet the 
accuracy specification), beginning with the first hour the fuel 
measured by the fuel flowmeter is used during the quarter following the 
flowmeter operating quarter in which the meter fails the fuel flow-to-
load ratio test. Second, in order to establish that the fuel flowmeter 
is again operating properly and providing quality-assured data, the 
facility would perform a fuel flowmeter accuracy test according to 
sections 2.1.5.1 or 2.1.5.2 of Appendix D or, for orifice-, nozzle-, 
and venturi-type flowmeters, a transmitter or transducer accuracy test 
according to section 2.1.6.1 of Appendix D. In addition to the 
transmitter or transducer test, orifice-, nozzle-, and venturi-type 
fuel flowmeters would need to be further tested following a failed 
flow-to-load or GHR test in order to ensure that the problem causing 
the failure of the fuel flow-to-load ratio was a problem with the 
transmitters or transducers.
    Once the orifice-, nozzle-, or venturi-type flowmeter has been 
recalibrated and passes a transmitter or transducer accuracy test 
according to section 2.1.6.1 of Appendix D, the facility would perform 
a shortened version of the fuel flow-to-load ratio test. The shortened 
version of the test would use six to twelve hours of data following the 
passed transmitter or transducer accuracy test. If the fuel flowmeter 
passed the abbreviated fuel flow-to-load ratio test, then its data 
would be considered valid, beginning with the time and date of the 
passed transmitter or transducer accuracy test. However, if the fuel 
flowmeter were to fail the abbreviated fuel flow-to-load ratio test, 
then it would be necessary for the facility to inspect the primary 
element for corrosion or damage. Furthermore, data would be considered 
invalid until the orifice-, nozzle-, or venturi-type fuel flowmeter 
passes an inspection of the primary element. Although data from the 
flowmeter would be considered quality-assured after successful 
completion of all required accuracy testing, visual inspections and 
diagnostic tests, the baseline would have to be re-established no later 
than the end of the second flowmeter operating quarter following the 
quarter in which the quality assurance tests are completed.
Rationale:
    EPA is proposing to incorporate by reference the standard: American 
Petroleum Institute (API) Section 2, ``Conventional Pipe Provers,'' 
from Chapter 4 of the Manual of Petroleum Measurement Standards, 
October 1988 edition. The Agency has already approved this method of 
fuel flowmeter testing in response to a petition (see Docket A-97-35, 
Item II-C-6). This is also a standard agreed to by API that is 
traceable to NIST standards. The Agency has a general policy of 
approving standards from technically knowledgeable groups such as the 
Organization for International Standards (ISO), the American Society 
for Testing and Materials (ASTM), the American Society of Mechanical 
Engineers (ASME), the American Gas Association (AGA), the Gas 
Processors Association (GPA), and API. EPA would also be willing to 
incorporate additional standards by reference if commenters supply a 
copy for consideration.
    The Agency recognizes that it is difficult and sometimes costly to 
take a fuel flowmeter out from its installation location to be tested 
(see Docket A-97-35, Item II-E-22). Today's proposed rule would provide 
the flexibility of an additional approach for testing fuel flowmeters 
where they are installed. Today's proposal for a fuel flow rate-to-load 
comparison test would allow facilities to assure the quality of their 
fuel flow rate data without taking a fuel flowmeter out of line. 
Several industry representatives suggested that a fuel flow rate-to-
load comparison was a useful approach to quality assuring data (see 
Docket A-97-35, Items II-E-22, II-E-23). Some industry representatives 
felt that a fuel flow rate-to-load ratio was straightforward and even 
more representative than a stack flow rate-to-load ratio (see Docket A-
97-35, Item II-E-23).
    In general, utilities have indicated that the idea of a fuel flow-
to-load ratio is an appropriate quality assurance test for fuel 
flowmeters (see Docket A-97-35, Items II-D-30, II-D-41, II-E-33). Use 
of the fuel flow-to-load ratio was first suggested to the Agency as an 
alternative to annual orifice inspections (see Docket A-97-35, Item II-
E-22). One utility mentioned that the fuel flow-to-load ratio test 
would be most useful if it allowed them to stretch the time between 
transmitter or transducer accuracy tests on orifice-, nozzle-, and 
venturi-type fuel flowmeters, as well as primary element inspections 
and fuel flowmeter accuracy tests performed in-line against a ``master 
meter'' or performed in a laboratory (see Docket A-97-35, Item II-D-
49).
    Utilities have also indicated that they would prefer the provisions 
of the fuel flow-to-load ratio test to be as similar as possible to the 
stack flow-to-load ratio test in today's proposed rule (see Docket A-
97-35, Item II-E-33). This would be easier for facilities to comply 
with because they would need to learn fewer new procedures, they could 
use the same equations and algorithms in computer software or hand 
calculations, and they could report information in a similar format. To 
the extent possible, the Agency has incorporated this suggestion in 
today's proposed rule. However, because monitoring with fuel flowmeters 
is not identical to monitoring with stack volumetric flow monitors, 
there are some differences in the procedures and in the data to be 
recorded and reported.
    Today's proposed rule would allow the quarterly fuel flow-to-load 
ratio test as an optional supplement to flowmeter accuracy tests under 
section 2.1.5.1 or 2.1.5.2 of Appendix D, transmitter or transducer 
accuracy tests under section 2.1.6.1 of Appendix D for orifice-, 
nozzle-, and venturi-type fuel flowmeters, and visual inspections of 
the primary element required under section 2.1.6.6 of Appendix D for 
orifice-, nozzle-and venturi-type fuel flowmeters. These more rigorous 
fuel flowmeter quality assurance procedures would still be required at 
least once every 20 calendar quarters (five years), even if the 
procedures of section 2.1.7 of Appendix D were followed. The Agency has 
proposed a quarterly fuel flow-to-load ratio test for several reasons: 
(1) this is consistent with the provisions of the proposed volumetric 
stack flow-to-load ratio test in today's proposed rule; (2) the test 
involves examining data more closely when preparing quarterly reports; 
and (3) a quarterly test allows facilities to find problems in fuel 
flowmeter data before an entire year has passed. The Agency also 
considered requiring the fuel flow-to-load ratio to be used more 
frequently than quarterly, perhaps daily; however, this would require 
facilities to spend far more time and effort in evaluating data at 
different times during the quarter than they may do currently, 
particularly for small, infrequently operated units. In addition, many 
utilities claim that fuel

[[Page 28092]]

flowmeters tend to be stable, and therefore little change would be 
expected over short time periods such as a day (see Docket A-97-35, 
Item II-E-33).
    EPA is proposing that the optional fuel flow-to-load ratio test 
could serve as a supplement to other quality assurance procedures for 
fuel flowmeters for up to 20 calendar quarters (five years). EPA is 
proposing a time period of 20 calendar quarters for the following 
reasons. First, it is similar to the current provision in section 
2.1.5.2 of Appendix D, which allows a reference fuel flowmeter to be 
accuracy tested as seldom as once in five calendar years if comparison 
with an in-line ``master'' flowmeter shows less than a 1.0 percent 
difference in their flow rates. Second, a five-year test cycle offers 
certain administrative advantages. For instance, fuel flowmeters used 
to provide heat input data for the heat input-versus-load correlation 
of Appendix E could be accuracy-tested before each Appendix E test 
(i.e., once every five years). In addition, a five-year period would 
ensure that fuel flowmeters are tested by the time the unit's operating 
permit is renewed. The 20 calendar quarter (five-year) period is 
consistent with the provisions for reduced three-level flow RATAs for 
stack flow monitors. The 20 calendar quarter (five-year) period between 
tests is also consistent with the proposed time between quality 
assurance tests for fuel flowmeters that are used very infrequently. 
Repeating the periodic quality assurance procedures for fuel flowmeters 
at least every five years would catch slow, long-term changes in heat 
rates mentioned by a facility and would allow a facility to update its 
baseline data periodically (see Docket A-97-35, Item II-D-49). Finally, 
allowing the option of a 20 calendar quarter (five-year) period between 
more rigorous quality assurance procedures would be safer and less 
costly than annual testing, while, in coordination with quarterly fuel 
flow-to-load ratio testing, still providing assurance of the quality of 
the data.
    (1) Use of Gross Heat Rate or Flow-to-Load Ratio. Today's proposed 
rule would allow a facility the option of calculating either the ratio 
of the fuel flow rate to the gross generation in MWe or the steam flow 
rate in thousands of pounds of steam per hour (``fuel flow-to-load 
ratio'') or the ratio of the heat input rate to the gross generation in 
MWe or the steam flow rate in thousands of pounds of steam per hour 
(``gross heat rate'' or ``GHR''). One utility suggested that, because 
the load is created based upon a number of factors in addition to the 
fuel flow rate, such as the gas heat rate (i.e., gross calorific 
value), a ratio of the heat input to the unit load would be a better 
test than the ratio of the fuel flow rate to the unit load (see Docket 
A-97-35, Item II-D-50). In addition, some utilities pointed out that 
the Agency allows facilities to use either a stack flow-to-load ratio 
or a heat input-to-load ratio (gross heat rate) as a diagnostic test on 
stack volumetric flow monitors, through Policy Manual Question 13.15 
(see Docket A-97-35, Item II-I-9). The Agency agrees that the heat 
input-to-load ratio (GHR) is also a technically appropriate check on 
the performance of fuel flowmeters. Therefore, today's proposal 
includes options for both the fuel flow-to-load ratio and the GHR.
    (2) Baseline Period for Fuel Flow-to-Load Ratio or GHR. When using 
this type of comparison test, it is important to establish a baseline 
of reliable data to which hourly data can later be compared. For the 
stack volumetric flow-to-load ratio, the baseline of reliable data 
consists of data from the reference method for flow, Method 2 of 
Appendix A to 40 CFR part 60. However, there is no universally 
applicable test for flowmeters that is performed in-line with a 
reference method while the unit is operating, parallel to the flow 
RATA. EPA asked several utilities what could be a source of baseline 
data to which the fuel flowmeter could later be compared. One utility 
suggested using fuel flowmeter readings during a time when the unit is 
operating at a steady load, such as when the unit undergoes Appendix E 
testing for a NOX-versus-heat input correlation or when a 
NOX CEMS undergoes a normal level RATA (see Docket A-97-35, 
Item II-D-41). A second utility recommended that the baseline be 
established just after performing a transmitter calibration, i.e., 
after performing a quality assurance test on the fuel flowmeter (see 
Docket A-97-35, Item II-D-49). The Agency believes that using fuel 
flowmeter data taken immediately following a flowmeter quality 
assurance test would be most likely to be accurate and representative 
of proper operation of the fuel flowmeter. Flowmeter quality assurance 
tests might include any of the methods incorporated by reference in 
section 2.1.5.1 of Appendix D; meter testing against a certifiable 
``master'' meter under section 2.1.5.2 of Appendix D; or transmitter or 
transducer accuracy testing under section 2.1.6.1 of Appendix D, and 
inspection of a primary element for an orifice-, nozzle-, or venturi-
type fuel flowmeter under section 2.1.6.6 of Appendix D. This approach 
is proposed in today's rule.
    The utilities supporting the idea of using fuel flowmeter data 
taken immediately after a flowmeter quality assurance test have 
suggested that it would be important to have a fairly large number of 
hours in the baseline, on the order of 100 or more, to ensure that the 
baseline period is representative of typical operation (see Docket A-
97-35, Item II-E-33). In today's rule, EPA is proposing to use the 
first 168 hours of quality assured data measured by that flowmeter for 
which: (1) only the fuel measured by that fuel flowmeter is combusted; 
(2) the unit load is not significantly ``ramping'' up or down; and (3) 
the unit load is safely above the minimum safe, stable load. The Agency 
believes that a baseline period containing 168 hours of data is 
sufficiently long to be representative of different unit operating 
conditions that may occur later. This specific time period is 
consistent with the minimum number of hours that a unit combusts a fuel 
before the quarter counts toward the deadline for the next quality 
assurance test, and with the minimum number of hours that a unit 
combusts a fuel before a quarter needs to be evaluated using the fuel 
flow-to-load ratio. Certain hours would be excluded from the baseline 
(i.e., periods of co-firing, unstable, or low load), because the fuel 
flow-to-load ratio or GHR would tend to be less reliable during those 
periods.
    Today's proposal would also limit the baseline period so that it 
may extend no more than two quarters beyond the quarter in which the 
flowmeter passes its accuracy tests. The Agency has concerns that if 
the baseline data were to extend longer than this, the performance of 
the fuel flowmeter might degrade. In order for the baseline data to 
reflect fuel flow rate data that are most likely to be accurate, the 
Agency is proposing that the fuel flow rate or heat input rate data 
used in the baseline period must either be obtained in the calendar 
quarter in which the quality assurance procedure is performed, or 
within two calendar quarters after the QA test. The Agency considered 
limiting the time period to the same calendar quarter as the quality 
assurance procedure or to one flowmeter operating quarter beyond the QA 
test. However, because a quality assurance procedure may be conducted 
at any time during a quarter, it could be difficult for a facility to 
collect 168 hours of fuel flowmeter data after a quality assurance 
procedure in the same calendar quarter or even (for infrequently 
operated units that ramp

[[Page 28093]]

up and down often) in the next calendar quarter.
    For orifice-, nozzle-, and venturi-type fuel flowmeters, two 
quality assurance procedures would be required prior to collecting the 
baseline data: (1) a transmitter or transducer accuracy test, and (2) 
an inspection of a primary element. The Agency considered whether these 
two quality assurance procedures should be separated and whether the 
baseline period could simply be based upon a time period after the most 
recent quality assurance procedure. The Agency believes that the 
baseline period data would be more reliable if they were taken shortly 
after completing both quality assurance procedures for orifice-, 
nozzle-, and venturi-type fuel flowmeters. Using the same time period 
for both tests simplifies administration of the fuel flow-to-load ratio 
test. EPA also notes that a unit does not need to be operating in order 
to perform the tests; thus, it should not be burdensome for a facility 
to plan to coordinate the two quality assurance procedures.
    (3) Data Preparation and Analysis. The proposed procedures for data 
preparation and analysis for the fuel flow-to-load ratio are similar to 
those for the volumetric stack flow-to-load ratio. Equations of the 
same form as those for the stack volumetric flow-to-load ratio are used 
to calculate the hourly fuel flow-to-load ratio, the hourly absolute 
value of the percentage difference between the baseline fuel flow-to-
load ratio and the hourly fuel flow-to-load ratio, and the quarterly 
average percentage difference. Common pipe headers would be treated in 
the same way as common stacks. If there were multiple units associated 
with a single fuel flowmeter or flow monitor, the total load from all 
units would be summed before the flow rate data are divided by the load 
data to calculate the flow-to-load ratio. Fuel flowmeters on multiple 
pipes would be treated in the same way as multiple stacks associated 
with a single unit. If there are multiple fuel flowmeters or flow 
monitors associated with a single unit, the flow rates from all fuel 
flowmeters for the same fuel or all flow monitors would be added 
together before the flow rate data are divided by the load data to 
calculate the flow-to-load ratio.
    Certain aspects of the volumetric stack flow-to-load ratio test are 
not the same for the fuel flow-to-load ratio test. For example, the 
volumetric stack flow-to-load ratio test requires the facility to 
screen out those hours when the unit operates further than 10.0 percent 
away from the average load during the most recent normal-load flow 
RATA. As was discussed previously, there is no equivalent of an in-line 
flow RATA for fuel flowmeters. EPA does not believe that there is a 
need to screen out hours for the fuel flow-to-load test when the unit 
operates at a load somewhat less than or greater than normal. Some 
facilities have indicated that the fuel flow-to-load ratio or GHR based 
on fuel flow readings is less variable over different loads than the 
volumetric stack flow-to-load ratio (see Docket A-97-35, Items II-E-33 
and II-D-98). However, preliminary evidence has also indicated that the 
fuel flow-to-load ratio or GHR can be significantly different at very 
low operating loads than at other load levels (see Docket A-97-35, Item 
II-A-5). For this reason, EPA is proposing to allow hours in which the 
unit load is within the lower 10.0 percent of the range of operation to 
be excluded from both the baseline data and the quarterly flow-to-load 
or GHR analysis, unless such low loads are considered normal for the 
unit.
    Another feature of the volumetric stack flow-to-load ratio test 
that differs from the fuel flow-to-load ratio test is the treatment of 
bias-adjusted data. Fuel flow rate data are never adjusted for bias. 
There is no bias test for fuel flowmeters. Bias-adjustment of data is 
an issue for the volumetric stack flow-to-load ratio test because bias-
adjusted data has already been adjusted to make it more consistent with 
the value of the reference method data. Thus, bias-adjusted volumetric 
stack flow data must meet a stricter quarterly average percentage 
difference of 10.0 percent from the reference flow-to-load ratio, 
whereas the allowable difference is 15.0 percent when unadjusted 
volumetric stack flow data are used. (See discussion of stack flow-to-
load test in Section III.M. of this preamble.) EPA notes that since the 
same fuel flow meter is used to produce both the baseline data and the 
quarterly data, the fuel flow-to-load ratio is more closely analogous 
to the use of bias-adjusted volumetric flow data. Therefore, the limit 
on the quarterly average percentage difference from baseline for fuel 
flow rate data should be at least as stringent as that for bias-
adjusted volumetric flow data (10.0 percent). Information provided by 
facilities on the gross heat rate derived from fuel flow rate data have 
shown less variability than the corresponding stack heat rate (see 
Docket A-97-35, Item II-D-98). Based upon this information, EPA is 
proposing a limit of 10.0 percent on Ef, the quarterly 
average percentage difference from the baseline for the quarterly flow 
rate-to-load or GHR evaluation. EPA considered whether it would be 
appropriate to set a different limit for smaller units, as was done for 
the stack flow-to-load test. Analysis of some preliminary fuel flow-to-
load data has shown that for lower loads (e.g., < 50 MWe), the flow-to-
load ratio is quite sensitive to small changes in load (see Docket A-
97-35, Item II-A-5). This indicates that it would be appropriate to set 
a higher limit for smaller units. Therefore, today's rule proposes a 
limit of 15.0 percent on the value of Ef when the quarterly 
average load used for the data analysis is 50 megawatts or less (or 
 500 klb steam per hour). The Agency solicits comment on the 
15.0 percent limit for loads less than or equal to 50 megawatts.
    (4) Optional Data Exclusions. As for volumetric stack flow 
monitors, if a fuel flowmeter's data would not meet the limit on the 
percentage deviation from the baseline, then a facility could opt to 
exclude certain hours of unrepresentative fuel flow rate (or heat input 
rate) data and then reanalyze the smaller set of data. The hours of 
data that EPA proposes to view as non-representative for fuel 
flowmeters are: (1) hours when the unit combusts multiple fuels; (2) 
hours when the unit load in a given hour would differ by more than 
 15.0 percent from the load during either the previous hour 
or the subsequent hour; or (3) hours when the load is very close to the 
minimum safe, stable load (unless operation in that range is normal).
    The baseline period for fuel flowmeters and the data used for the 
quarterly flow-to-load or GHR analyses would include only those hours 
when a single fuel is combusted--the fuel measured by the fuel 
flowmeter. If the quarterly fuel flow rate data included hours when 
multiple fuels are co-fired, the fuel flow-to-load ratio or GHR for the 
fuel flowmeter being tested would be biased low. This could result in a 
failure of the flow-to-load test or GHR evaluation. Today's proposed 
rule would also allow a facility to exclude from the baseline data and 
the quarterly analyses those hours that are not representative because 
the unit's load is changing rapidly. Specifically, hours could be 
excluded when the unit load in a given hour would differ by more than 
 15.0 percent from the load during either the previous hour 
or the hour afterwards. There will be a lag in the time between when 
electricity is generated and registered as load and the time that the 
fuel flowmeter measures the fuel that is combusted to generate the 
load. Therefore, during an hour when the load changes rapidly, the fuel 
flow rate will not necessarily be changing by the same amount or in the

[[Page 28094]]

same direction. At least one utility has suggested that the Agency 
consider such an exclusion for the proposed fuel flow-to-load ratio 
test (see Docket A-97-35, Item II-D-41).
    In general, the fuel flow is directly proportional to load, with a 
linear graphical relationship. However, this is not always the case at 
extremely low loads (see Docket A-97-35, Items II-E-33, II-D-98). 
Therefore, today's proposed rule would allow certain low-load hours to 
be excluded from the flow-to-load baseline and quarterly data analyses. 
Specifically, loads in the lower 10.0 percent of the ``range of 
operation'' of the unit, (as that term is defined in proposed section 
6.5.2.1 of Appendix A in today's proposal) could be excluded, unless 
such loads are considered normal for the unit.
    Today's proposed rule, in section 2.1.7 of Appendix D, would also 
exempt a fuel flowmeter from the fuel flow-to-load ratio test in a 
quarter when a more rigorous quality assurance test is performed. This 
is unlike the volumetric stack flow-to-load ratio, which is required 
each QA operating quarter, including quarters when the flow monitor is 
tested with a RATA (provided, of course, that sufficient data for the 
analysis are obtained after the RATA).
    (5) Consequences of Failing the Fuel Flow-to-Load Ratio Test. The 
consequences of failing the fuel flow-to-load ratio test would be 
similar to the consequences of failing quality assurance tests in 
general for fuel flowmeters. Data from the fuel flowmeter would no 
longer be considered quality assured. Because the fuel flow-to-load 
ratio test is only performed at the end of a quarter, the facility 
would invalidate data from the fuel flowmeter beginning with the first 
hour in the quarter after the quarter in which the meter fails the fuel 
flow-to-load ratio test. In order to establish that the fuel flowmeter 
is operating properly and providing quality assured data again, the 
facility would perform a flowmeter accuracy test or (for orifice-, 
nozzle-, and venturi-type flowmeters) a transmitter or transducer 
accuracy test. The Agency believes it is appropriate to perform an 
accuracy test if the fuel flow-to-load ratio test is failed, because in 
such cases the facility has had the benefit of postponing the accuracy 
test based upon the assumption that the fuel flowmeter has continued to 
measure accurately and consistently with its operation during the 
baseline period.
    Note that for orifice-, nozzle-, and venturi-type fuel flowmeters, 
a transmitter/transducer test alone would not suffice to demonstrate 
that the flowmeter is back in control. The owner or operator would 
still need to ensure that the cause of the failed fuel flow-to-load 
ratio test was a problem with the transmitters or transducers rather 
than a problem with the primary element. Sudden changes in flowmeter 
performance are likely to be caused by a problem with transmitters (see 
Docket A-97-35, Item II-D-33). However, it cannot be assumed that the 
transmitters are solely responsible for degradation in monitor 
performance. In order to verify that the primary element is not 
contributing additional error to the fuel flow measurements because of 
corrosion, a facility would conduct an abbreviated (6 to 12 hour) 
version of the fuel flow-to-load ratio test, similar to the diagnostic 
test for volumetric stack flow monitors in Policy Manual Question 13.15 
(see Docket A-97-35, Item II-I-9). The Agency believes that this 
abbreviated fuel flow-to-load ratio test would provide additional 
assurance that the fuel flowmeter is indeed operating properly. In 
addition, it would be more timely than waiting for another calendar 
quarter to pass to repeat the fuel flow-to-load ratio. The abbreviated 
test would also be less burdensome than removing the primary element 
from the fuel pipe. EPA believes the abbreviated fuel flow-to-load 
ratio test strikes a reasonable balance by providing some additional 
quality assurance in a timely manner. If the orifice-, nozzle-, or 
venturi-type fuel flowmeter failed the abbreviated fuel flow-to-load 
ratio test, then it would appear that the primary element may also have 
a problem. Therefore, upon failure of an abbreviated fuel flow-to-load 
ratio test, the facility would be required to inspect the primary 
element and to repair or replace it, as necessary.
    The rules for data validation upon failure of the fuel flow-to-load 
ratio are not parallel with the procedures for data validation 
following failure of the volumetric stack flow-to-load ratio test in 
that there is no conditional validation of data. A number of utilities 
have emphasized that they wish to spend less time and effort preparing 
and evaluating quarterly reports for units using Appendix D, which are 
generally smaller and less frequently operated than coal-fired units or 
oil-fired units that choose to use CEMS (see Docket A-97-35, Item II-E-
33). The concept of conditional data validation for fuel flowmeters is 
not consistent with this objective, because it would introduce 
additional complexity into the process, would require significantly 
more time and resources to quality-assure the data, and might require 
additional DAHS programming. Therefore, the Agency is not proposing the 
use of conditional data validation for fuel flowmeters.
(c) Fuel Flowmeter Quality Assurance Testing Frequency
Background
    Section 2.1.6.1 of Appendix D, as revised by the May 17, 1995 
direct final rule, requires regular quality assurance 
``recalibrations'' (accuracy tests) of fuel flowmeters at least 
annually (once every four calendar quarters). For fuel flowmeters that 
were not used on a regular basis, such as fuel flowmeters used to 
measure the usage of emergency fuel or backup fuel, or flowmeters 
installed on peaking units, owners or operators are allowed to do 
flowmeter accuracy tests once every four quarters when the unit 
actually combusts the fuel measured by the flowmeter, rather than once 
every four calendar quarters. Flowmeters can be retested either by 
using one of the methods incorporated by reference in section 2.1.5.1 
of Appendix D to part 75 or by an in-line comparison of the fuel 
flowmeter against a ``master'' fuel flowmeter using the procedure in 
section 2.1.5.2 of Appendix D.
    Some utilities have expressed concern about the annual fuel 
flowmeter testing requirement (see Docket A-97-35, Items II-D-20, II-E-
13, II-E-14). In many cases, it is neither practical nor cost-effective 
to modify the fuel pipes (e.g., to install a parallel length of pipe) 
to allow installation of a master fuel flowmeter for comparison 
testing. Thus, most utilities must remove a fuel flowmeter from the 
pipe and return it to a laboratory or to the manufacturer to be 
retested. In some cases, especially for oil flowmeters, this can be 
difficult.
    Some utilities have raised the issue of whether there should be a 
minimum time period that a fuel flowmeter is used before a quality 
assurance test is required. For instance, a utility might test its 
unit's burners once each quarter for a few hours to ensure that the 
unit can be operated when needed and may not operate for the rest of 
the quarter. Under the current rule, the fuel flowmeter would have to 
be quality assurance tested after four such operating quarters, even 
though the flowmeter was only used for a few hours in those calendar 
quarters.
Discussion of Proposed Changes
    Today's proposed rule includes a provision that only those calendar 
quarters in which the fuel measured by the fuel flowmeter is combusted 
for at least 168 hours would count toward determining the next quality 
assurance test deadline. The 168-hour time period

[[Page 28095]]

is roughly equivalent to one week of operation while combusting the 
fuel measured by a particular fuel flowmeter. A calendar quarter in 
which the fuel measured by a fuel flowmeter is combusted for 168 hours 
or more would be called a ``flowmeter operating quarter.'' For example, 
if a unit combusted oil for 200 hours in the first calendar quarter of 
the year, 10 hours in the second calendar quarter, 250 hours in the 
third calendar quarter, and 100 hours in the fourth calendar quarter, 
then only the first and third calendar quarters would be considered 
flowmeter operating quarters for the oil flowmeter. Only the first and 
third calendar quarters would count toward determining the deadline for 
the next required oil flowmeter accuracy test.
    In today's proposed rule, each fuel flowmeter would need to be 
accuracy tested at least once every four flowmeter operating quarters. 
However, the deadline for testing infrequently-used meters could not be 
extended indefinitely. No more than 20 calendar quarters (five years) 
would be allowed to elapse between successive flowmeter accuracy tests, 
regardless of the number of ``flowmeter operating quarters'' that have 
elapsed since the last test. The interval between successive quality 
assurance tests could also be extended for up to 20 calendar quarters 
if the quarterly fuel flow rate-to-load procedures in proposed section 
2.1.7 of Appendix D were implemented.
Rationale
    In evaluating the frequency of fuel flowmeter accuracy testing, EPA 
considered simply extending the less strict requirement for fuel 
flowmeter quality assurance testing for peaking units, backup fuel, and 
emergency fuel to apply to all units and all fuel flowmeters. Thus, 
quality assurance testing would be required once every four quarters in 
which the unit combusted the fuel measured by the flowmeter.
    One industry representative recommended that the Agency require 
fuel flowmeter calibrations once every four unit operating quarters, 
where a unit operates at least 168 hours in the quarter (see Docket A-
97-35, Item II-E-13). This approach would treat all fuel flowmeters the 
same, whether they were used for primary, emergency, or backup fuel.
    Another utility suggested that the Agency consider creating some 
sort of diagnostic test comparing the flow rate of the fuel flowmeter 
to the unit load (generation) to determine whether the fuel flowmeter 
readings are degrading over time, rather than specifying a particular 
frequency for accuracy testing (see Docket A-97-35, Item II-E-22). 
Although this suggestion was originally referring to problems with 
corrosion of an orifice plate, such a test could also be used for other 
types of fuel flowmeters as a check on the quality of fuel flowmeter 
data.
    The Agency also considered extending the typical time between 
accuracy tests to the equivalent of two years. This time was suggested 
by a member of the AGA subcommittee responsible for the drafting of AGA 
Report No. 7 for turbine-type flowmeters (see Docket A-97-35, Item II-
E-17). The Agency also considered extending the typical time between 
accuracy testing to 12 calendar quarters--the equivalent of three 
years. Three years is the period of time that records must be retained 
in a file at the source under Sec. 75.54 (or proposed Sec. 75.57).
    The Agency also considered allowing fuel flowmeters to continue for 
up to five calendar years between accuracy tests. This is similar to 
the current provision in section 2.1.5.2 of Appendix D, which allows a 
reference fuel flowmeter to be accuracy tested as seldom as once in 
five calendar years, if the in-line comparison with a master fuel 
flowmeter shows a 1.0 percent or less difference in their flow rates. A 
five-year test cycle offers certain administrative advantages. For 
instance, fuel flowmeters used to provide heat input data for the heat 
input-versus-load correlation of Appendix E could be accuracy-tested 
before each Appendix E test (i.e., once every five years). In addition, 
the five calendar-year period would ensure that fuel flowmeters are 
tested by the time the unit's operating permit is renewed. Facilities 
might find this time cycle easier to determine than a time period based 
upon a number of calendar quarters. However, test data would need to be 
retained for five years, rather than for three years, the recordkeeping 
period for most records under part 75. However, the Agency is not 
proposing this option because five years is far too long a period of 
time to allow a unit to continue with no checks at all upon the quality 
of its data. Such an approach would allow the use of data from a fuel 
flowmeter that potentially had been reading inaccurately for the 
previous five years.
    Another option that EPA evaluated was to establish different fuel 
flowmeter quality-assurance testing frequencies depending on the fuel 
measured by the fuel flowmeter. Under this approach, oil flowmeters 
would need to be tested every four calendar quarters in which oil was 
combusted. Gas flowmeters would only need to be tested once every five 
years. The two fuels would be treated differently because units emit 
less NOX and far less SO2 when combusting gas 
than when combusting oil. In addition, gaseous fuels, particularly 
pipeline natural gas, should be less corrosive; therefore, a gas 
flowmeter should be less likely to degrade than an oil flowmeter.
    EPA believes that today's proposed approach to reducing the fuel 
flowmeter quality assurance testing frequency takes into account many 
of the concerns raised by utilities. All unit types and fuel types 
would have the same frequency of testing. This would avoid confusion 
that could follow from an approach that set different requirements for 
fuels or units that are used less frequently. A group of utilities had 
indicated that they prefer a more consistent approach (see Docket A-97-
35, Item II-E-13). Under today's proposal, infrequently-used fuel 
flowmeters (e.g., meters for backup fuel or emergency fuel) would only 
need to be calibrated once every five years. When a facility renews its 
operating permit, the permitting agency could verify that all fuel 
flowmeters have been tested at least once in the previous five years.
    The minimum period of 168 hours of fuel flowmeter usage which 
defines a ``flowmeter operating quarter'' is consistent with the 
definition of a ``QA operating quarter'' in Appendix B in today's 
proposed rule for the quality assurance of CEMS. The Agency believes 
that using a consistent minimum number of hours in a calendar quarter 
for both CEMS and fuel flowmeters will make implementation easier for 
facilities and air regulatory agencies. In addition, 168 hours should 
be a sufficiently long period of time to ensure that short-term usage 
of backup fuel or emergency fuel or short-term tests of a unit do not 
trigger unnecessary quality assurance testing.
    Today's proposed rule would also provide more flexibility in the 
methods that could be used for fuel flowmeter quality assurance 
testing. As discussed above in Section III.P.2 of this preamble, a new 
testing procedure has been proposed that would allow a facility to test 
flow rate-to-load ratio of the fuel flowmeter while leaving it 
installed. Thus, the Agency believes that the overall burden of fuel 
flowmeter testing has been significantly reduced. In addition to the 
reduced frequency of testing discussed above, the Agency believes the 
less burdensome testing procedures should address concerns of the 
regulated community.
    The Agency requests comment on whether facilities would prefer to 
base

[[Page 28096]]

the frequency of fuel flowmeter quality assurance testing on the type 
of fuel used or the amount of time the fuel flowmeter is used. Under 
the first approach, gas flowmeters would receive greater regulatory 
relief. Under the second approach, which is being proposed in today's 
rule, infrequently-used flowmeters (typically oil flowmeters) would 
receive greater regulatory relief.
(d) Orifice, Nozzle, and Venturi Visual Inspections
Background
    Section 2.1.6 of Appendix D, as revised in the May 17, 1995 direct 
final rule, created special provisions for the ongoing quality 
assurance testing of orifice fuel flowmeters. Orifice-,
nozzle-, and venturi-type fuel flowmeters are designed and installed 
within a set of physical specifications, such as the orifice diameter 
(see Docket A-97-35, Item II-D-13). Maintaining these physical 
specifications determines the flowmeter's ability to read accurately. 
Thus, it is not necessary to take an orifice-, nozzle-, or venturi-type 
flowmeter out of line and send it to a laboratory to determine its 
accuracy.
    After installation of an orifice-, nozzle-, or venturi-type 
flowmeter is complete, the two major factors that contribute to error 
in flow readings are: drift in the transmitters (or transducers) which 
determines the total pressure, differential pressure and temperature, 
and corrosion of the primary element (e.g., the orifice plate) itself. 
Quality assurance testing of the transmitters is discussed in the next 
section of the preamble. In order to identify cases where error might 
result from corrosion of the orifice plate, the May 17, 1995 direct 
final rule added a requirement for an annual visual inspection of the 
orifice plate. If an orifice plate fails the inspection, then the 
facility must perform a test on the transmitters during the next 
calendar quarter. A procedure for visual inspections is given in 
Appendix B of part 2 of American Gas Association (AGA) Report No. 3, 
which is one of the accepted standards for installation and use of 
orifice flowmeters.
    Some facilities have expressed concern with the frequency of visual 
inspections (see Docket A-97-35, Items II-D-20, II-E-13, II-E-14). This 
process must be done either with a tool, such as a boroscope, or else 
the primary element must be removed from the pipe and lifted out to be 
inspected. In the case of large, heavy orifices, it is necessary to use 
a crane to remove the orifice. Fuel must not be flowing through the 
pipe while the orifice plate is being removed (see Docket A-97-35, Item 
II-E-8).
    The current provisions of Appendix D to part 75 do not explicitly 
state the consequences of failing a quality assurance test. Section 
2.1.5.1 of Appendix D states that if a fuel flowmeter exceeds the 
flowmeter accuracy of  2.0 percent of the upper range 
value, then the flowmeter may not be used under part 75. Section 
2.1.5.2 states that if a fuel flowmeter's accuracy exceeds  
2.0 percent of the upper range value, then the flowmeter must be 
recalibrated to meet that accuracy, or it must be replaced with another 
flowmeter that meets the specification. Neither section explicitly 
states the impact upon the validity of data if a test is failed. 
However, if fuel flowmeter systems are to be treated parallel with 
continuous emission monitoring systems under Sec. 75.21(e)(2), the 
consequences of failing a quality assurance test for a fuel flowmeter 
or an inspection of the primary element should result in the monitor 
being considered out-of-control and the data being considered invalid.
    In section 2.1.6.1 of Appendix D, the specific consequence of 
failing a visual inspection of the primary element is that the 
transmitters must be tested in the following calendar quarter, rather 
than waiting until the regular annual calibration is required. However, 
no mention is made of any mandatory corrective action(s) to eliminate 
the corrosion problem.
Discussion of Proposed Changes
    Section 2.1.6.6 of Appendix D in today's rulemaking proposes to 
require visual inspections of primary elements (i.e., orifice, nozzle 
or venturi) at the frequency recommended by the manufacturer or once 
every three years, whichever is more frequent. The Agency solicits 
comment on the proposed frequency of visual inspections.
    The proposed rule would also explicitly require repair or 
replacement of the primary element and invalidation of data when a 
visual inspection is failed. Once the primary element is replaced or 
repaired, the new or repaired primary element would have to demonstrate 
that it meets the overall flow rate accuracy of  2.0 
percent of the upper range value. This could be demonstrated by showing 
that the new or repaired primary element meets the design and 
installation requirements of AGA Report No. 3 or ASME MFC-3M, the same 
methods required for initial certification. Alternatively, the flow 
rate accuracy could be demonstrated by testing the fuel flowmeter 
against a reference fuel flowmeter using the provisions of section 
2.1.5.2 of Appendix D. Finally, whenever a primary element is repaired, 
the fuel flowmeter transmitters would also have to be tested before the 
fuel flowmeter is used to provide quality assured data.
Rationale
    During the process of reviewing certification applications for 
units using orifice flowmeters, the Agency learned of one plant where 
orifice corrosion was a serious problem. This utility had an orifice 
flowmeter which had been installed in the 1960's. This utility did not 
have documentation of the standard used to install the orifice as a 
demonstration of the meter's accuracy. In order to qualify for 
certification, the utility inspected the orifice. The utility personnel 
discovered that the orifice had been completely eaten away and was 
incapable of reading the flow rate (see Docket A-97-35, Item II-E-22). 
The utility replaced the orifice before it was able to have its fuel 
flowmeter certified. In addition, it was required to invalidate the 
flow rate data from the orifice meter and substitute for the missing 
data. Based upon this experience, the Agency believes that corrosion of 
an orifice can be a problem, and that in severe cases of corrosion, 
replacement of the orifice is necessary.
    Despite this, many utilities have expressed concern over the 
difficulty of removing an orifice from place for visual inspection (see 
Docket A-97-35, Items II-D-20, II-E-13, II-E-14), because removal 
requires halting the flow of gas through the pipeline in order to 
remove the orifice, which can be expensive (see Docket A-97-35, Item 
II-E-8).
    Utilities have provided the Agency with several suggestions for 
reducing the frequency of primary element inspections. One industry 
group recommended that the Agency reduce the inspection frequency to 
once every five years, to be coordinated with renewal of the plant's 
operating permit under title V of the Act (see Docket A-97-35, Items 
II-D-20, II-E-13, and II-E-14). One utility representative mentioned 
that most orifice manufacturers recommend an inspection once every 
three years; thus, he recommended that the Agency require visual 
inspections the earlier of once every three years or the time period 
specified by the manufacturer (see Docket A-97-35, Item II-D-41). 
Another utility suggested that the Agency consider creating some sort 
of diagnostic test comparing the flow rate of the fuel flowmeter to 
unit load (generation) to determine whether the fuel flowmeter readings 
are degrading

[[Page 28097]]

over time, rather than specifying a particular time period (see Docket 
A-97-35, Item II-E-22).
    EPA agrees that it would be helpful to facilities to reduce the 
frequency of visual inspections from their current annual frequency. 
Having considered all of the options suggested by the utilities, the 
Agency is proposing that the primary element of all nozzle, venturi and 
orifice fuel flowmeters be visually inspected at the frequency 
recommended by the manufacturer or once every three years, whichever is 
the more frequent. The Agency believes that up to three years between 
visual inspections is a technically sound period of time that will 
assure the quality of fuel flow rate data, while providing regulatory 
relief from the current annual requirement.
    The Agency also has reconsidered the consequences of failure of a 
visual inspection. The May 17, 1995 direct final rule added a 
requirement to test a flowmeter's transmitters in the calendar quarter 
following a failed inspection, but the rule does not explicitly require 
that the primary element be repaired or replaced, nor does it 
explicitly require data from the fuel flowmeter to be invalidated.
    Today's proposed rule would require the primary element to be 
removed following a failed visual inspection and would require the 
problem to be corrected. The Agency believes that it is appropriate to 
provide two options for correcting the problem: either replace the 
element with a new one or repair it. This would provide flexibility to 
facilities, while still assuring that the fuel flowmeter will be 
repaired to give quality assured data.
    Today's proposed rule would also change the timing of the 
requirement for fuel flowmeter transmitter or transducer testing if a 
primary element fails its visual inspection. The Agency believes that 
it would be appropriate also to test the fuel flowmeter transmitters 
before the fuel flowmeter is placed into service again. This would be a 
more thorough quality assurance check of the entire fuel flowmeter than 
simply addressing the problem with the primary element. Thus, when the 
fuel flowmeter is placed into service again, its accuracy would be 
tested as fully as possible. In addition, EPA proposes to remove the 
requirement for a test on the flowmeter transmitters in the calendar 
quarter following a failed visual inspection. This requirement might be 
appropriate if it seemed that transmitter drift was likely to be a 
problem or if the Agency had no other means of assuring the quality of 
the data from the flowmeter after a problem with the primary element 
was known to have occurred. However, the Agency believes that problems 
with the primary element are separate from problems with drift in the 
transmitters. Because today's proposal would require a check on the 
fuel flowmeter transmitters after repair or replacement of the primary 
element, requiring an additional test of the transmitters in the 
following calendar quarter appears to be unnecessary.
    The proposed rule gives procedures for data validation when a 
primary element fails a visual inspection. The element would have to be 
replaced or repaired, and the transmitters would have to be tested 
before data would again be valid from the fuel flowmeter. During the 
period in which the flowmeter data are considered invalid, the 
appropriate missing data substitution procedures would be used. The 
Agency has clarified that these data validation procedures would also 
apply to failures of other fuel flowmeter quality assurance tests. EPA 
believes that this will make facilities' obligations clearer. In 
addition, the Agency believes that fuel flowmeter systems should be 
treated as consistently as possible with CEMS. Consistent treatment 
simplifies the part 75 requirements and is more equitable for sources 
using different monitoring approaches.
(e) Orifice, Venturi, and Nozzle Flowmeter Transmitter Testing
Background
    As discussed previously, once an orifice-, nozzle-, or venturi-type 
flowmeter has been installed, one of the major causes of error in the 
measured flow rates is drift in the transmitters or transducers that 
determines the total pressure, differential pressure, and temperature. 
The flow measurement error for these types of flowmeters is a 
combination of the errors in these individual transmitters or 
transducers and a constant error value associated with the physical 
dimensions of the primary element. The May 17, 1995 direct final rule 
added a requirement that flowmeter transmitters be tested at least 
annually. The transmitters are also required to be retested in the next 
calendar quarter if the overall flow rate error is greater than 1.0 
percent of the upper range value of the flowmeter. For practical 
purposes, this requires a facility to know the error from the physical 
dimensions of the primary element in order to determine if the 
flowmeter meets the overall accuracy requirement.
    Some utilities asked the Agency how to determine the overall 
flowmeter accuracy from individual transmitter values (see Docket A-97-
35, Item II-E-31). EPA addressed this issue in Policy Guidance (see 
Docket A-97-35, Item II-I-9, Policy Manual, Question 10.17). This 
guidance included a formula for calculating total flowmeter accuracy 
from error in transmitter readings for differential pressure, static 
pressure and temperature, and error from all other sources (i.e. 
physical dimensions of the primary element). Some utilities indicated 
that they do not always have information available on the constant 
error from other portions of the primary element (see Docket A-97-35, 
Item II-E-13). The policy guidance also indicated that a facility could 
report test results electronically using the highest amount of error 
from any of the three transmitters. Provided that the highest error 
from an individual transmitter is 1.0 percent of the upper range value 
of the transmitter or less, the overall flowmeter accuracy will be less 
than 2.0 percent of the upper range value (see Docket A-97-35, Item II-
I-10).
    EPA has also observed that transmitter test data reported for 
orifice-, nozzle-, and venturi-type flowmeters have not been 
consistent. Some facilities test each transmitter once at three 
different levels, including a low, middle, and high value (see Docket 
A-97-35, Item II-D-16). Others test each transmitter at five different 
levels, including zero, full scale, and three intermediate levels (see 
Docket A-97-35, Item II-D-17). The Agency had previously issued some 
guidance on reporting test results, both for orifice flowmeters and 
other flowmeters (see Docket A-97-35, Items II-I-4, p. 3-58, and II-I-
9, Policy Manual, Questions 10.17 and 12.27). However, this guidance 
appears to have been insufficient, as utilities have continued to 
request guidance in how to perform and report test results (see Docket 
A-97-35, Item II-D-21). Questions have included the number of levels at 
which transmitters should be tested, whether all of these levels must 
be non-zero, the number of times the transmitter should be tested at a 
particular level, if results may be reported in hardcopy or should be 
reported electronically, and how data should be reported 
electronically.
Discussion of Proposed Changes
    Today's proposed rule would make the requirement to assess the 
total accuracy of orifice-, nozzle-, and venturi-type fuel flowmeters 
from the transmitter/transducer test results an option. As an 
alternative, proposed section 2.1.6.5 in Appendix D would allow each of 
the three transmitters (static pressure, differential pressure, and 
temperature) individually to meet

[[Page 28098]]

an accuracy specification of 1.0 percent of the upper range value of 
the transmitter.
    Today's rulemaking also proposes a procedure in section 2.1.6.1 of 
Appendix D for testing the accuracy of orifice-, nozzle-, and venturi-
type fuel flowmeters. Each transmitter would be calibrated against 
NIST-traceable reference values at least once at the zero level and at 
a minimum of two other levels across the range of values that the 
transmitter reads during normal unit operation. Note that in many 
instances this would be a portion of the full-scale range of the 
transmitter, rather than the entire range. In addition, revised section 
2.1.6.2 of today's proposed rule includes the new Equation D-1a to 
clarify how to calculate the error from an individual transmitter.
    Finally, today's proposal would clearly specify the consequences of 
failure of an accuracy test on transmitters in section 2.1.6.5 of 
Appendix D. Just as CEM data are considered invalid from the time that 
a quality assurance test is failed until the test is subsequently 
passed, data from a fuel flowmeter would be considered invalid from the 
date and time of a failed transmitter accuracy test until the date and 
time of a passed transmitter accuracy test.
Rationale
    The Agency considered two main options for determining the accuracy 
of a transmitter or transducer of an orifice-, nozzle-, or venturi-type 
fuel flowmeter. In the first approach (which is consistent with current 
policy guidance), these types of fuel flowmeters would be required to 
meet an accuracy of 2.0 percent of the upper range value of the total 
flow rate of the fuel flowmeter. The accuracy would be determined using 
the square root of the sum of the squares of all sources of error in 
the fuel flowmeter, according to the following equation:
[GRAPHIC] [TIFF OMITTED] TP21MY98.000

Where: dqv/qv = Error in the volumetric flow rate 
due to transmitter drift at a given level;
K = Original error resulting from installation of orifice (including 
all other variables);
dPf = Average difference between static pressure transmitter 
reading(s) and reference static pressure reading(s) at a given level;
Pf = Average reference static pressure reading at a given 
level;
dP = Average difference between differential pressure 
transmitter reading(s) and reference differential pressure reading(s) 
at a given level;
P = Average reference differential pressure reading at a given 
level;
dTf = Average difference between temperature transmitter 
reading(s) and reference temperature reading(s) at a given level; and
Tf = Average reference temperature reading at a given level.

    If the error calculations for error from the primary element of the 
fuel flowmeter were not available, then the facility could use a 
default value of 1.0 percent of the upper range value error from all 
parts of the fuel flowmeter except for the differential pressure, 
static pressure, and temperature transmitters. (In other words, the 
factor ``K'' in the equation above would be equal to 1.0 percent of the 
upper range value.) However, this would almost certainly trigger the 
requirement for recalibration or retesting of the accuracy of the 
transmitters in the next calendar quarter because the fuel flowmeter 
accuracy would exceed 1.0 percent of the upper range value. Based upon 
statements from the American Gas Association, it is the Agency's 
understanding that for an orifice-, nozzle-, or venturi-type fuel 
flowmeter meeting AGA Report No. 3 or ASME MFC-3M, the maximum error 
from portions of the meter other than the transmitters should be 1.0 
percent of the upper range value (see Docket A-94-16, Item II-F-2, and 
this Docket, A-97-35, Item II-E-18).
    In the second approach to determining error for orifice-, nozzle-, 
and venturi-type fuel flowmeters, each transmitter or transducer would 
be tested separately for accuracy, and each transmitter or transducer 
would be required to meet an accuracy specification of 1.0 percent of 
the full scale range of the transmitter. Under this approach, it would 
no longer be necessary to determine the total error in the flowrate 
from the fuel flowmeter. Because this proposal would eliminate the 
calculation of the total error in flowrate, there would no longer need 
to be a requirement to retest the accuracy of the transmitters in the 
next calendar quarter when the total fuel flowmeter accuracy exceeds 
1.0 percent of the upper range value.
    In today's rule, EPA proposes to allow both of the approaches 
described above for calculating the total flowmeter accuracy. The 
second approach (i.e., calculating individual transmitter accuracy) is 
simpler than calculating the total error in the flow rate, although it 
is less directly related to the accuracy of SO2 mass 
emission rate and heat input measurements than the fuel flowrate. An 
individual transmitter accuracy specification of 1.0 percent of the 
full scale of each transmitter would be slightly stricter than a total 
fuel flowmeter accuracy specification of 2.0 percent of the upper range 
value of the fuel flowmeter, because one transmitter could potentially 
have an error greater than 1.0 percent of its full scale range while 
the entire error in the fuel flowrate would still be less than 2.0 of 
the upper range value of the fuel flowmeter. Thus, the option of 
calculating the total error in the fuel flowrate has been retained in 
today's proposal. At least one industry representative suggested 
allowing both approaches of calculating accuracy when testing 
transmitters of an
orifice-, nozzle-, or venturi-type fuel flowmeter (see Docket A-97-35, 
Item II-E-24).
    The Agency considered two main methodologies for transmitter 
testing on orifice-, nozzle-, and venturi-type flowmeters. The first 
method would be to require a five-point test that checks the linearity 
of the transmitter. The transmitter would be tested against an NIST 
traceable method (e.g., testing a pressure transmitter against an NIST 
traceable deadweight transmitter) at the following percentages of the 
full scale range of the transmitter: 0.0 percent, 20.0 to 30.0 percent, 
40.0 to 60.0 percent, 70.0 to 80.0 percent, and 100.0 percent. This is 
the general approach that was taken by many utilities that provided 
transmitter calibration results to EPA (see Docket A-97-35, Items II-D-
26 through 28).
    The second method would be to require a comparison to an NIST 
traceable transmitter at the zero level and at least two other levels 
across the range of readings on the transmitter or transducer. This 
would be different from the first method in that the transmitter would 
only need to be tested across the range where the transmitter is

[[Page 28099]]

actually used. For example, if a fuel flowmeter transmitter's readings 
never rise higher than 60.0 percent of the full scale range of the 
transmitter, then the transmitter could be tested at 0.0 percent, 30.0 
percent, and 60.0 percent of full scale. These procedures are reflected 
in the proposed revised section 2.1.6.1 of Appendix D.
    The Agency is proposing the second method in today's rule, i.e., 
that each individual transmitter must be tested at three or more points 
across its normal range of readings. EPA realizes that it is standard 
industry procedure to test a fuel flowmeter at five levels across its 
entire range (see Docket A-97-35, Item II-E-24). However, the Agency is 
aware of at least one case where a fuel flowmeter failed to meet an 
accuracy specification of 2.0 percent of the upper range value when it 
was tested at 100.0 percent of the upper range value. However, the fuel 
flowmeter was never used to measure a rate greater than roughly 55.0 
percent of the upper range value (see Docket A-97-35, Item II-D-15). If 
this flowmeter had only been required to test across the range where 
the fuel flowmeter actually measured fuel flow rates, it would have met 
the accuracy specification. Section 2.1.5 requires fuel flowmeters that 
are tested against a master fuel flowmeter to be tested across the 
range of measured fuel flowrate only. Requiring testing of each 
transmitter at three or more points across the range of all readings 
would still ensure that the transmitter reads accurately across all 
readings, while reducing the possibility that the transmitter might 
fail an accuracy test because of a high error reading at the high end 
of the transmitter's range where the transmitter is never used. At 
least one utility has mentioned that this would be helpful (see Docket 
A-97-35, Item II-E-24). The Agency solicits comment on the proposed 
approach.
    Today's proposed rule also includes Equation D-1a for calculating 
error from an individual flowmeter transmitter. The Agency feels that 
this would clarify the calculation. It also would prevent the possible 
confusion that would occur if a facility attempted to use the existing 
Equation D-1, which is designed for a fuel flowmeter that is compared 
to another fuel flowmeter.
    Finally, under today's proposal, when a transducer or transmitter 
test is failed, a fuel flowmeter would be considered out-of-control, 
and its data would be considered invalid until the date and time the 
transmitter is retested and meets an accuracy of 1.0 percent of its 
full scale.
(f) Reporting of Fuel Flowmeter Testing Data
Background
    As mentioned above in Section III.P.5 of the preamble, utilities 
have had questions about how to report the results of their fuel 
flowmeter testing data. In certification applications and quality 
assurance testing results, utilities have reported test data in a 
variety of ways. In some cases, the Agency was unable to determine the 
flowmeter accuracy from the testing information provided because data 
were not labeled as reference flow rate data, flowmeter data, or 
accuracy data. For example, for turbine flowmeters, data on the 
reproducibility of the ``K-factor'' was often presented. However, these 
are not flow rate data, nor is it clear what the accuracy of the flow 
rate is (see Docket A-97-35, Item II-D-9). Sometimes data were 
presented in tables. Other data were presented in graphs (see Docket A-
97-35, Item II-D-9). In many cases, Agency or state environmental 
agency staff needed to request additional information from utilities to 
determine if they had met the accuracy requirement for fuel flowmeters 
(see Docket A-97-35, Items II-C-3, II-C-5).
    To clarify the requirements for certification applications for fuel 
flowmeters, the Agency issued policy guidance about the type of 
information to provide (see Docket A-97-35, Item II-I-9, Policy Manual, 
Question 12.27). This guidance included a sample table with an example 
of how to submit information for a fuel flowmeter that is tested 
against a master meter or flow prover reference value.
Discussion of Proposed Changes
    EPA proposes to add a sample table to Appendix D (Table D-1) for 
summarizing the results of accuracy tests of fuel flowmeters that are 
calibrated by comparison against other fuel flowmeters or a prover. In 
addition, EPA proposes to add a separate table for summarizing the 
results of calibrations of the transmitters or transducers of an 
orifice-, nozzle-, or venturi-type fuel flowmeter.
Rationale
    In today's proposed rule, EPA would provide clarification in the 
form of a table for summarizing the quality assurance test results of 
fuel flowmeters that are compared against other fuel flowmeters or a 
prover. A second table is provided for summarizing the results of 
calibrations of transmitters or transducers of an orifice-, nozzle-, or 
venturi-type fuel flowmeter. This second table accounts for differences 
in the testing procedure for transmitters or transducers. In both 
cases, EPA has tried to make clear what critical information would have 
to be reported in order to demonstrate that the fuel flowmeter (or the 
transmitter of an orifice-, nozzle-, or venturi-type fuel flowmeter) 
meets the accuracy specification. In addition, EPA will design revised 
electronic record types with this type of information so that test 
results may be more easily reported electronically. The Agency is aware 
that this has been difficult or confusing for some utilities (see 
Docket A-97-35, Items II-D-23, and II-I-9, Policy Manual, Question 
12.27). The Agency also considered adding a sample graph for reporting 
accuracy data. However, EPA feels that it would be easier to compare 
the data in tabular format and to enter it into the electronic data 
format than to enter values from a graph. Most of the graphs provided 
to EPA have been relatively easy to read, and there appears to be less 
of a need for an example to be included in Appendix D (see Docket A-97-
35, Item II-D-9).
7. Use of Uncertified Commercial Gas Flowmeter
Background
    Currently, a facility using Appendix D may either install its own 
gas flowmeter or use a commercial gas flowmeter owned by a pipeline 
natural gas supplier, provided that the meter meets the reporting and 
accuracy requirements of Appendix D, including initial certification 
and continuing quality assurance requirements. Some utilities have 
suggested to EPA that they would like to be able to use data from the 
commercial billing of pipeline natural gas without having to 
demonstrate that the gas flowmeter meets initial certification and 
continuing quality assurance requirements (see Docket A-97-35, Items 
II-D-45, II-D-49). Those utilities assert that because the amount of 
gas measured is already subject to market forces, the monitoring should 
be sufficiently accurate for the Acid Rain Program. Utilities have 
mentioned that gas companies often are already conducting meter 
calibrations as quality assurance, but utility customers generally do 
not have access to this information (see Docket A-97-35, Items II-D-49, 
II-E-33). Facilities would find it advantageous to rely upon their 
commercial billing charges for accounting for pipeline natural gas 
usage because they would need to devote less time, effort, and money to 
the maintenance of gas fuel flowmeters. This is particularly desirable 
to facilities since the SO2 emissions from pipeline

[[Page 28100]]

natural gas are extremely low compared to the SO2 emissions 
from other fuels.
Discussion of Proposed Rule Changes
    Proposed section 2.1.4.2 of Appendix D would allow facilities to 
record and report the gas flow rate, the heat input rate, and emission 
values based on gas flowmeter readings from a flowmeter used for 
commercial billing of pipeline natural gas without meeting the 
certification requirements of section 2.1.5 of Appendix D or the 
quality assurance requirements of section 2.1.6 of Appendix D under 
specified conditions. Relief from the certification and quality 
assurance requirements for gas flowmeters used for commercial billing 
would be limited to flowmeters where the gas flowmeter is used for 
commercial billing under a contract with another company having no 
common owner with the unit(s) served by the flowmeter, which would 
exclude any gas flowmeters used for transfers of gas between different 
divisions, subsidiaries, or affiliates of the same company.
    If the commercial billing gas flowmeter would be used without 
undergoing certification or quality assurance under part 75 
requirements, then the designated representative would need to report 
hourly records of the gas flow rate, the heat input rate, and emissions 
due to combustion of pipeline natural gas, as well as heat input rate 
for each unit if the commercial billing gas flowmeter is on a common 
pipe header. This would be similar to the reporting currently done for 
a certified gas flowmeter, but no quality assurance records would be 
required. The quarterly report would contain record types 303 for fuel 
flow rate and heat input rate, record type 314 for the SO2 
mass emission rate, either record type 320 or 323 for the 
NOX emission rate in lb/mmBtu, and either record type 330 or 
331 for CO2 mass emissions. It also would be necessary for 
the designated representative to identify the commercial billing gas 
flowmeter in Table B (electronic record type 510) of the monitoring 
plan for the unit.
    So long as the records from the commercial billing gas flowmeter 
are the values used for commercial billing, the designated 
representative would report those values from the commercial billing 
gas flowmeter without adjustment. If the records from the commercial 
billing gas flowmeter are not consistent with the values used for 
commercial billing because of some problem that needs to be reconciled 
between the gas vendor and the facility customer, then the designated 
representative would consider the readings from the commercial billing 
gas flowmeter to be invalid for that billing period and would report 
hourly records using the missing data procedures for fuel flowmeter 
data found in section 2.4 of Appendix D for all hours of gas combustion 
during that billing period. A facility would not be able to use the 
commercial billing value in the quarterly report if the commercial 
billing value was different from the value on the commercial billing 
gas flowmeter.
Rationale
    Utilities have suggested that the purchase of pipeline natural gas 
from a vendor is subject to market forces that ensure accurate 
monitoring (see Docket A-97-35, Item II-D-49). Utilities have stated 
that gas vendors already have procedures for certification and meter 
calibration and that the gas vendors have an even greater incentive 
than utilities to maintain a high monitor ``uptime'' (i.e., 
availability) for gas fuel flowmeters. Typically, utilities will work 
together with their gas vendors if they believe there is any sort of 
discrepancy in their monthly billing for pipeline natural gas (see 
Docket A-97-35, Items II-D-33, II-E-33).
    The Agency believes that this argument is reasonable. However, EPA 
also understands that some utilities require their gas vendor to 
correct their billing values based upon the evidence of the utility's 
own gas flowmeters. In addition, it is likely that utilities will be 
combusting more pipeline natural gas in the future as they respond to 
current and potential future environmental requirements for reducing 
NOX and CO2. Therefore, the Agency believes that 
there must be conditions placed upon reporting emissions and heat input 
for the Acid Rain Program from gas flowmeters used for commercial 
billing if the gas flowmeters will not be required to meet the 
certification and quality assurance requirements of part 75.
    The Agency is proposing to limit the waiver from certification and 
quality assurance requirements to commercial billing gas flowmeters 
that are used in billing transactions between companies with entirely 
different ownership (e.g., a pipeline natural gas vendor and a separate 
electric utility company with no owners in common). Some utilities 
requested the relief from quality assurance requirements based upon the 
reasoning that a gas vendor would do its own quality assurance and 
maintenance, and perhaps with better accuracy than a utility would be 
able to maintain, but the utility would not necessarily have access to 
the test results and would not have control over what quality assurance 
might occur (see Docket A-97-35, Items II-D-49, II-E-33). This 
reasoning is sound if the utility and the gas vendor have no common 
owners, but it would not necessarily be sound if a gas supplier were 
part of the same company as the electric utility. Also, utilities 
suggested that a gas vendor may have an incentive to overstate the 
amount of gas in order to bill more, rather than having an incentive to 
underestimate or under-report (see Docket A-97-35, Item II-D-49). Once 
again, this argument is reasonable if the gas vendor is a separate 
entity, but may not be reasonable if the gas supplier has common owners 
with the electric utility. Therefore, today's proposed rule includes a 
limitation on the waiver from certification and quality assurance 
requirements for commercial billing gas flowmeters to those gas 
flowmeters used for commercial billing between companies with separate 
ownership.
    EPA solicits comment on the proposed approach of allowing the use 
of uncertified fuel flowmeters for purposes of determining emissions 
and heat input in the limited circumstances described above.
    EPA has proposed in today's rule that a facility may only report 
data from a commercial billing gas flowmeter if the data are used in a 
commercial transaction. A group of utilities suggested that the Agency 
allow facilities to report quarterly SO2 emissions based on 
gas supplier data, including any reconciliation that has taken place 
(see Docket A-97-35, Item II-D-45). Such a reconciliation between a gas 
vendor and its customer may occur if the customer believes there is a 
discrepancy in their monthly billing for pipeline natural gas (see 
Docket A-97-35, Items II-D-33, II-E-33). If a facility and its gas 
vendor determined that gas supply information from a fuel flowmeter 
were not sufficiently accurate to purchase gas, then the Agency 
presumes the gas supply information is also not sufficiently accurate 
for emissions accounting.
    The Agency also considered whether a facility should be able to use 
the reconciled gas volumes agreed upon for billing if that value were 
not from the commercial billing gas flowmeter. In general in the Acid 
Rain Program, hand-typed corrections to emissions data are not 
permitted (see Docket A-97-35, Item II-I-14), with the primary 
exception of cases where sound engineering judgement indicates there is 
an obvious error that cannot exist, such as a negative concentration 
reading.

[[Page 28101]]

Allowing a facility to enter a commercial billing value by hand would 
contradict this basic reporting policy of the Acid Rain Program.
    Today's proposed rule also specifies the type and frequency of 
information that would be required to be reported by a facility 
concerning pipeline natural gas. Some utilities have requested the 
ability to report only a quarterly cumulative SO2 mass 
emission number for emissions from gas (see Docket A-97-35, Item II-D-
45). However, the Agency believes that there are several reasons for 
maintaining hourly heat input rate and emissions data during combustion 
of pipeline natural gas. First, hourly data is the most useful interval 
of data for air quality modeling in order to see if progress is being 
made in reducing emissions. Hourly data from combustion of pipeline 
natural gas will become even more important as more units switch to 
combusting pipeline natural gas in order to reduce their emissions. In 
addition, hourly data are easier to check for anomalous values than 
quarterly data. Further, hourly heat input rate data is necessary in 
order to determine the NOX emission rate when using the 
NOX-versus-heat input rate correlation of Appendix E to part 
75. Also, since hourly data are already being recorded, reported, and 
processed by automated computer data acquisition and handling systems, 
a change to this requirement would require costly reprogramming for 
industry and for EPA. For all of these reasons, EPA is proposing that 
facilities continue to report hourly gas flow rates, heat input rates, 
and emissions from commercial billing gas flowmeters that are not 
required to meet the certification and quality assurance requirements 
of part 75.

Q. Appendix G

1. Use of ASTM D5373-93 for Determining the Carbon Content of Coal
Background
    Appendix G to part 75 provides procedures for determining 
CO2 emissions from fuel sampling and analysis instead of 
from a CO2 CEMS and a flow monitor. Section 2.1 of Appendix 
G includes a mass-balance equation for determining CO2 (see 
Equation G-1), the frequency for sampling fuel, and the specific 
methods for analyzing fuel for carbon content. Section 2.3 of Appendix 
G provides a method for determining CO2 mass emissions from 
a gas-fired unit from its heat input using Equation G-4. Some 
facilities use Appendix G procedures to determine CO2 mass 
emissions every day for their units. Other facilities might use the 
procedures of section 2.1 of Appendix G only to provide CO2 
mass emissions during extended periods when CO2 data are 
missing from their CO2 CEMS, under the provisions of 
Sec. 75.36.
    A utility and its fuel analysis laboratory contacted EPA concerning 
use of an additional ASTM method for analysis of carbon content. The 
industry staff felt that the new infrared analysis method, ASTM D5373-
93, was the most up-to-date method and that this method should be at 
least as accurate as the methods specified in Appendix G to part 75 
(see Docket A-97-35, Item II-D-25). Based upon the precision and bias 
information in the method, EPA approved its use under Sec. 75.66 (see 
Docket A-97-35, Item II-C-16).
Discussion of Proposed Changes
    Today's proposed rule would allow the use of ASTM D5373-93, 
``Standard Methods for Instrumental Determination of Carbon, Hydrogen, 
and Nitrogen in Laboratory Samples of Coal and Coke,'' for Section 2.1 
of Appendix G to part 75. This method is for determining the carbon 
content of coal. ASTM D5373-93 would also be incorporated by reference 
in Sec. 75.6. Facilities would also continue to have the option to use 
ASTM D3178-89 to analyze coal for carbon content.
Rationale
    EPA has previously approved the use of ASTM D5373-93 for analyzing 
the carbon content of coal (see Docket A-97-35, Item II-C-16). The 
Agency believes this method is of sufficient accuracy for use in the 
Acid Rain Program. In addition, EPA historically has accepted 
analytical methods from standard-setting organizations such as the 
American Society for Testing and Materials (ASTM). The Agency solicits 
comment on the use of ASTM D5373-93 for analyzing the carbon content of 
coal.
2. Changes to Fuel Sampling Frequency
Background
    Section 2.1 of Appendix G (as revised by the May 17, 1995 direct 
file rule) specifies that fuel sampling should be done weekly for gas 
or oil for each shipment for diesel fuel and at least once per month 
for gaseous fuel. The sampling frequencies for diesel fuel and for 
gaseous fuel are consistent with the frequency for sampling under 
Appendix D to part 75.
    Most gas-fired and oil-fired units that perform fuel sampling for 
sulfur content under Appendix D also perform fuel sampling for carbon 
content. Today's proposed rule would reduce the frequency with which 
facilities need to sample oil or gas under Appendix D.
Discussion of Proposed Changes
    The fuel sampling frequency specified in section 2.1 of Appendix G 
would be made consistent with the proposed requirements for Appendix D 
oil and gas sampling. Thus, all oil samples could be taken upon 
delivery, either from the delivery vessel itself or from the storage 
tank after a delivery is transferred. Gas samples would be taken 
monthly (for pipeline natural gas), for each shipment (for gases 
delivered in lots), or daily (for fuels that are analyzed daily for 
sulfur). Coal samples would continue to be taken weekly.
Rationale
    Appendix D of today's proposed rule would reduce the required 
sampling frequency of oil and gaseous fuels delivered in lots. Based 
upon information provided by one utility, the variability of carbon 
content in oil is less than the variability of sulfur content (see 
Docket A-97-35, Item II-D-18). Some utilities have stated that they 
would prefer the procedures for sulfur and GCV to be similar (see 
Docket A-97-35, Item II-D-24). Based upon this statement, the Agency 
believes that facilities would also prefer to have consistent fuel 
sampling procedures for Appendices D and G. Therefore, the Agency 
believes it is appropriate to make the fuel sampling frequency for 
carbon analysis under Appendix G consistent with the fuel sampling 
frequency for sulfur content under Appendix D. Similarly, section 5.5 
of Appendix F would be revised to make the gas sampling frequency 
consistent with Appendix D. The Agency solicits comment on the proposed 
changes to the fuel sampling frequency.
3. Addition of Missing Data Procedures for Fuel Analytical Data
Background
    Appendix D provides procedures for substituting missing fuel 
analytical information, either for sulfur or GCV. However, Appendix G 
to part 75 does not specify what should be done if carbon content data 
are missing.
    Some software programmers asked EPA what missing data procedures 
should be used for carbon content data (see Docket A-97-35, Item II-E-
5). The Agency responded to this question at a public conference and in 
policy guidance (see Docket A-97-35, Items II-E-5, and II-I-9, Policy 
Manual, Question 6.3). In its policy guidance, EPA stated that 
facilities should ``[f]ill in the most recent carbon content . . . 
available for that fuel type (gas, oil or

[[Page 28102]]

coal) of the same grade (for oil) or rank (for coal). If at all 
possible, use a carbon content value from the same fuel supply.''
Discussion of Proposed Changes
    Today's proposed rule would allow facilities to substitute for 
missing carbon content prior to January 1, 2000, using either the most 
recent carbon content for that fuel type, grade and rank, or procedures 
parallel to those of Appendix D. Beginning January 1, 2000, facilities 
would substitute for missing carbon content data using procedures 
consistent with Appendix D. For gaseous fuels and for oil sampled 
manually, these procedures would provide for a conservative maximum 
carbon content value. Specifically, the permissible conservative carbon 
content values would be either the maximum carbon content measured in 
the previous calendar year or, if this information were not available, 
a default value based upon handbook fuel characteristics. For weekly 
coal samples or composite oil samples, CO2 mass emissions 
would be calculated using the highest carbon content from the previous 
four carbon samples available.
Rationale
    Software programmers have already indicated that it is useful to 
have a procedure for filling in missing carbon content data for 
purposes of programming (see Docket A-97-35, Item II-E-5). Some 
utilities have stated that they would prefer the missing data 
procedures to be similar for both sulfur and GCV, even if both values 
are conservative (see Docket A-97-35, Item II-E-24). Therefore, the 
Agency believes that facilities would also prefer to have Appendix G 
missing data procedures for carbon content that are parallel with those 
for sulfur content and GCV in Appendix D. Thus, today's proposal would 
allow for missing data for manual oil samples or for gaseous fuel using 
the maximum carbon content measured in the previous calendar year or, 
if this information were not available, a default value based upon 
handbook fuel characteristics.
    In determining the conservative default carbon content values that 
would be used for missing data substitution in the event that no 
previous carbon content samples are available, the Agency consulted 
several handbook reference tables on fuel characteristics. 
Specifically, the Agency reviewed handbook values for the carbon 
content of coal (of various ranks), oil (of various grades), and gas 
(of different types). (see Docket A-97-35, Items II-I-18, II-I-19, II-
I-20). In the case of coal, there was a fairly wide range of carbon 
content values for different ranks of coal. Therefore, today's rule 
would propose separate default carbon content values for Anthracite, 
Bituminous, and Subbituminous/Lignite. In contrast, the carbon content 
values for different grades of residual oil were fairly consistent. For 
this reason, today's rule proposes a single default carbon content 
value for all grades of oil. Finally, for gaseous fuels, the handbooks 
which were reviewed presented a fairly narrow range of values for 
natural gas but a much wider range of values for other types of gaseous 
fuels. Therefore, today's rule proposes a value for natural gas and a 
separate, conservative value for all other types of gaseous fuels.
    The Agency solicits comment on the proposed revisions to the 
missing data procedures under Appendix D.

R. Reporting Issues

1. Partial Unit Operating Hours and Emission and Fuel Flow Rates
Background
    For affected units that use CEMS to account for emissions under 
part 75, hourly emission rates of SO2 (in lb/hr), 
NOX (in lb/mmBtu), and CO2 (in tons/hr), and 
hourly heat input rates (in mmBtu/hr) are calculated using the 
applicable equations in Appendix F. For affected units that use fuel 
flow meters and fuel analysis (or default emission rates) rather than 
CEMS, the applicable equations in Appendices D, F and G (for certain 
gas-fired units) are used to determine the hourly SO2 and 
CO2 mass emission rates and heat input rates. For oil and 
gas-fired peaking units that use Appendix E to account for 
NOX emissions, the hourly NOX emission rates in 
lb/mmBtu are derived from a graph of NOX emission rate 
versus heat input rate, the hourly heat input rates being derived from 
the applicable equation in Appendix F. Under Sec. 75.54(b)(2), unit 
operating time is reported by rounding the actual operating time up to 
the nearest 15 minutes.
    The equations in Appendices D through G assume that each unit 
operating hour consists of a full 60 minutes of unit operation (or, for 
common stacks, that emissions are discharged through the stack for 60 
minutes in each hour); the equations do not attempt to account for 
partial unit operating hours. This is a shortcoming in the current 
rule, because partial unit operating hours sometimes occur during 
periods of unit startup, shutdown, and malfunction. Therefore, to 
ensure accurate accounting of SO2 and CO2 mass 
emissions and unit heat input, part 75 should address the issue of 
partial unit operating hours. Note, that because NOX 
emission rates are measured with respect to heat input (lb/mmBtu), 
rather than with respect to time (lb/hr), this discussion is not 
relevant for NOX emission rate. Many vendors and utilities 
have asked EPA for guidance on how to calculate mass emission rates 
during partial unit operating hours (see, e.g., Docket A-97-35, Item 
II-D-4).
    The crux of the partial unit operating hour issue is when to adjust 
the emission data for unit operating time, before the reporting of 
hourly values or at the quarterly summation. For many units, there are 
very few hours of partial operation, and adjusting the data for 
operating time merely involves multiplying by 1, a seemingly 
inconsequential issue. For other units, such as peaking and cycling 
units, which start up and shut down often, the issue of how the data is 
reported is relevant because there can be a significant amount of 
partial unit operating hours. Definitive and standardized reporting 
requirements allow facilities and/or vendors to program their software 
such that their calculated result equals the result calculated by EPA.
    For SO2 and CO2, the question is whether to 
report hourly emissions on a mass basis (i.e., lb or tons) or on a mass 
emission rate basis (i.e., lb/hr or tons/hr). For heat input, the 
question is whether to report the total hourly heat input (in mmBtu) or 
the hourly heat input rate (in mmBtu/hr). For example, suppose that a 
unit emits for a full 60 minutes in a particular clock hour at an 
SO2 concentration of 602.5 parts per million (ppm), a 
CO2 concentration of 10.0 percent, a volumetric flow rate of 
4,000,000 standard cubic feet per hour (scfh), and a heat input rate of 
300 mmBtu/hr. Suppose further that the same unit operates for only 15 
minutes in the next hour and all of the parameters (i.e., 
SO2 and CO2 concentration, flow rate, and heat 
input rate) remain unchanged. If unit operating time is disregarded, 
the SO2 mass emission rate (calculated from Equation F-1 in 
Appendix F) would be the same (400 lb/hr) for both the partial 
operating hour and the full unit operating hour. Similarly, the 
CO2 mass emission rate would be the same (22.8 tons/hr) and 
the heat input rate would be the same (300 mmBtu/hr) for both the full 
and partial operating hours. The mass emission rates and heat input 
rate for the partial unit operating hour are the same as the full-hour 
values because they are based solely upon data recorded during unit 
operation, i.e., in

[[Page 28103]]

the first 15 minutes of the hour. The hourly average rates for the 
partial hour do not include ``zero'' values for the three 15-minute 
periods of unit non-operation during the clock hour (e.g., an 
SO2 emission rate of (400 lb/hr + 0 + 0 + 0)/4 = 100 lb/hr 
would not be appropriate). If the emission and heat input rates are 
adjusted by multiplying them by the operating time, then, for the full 
operating hour (i.e., operating time = 1.0), the SO2 and 
CO2 mass emissions and heat input would be, respectively, 
400 lb SO2, 22.8 tons CO2, and 300 mmBtu. For the 
partial hour (operating time = 0.25), the corresponding values would 
all be divided by four, i.e., 100 lb SO2, 5.7 tons 
CO2, and 75 mmBtu, respectively.
    Software vendors and utilities have requested clarification as to 
whether hourly SO2 mass emission values should be reported 
as totals, in lb, or as rates, in lb/hr. As early as November of 1993, 
EPA stated that hourly SO2 mass emission values should be 
reported as rates in lb/hr. Then, when determining quarterly cumulative 
SO2 mass emissions, each hourly emission rate would be 
converted to a mass basis by multiplying it by the unit operating time 
(expressed as a fraction of an hour) for the same hour. Similarly, 
hourly heat input values would be expressed as rates, in mmBtu/hr, and 
hourly CO2 mass emissions would be expressed as rates, in 
tons/hr. Parallel issues were also addressed by the Agency's policy, 
for units that determine SO2 and CO2 mass 
emissions and heat input from fuel flow rates and fuel analyses under 
Appendix D to part 75 (see Docket A-97-35, Item II-I-9, Policy Manual, 
Questions 14.14, 14.36 and 14.37).
    Some utilities have requested that the Agency change its policy and 
allow reporting of hourly total SO2 and CO2 mass 
emissions and heat input instead of mass emission rates and heat input 
rates (see Docket A-97-35, Item II-E-14). The utilities argued that 
this would simplify determination of the total year-to-date 
SO2 mass emissions, in order to estimate the number of 
allowances needed to cover a unit's emissions or to prepare a report on 
mass emissions for a state environmental agency, because the reported 
values would already be multiplied by the hourly operating time. Thus, 
by performing the multiplication by operating time before reporting the 
hourly value rather than waiting until calculating the quarterly value, 
it might save a calculation step if a facility wanted to use the data 
for another purpose. For these reasons, reporting of totals is a 
preferred approach for some facilities. However, other utilities that 
have incorporated the correct rate approach into their software have 
indicated that they would prefer not to have to revise their software 
to report in totals.
    Partial unit operating hours must also be considered in the 
recording and reporting of hourly unit load. The standard missing data 
procedures in Sec. 75.33 require historical flow rate data to be placed 
in load ``bins'' (ranges) based upon the maximum operating electrical 
generation (or steam flow rate) of the unit. However, the recorded 
hourly volumetric flow rate value in scfh applies only to the fraction 
of the hour in which the unit operates. Therefore, the reported load 
for the hour should be based upon the average electrical generation 
during the period when the unit operates. Thus, the electrical 
generation should be recorded as a rate for the period when the unit 
operates, rather than an integrated total for the entire hour. The 
units for reporting hourly load should, therefore, be MWe or 1000 lb/hr 
of steam, and not MW-hr or 1000 lb of steam.
Discussion of Proposed Changes
    In today's rulemaking, EPA is proposing to amend part 75 to clarify 
that heat input, fuel flow, SO2 mass emissions, and 
CO2 mass emissions are all to be reported on an hourly basis 
as rates. Today's proposal also would clarify that the hourly emission 
rates are to be based only upon data collected during periods of unit 
operation (i.e., for partial unit operating hours, emission rates or 
heat input rates of zero that are recorded during periods of non-
operation are not to be included in the hourly average emission rates). 
These clarifications are found in proposed Sec. 75.57, and Appendices 
D, E and F to part 75. Today's proposed rule would also clarify that 
the proper units of reporting for load are MWe and lb/hr of steam.
    Today's proposal would also provide new options for reporting unit 
operating time. While the current requirement to report operating time 
rounded to the nearest 15 minutes would be retained as an option, the 
proposal would allow more flexibility by specifying that, for reporting 
purposes, unit operating time be rounded up to the nearest fraction of 
an hour (in equal increments that can range from one hundredth to one 
quarter of an hour, at the option of the owner or operator).
    Consistent with the requirement to report hourly SO2 and 
CO2 mass emissions and hourly heat input as rates, today's 
rulemaking proposes to revise the quarterly summation formulas for 
SO2 and CO2 and to add summation formulas for 
heat input in Appendix F to part 75. The proposed formulas show that 
hourly mass emission rates or heat input rates would be multiplied by 
unit operating time before summing to get total mass emissions. Today's 
proposal also includes new formulas in Appendix D for summing hourly 
SO2 mass emission rates and hourly heat input values from 
fuel flowmeter systems in order to determine quarterly and annual total 
SO2 mass emissions and total heat input. The Appendix D and 
F equations revised or added to address summations include Equations D-
6, D-7, D-8, D-9, F-3, F-12, F-24, and F-25.
    In addition, EPA is proposing optional recordkeeping provisions for 
determining total heat input, total SO2 mass emissions or 
total CO2 mass emissions for the hour. In addition to 
reporting the required emission and heat input rates, owners or 
operators could choose to report the total hourly heat input and mass 
emissions under this option.
Rationale
    As stated above, some utilities have expressed a preference for 
reporting hourly total values for SO2 and CO2 
mass emissions and heat input, rather than rates (see Docket A-97-35, 
Item II-E-14). They have stated that this is easier to understand and 
that reporting hourly total values, instead of or in addition to rates, 
would make it easier to determine the cumulative total mass emissions 
at any time during the year.
    One representative requested that EPA consider allowing either 
method of calculation (i.e., hourly rates or totals), so long as the 
annual mass emissions and heat inputs are correctly determined and 
reported. EPA notes that, although this approach may appear 
advantageous because it would not require some facilities to reprogram 
their DAHS software, it would require other facilities to reprogram 
their software and it would make it difficult for EPA to verify 
emissions calculations from reported hourly data. Because EPA considers 
it essential to the Acid Rain Program to be able to recalculate annual 
compliance values based upon hourly emission information reported by 
facilities, the Agency is not revising the rule to take the 
representative's suggestion. EPA considered using the total mass 
emissions (or total heat input) approach instead of the mass emission 
rate (or heat input rate) approach currently stated in Agency policy 
(see Docket A-97-35, Item II-I-9, Policy Manual, Questions 14.14 and 
14.36). In fact, as discussed in section III.H. of this preamble, the 
Agency is proposing, under subpart H of part 75, model

[[Page 28104]]

reporting requirements for NOX mass emissions that would (if 
adopted by an applicable state or federal authority) require hourly 
NOX mass emissions to be reported as a total value (in lb) 
rather than an hourly mass emission rate (in lb/hr). However, using 
hourly mass emission totals for values currently reported to the Agency 
would have the distinct disadvantage of requiring both EPA and the 
utilities who correctly implemented the mass emission rate approach to 
reprogram software to perform the new calculations, whereas retaining 
the use of SO2 and CO2 emission and heat input 
hourly rates offers several advantages.
    First, using hourly mass emission rates and heat input rates 
instead of totals is consistent with the units of measure in which flow 
rate is recorded. Volumetric flow monitors measure flow rate during a 
given time in standard cubic feet per hour scfh, rather than total flow 
in standard cubic feet (scf). When SO2 concentration is 
multiplied by volumetric flow rate, one calculates a mass emission rate 
rather than a total mass of SO2. Similarly, multiplying a 
volumetric flow rate by a diluent gas concentration yields a heat input 
rate in mmBtu/hr, rather than a total heat input in mmBtu.
    Second, the current missing data procedures for volumetric flow 
rate, which are based upon the assumption that flow is a rate that is 
comparable from one hour to another, rather than a total volumetric 
flow that will vary depending upon the unit operating time, would no 
longer be appropriate if volumetric flow rate were changed to a total 
volumetric flow. Third, for Appendix E gas-fired or oil-fired peaking 
units, it is critical that heat input rate, and not total heat input, 
be used to determine the NOX emission rate. The Appendix E 
correlation curve formulas are based upon heat input rate rather than 
total heat input. Appendix E allows a facility to create a correlation 
of the NOX emission rate measured in the stack during stack 
testing and heat input combusted during that same period of time, 
rather than installing CEMS on gas-fired or oil-fired peaking units. If 
a facility were mistakenly to use the total heat input from an hour 
rather than the heat input rate, it would correlate to the wrong 
portion of the NOX to heat input rate correlation curve and 
would incorrectly estimate NOX emission rate. For example, 
if heat input totals were used to determine NOX emission 
rate from the Appendix E curve, the unit would have a different 
NOX emission rate if it combusted 25,000 mmBtu in half an 
hour than if it combusted 25,000 mmBtu during a full hour. This would 
apply both under the current provisions of Appendix E and today's 
revised provisions to Appendix E.
    In view of the above considerations, today's proposed rule would 
affirm that facilities are to report SO2 and CO2 
emissions and heat input as rates on an hourly basis. However, 
facilities would also be allowed, at their discretion, to report 
SO2 and CO2 emissions and heat input as hourly 
totals, in addition to reporting them as rates. This approach would not 
require reprogramming of computerized reporting software for those 
utilities that are following EPA's current policy, and would provide 
consistent reporting that allows EPA to recalculate emissions and heat 
input values. Those utilities that find recording and reporting of 
hourly total SO2 and CO2 mass emissions and heat 
input to be desirable would be able to do so. EPA will provide the 
necessary electronic record types to support this optional reporting.
    Although today's proposed rule would affirm that emissions and heat 
input are to be reported as rates, rather than totals, EPA has become 
concerned that for partial unit operating hours, some utilities are 
incorrectly calculating hourly average flow rates by including flow 
rates of zero in the hourly average to represent periods of non-
operation, rather than basing the average flow rate solely on the 
minutes of operation of the affected unit during the clock hour. In one 
example, it appears that the software is designed to calculate the 
average flow rate by including data from all minutes during those 
fifteen-minute quadrants of an hour when the unit operates, thus 
including some minutes when the unit is not operating, rather than 
creating an average flow rate just from merely those minutes when the 
unit is operating and emitting (see Docket A-97-35, Item II-C-17). EPA 
suspects that still other utilities may be calculating an average 
hourly flow rate that includes flow rates of zero for whole quadrants 
of an hour when a unit does not operate. This can result in the flow 
rate values for partial operating hours being under-reported to EPA and 
a lowering of the average flow rates in the load ranges used to provide 
substitute flow rate data, both of which can cause underestimation of 
SO2 mass emissions.
    The Agency is also concerned that this same kind of improper data 
averaging may be occurring when hourly gas concentrations are 
determined during partial operating hours. EPA would, therefore, 
require in today's proposal that facilities base all of their reported 
hourly average concentrations, flow rates, emission rates, and heat 
input rates solely upon data that are recorded during unit operation 
(that is, when the unit is combusting fuel and emitting).
    Some utilities have indicated that the approach of averaging in 
readings of zero from periods of non-operation has been incorporated to 
compensate for having to report operating time rounded up to the 
nearest fifteen minutes (Note, this is not an acceptable approach). A 
utility representative indicated that reporting operating time to less 
precision can cause overestimation of emissions because the operating 
time is multiplied by the mass emission rate. Thus, a mass emission 
rate of 400 lb/hr measured over a period of 20 minutes, during an hour 
when the unit shut down, would be multiplied by an operating time of .5 
hr (i.e., 20 minutes rounded up to the nearest fifteen minutes) and 
would result in 200 lb of SO2 being reported rather than the 
132 lb of SO2 that was actually emitted. The utility 
suggested that a solution would be to allow operating time to be 
reported to more precision than is currently allowed. Therefore, 
today's proposal would allow flexibility for reporting unit operating 
time to greater precision. While the current requirement to report 
operating time rounded up to the nearest 15 minutes would be retained 
as an option, the proposal would allow more flexibility by specifying 
that unit operating time be rounded up to the nearest fraction of an 
hour (in equal increments that can range from one hundredth to one 
quarter of an hour, at the option of the owner or operator). Thus, a 
facility could decide whether it had enough partial operating hours 
(e.g., unit start-ups and shutdowns) to merit changing their software 
to report operating time to more precision.
2. Use of Bias-Adjusted Flow Rates in Heat Input Calculations.
    In late 1995, the first year of the Phase I SO2 
allowance program, EPA conducted an audit of the Phase I-affected 
units. Data from the second quarter of 1995 were retrieved from the 
Emission Tracking System (ETS) in order to determine whether the 
SO2 emission rates and heat input values were being properly 
reported. The results of the audit showed that a number of sources were 
not reporting heat input correctly. The problem in most instances was 
that the unadjusted flow rate was being used in the heat input 
equation, rather than the bias-adjusted value. EPA believes that this 
is attributable to the fact that part 75 does not explicitly state that 
the bias-adjusted flow rate is to be used in heat input

[[Page 28105]]

calculations. The Agency has attempted to clarify this through policy 
guidance (see Docket A-97-35, Item II-I-9, Policy Manual, Question 
14.81). To correct the situation, the necessary language would be added 
to section 7.6.5 of Appendix A in today's proposed rule.
3. Removing the Restriction on Using the Diluent Cap Only for Start-Up
Background:
    Based on the May 17, 1995 direct final rule, sections 3.3.4, 4.1, 
4.4.1, 5.1, 5.2.1, 5.2.2, 5.2.3, and 5.2.4 of Appendix F currently 
provide for the substitution of a constant CO2 or 
O2 value for a measured value from a CO2 or 
O2 monitor during unit start-up. This provision was 
originally created in response to concerns from some utilities that 
their NOX emission rate in lb/mmBtu was being overestimated 
during unit start-up (see Docket A-90-51, Item IV-D-220, Letter from 
English, Mark G., Deputy General Counsel, Kansas City Power & Light 
Company on EPA's Proposed Part 75 regulations; see also Docket A-94-16, 
Item II-F-2). During unit start-up or other periods when the unit is at 
a low load level, CO2 concentrations are lower than during 
normal operation and O2 concentrations are higher than 
during normal operation. The NOX emission rate equation, 
however, is not designed to be used in these situations because it 
assumes complete combustion and normal operating conditions. As a 
result, the NOX emission rate equation overestimates the 
NOX emission rate when the CO2 concentration is 
very low or the O2 concentration is very high, such as 
during start-up. The equations for calculating emission rates in lb/
mmBtu use measured CO2 concentration or the difference 
between ambient air's O2 concentration and the measured 
O2 concentration in the denominator. For example, 
NOX emission rate is calculated using a NOX 
pollutant concentration monitor and a CO2 diluent monitor 
using the following equation:
[GRAPHIC] [TIFF OMITTED] TP21MY98.001

When a small CO2 concentration is entered into this 
equation, the calculated NOX emission rate will be very high 
and will overestimate the actual emissions.
    The idea of capping CO2 or O2 concentration 
was implemented in part 75 for determination of NOX emission 
rate, CO2 mass emissions, and heat input during unit start-
up. The cap concentration was set at a minimum CO2 
concentration of 5.0 percent CO2 and a maximum O2 
concentration of 14.0 percent O2, based upon some 
information provided by utilities for boilers (see Docket A-94-16, Item 
II-D-34).
    Some utilities asked EPA to consider extending this cap on diluent 
gas concentrations to other situations when a unit is operating at a 
low level (see, e.g., Docket A-97-35, Items II-D-20 and 30, and Docket 
A-97-35, Items II-E-13 and II-E-14). In addition to unit start-up, this 
might include periods of unit shutdown or unit ``banking,'' where a 
unit is combusting a very small amount of fuel to keep the boiler warm, 
but little or no electricity is generated. During these other 
situations where a unit operates at a low level, the CO2 
concentration will be very low and the O2 concentration will 
be very high, resulting in high calculated NOX emission rate 
values like those during unit start-up. One software vendor 
specifically mentioned that it would be easiest to implement the 
diluent cap if it could be used any time the CO2 
concentration would fall below or the O2 concentration would 
rise above the cap value (see Docket A-97-35, Item II-E-7). This could 
be implemented mathematically in the software, rather than having to 
examine the unit operation or the number of hours since the unit 
started operating in order to trigger use of the diluent cap.
    During the process of implementing the May 17, 1995 direct final 
rule, EPA issued guidance that explained that facilities may use the 
diluent cap values for calculating NOX emission rate during 
unit start-up whenever the CO2 concentration is below 5.0 
percent or the O2 concentration is above 14.0 percent, and 
also may use the actual measured CO2 or O2 
concentration values at all times for calculating CO2 mass 
emissions or heat input (see Docket A-97-35, Item II-I-9, Policy 
Manual, Question 14.39). In Question 14.39, EPA recommended that even 
if the diluent cap is used to calculate NOX emission rate, 
the actual diluent measurement should be used for the purpose of 
calculating CO2 mass emissions or heat input, because the 
purpose of the diluent cap was ``to avoid using an extreme diluent 
concentration in the denominator of the equation to calculate emission 
rate in lb/mmBtu.'' The formulas for calculating hourly CO2 
mass emission rate or hourly heat input rate do not use the 
CO2 or O2 concentrations in the denominator of 
the equation. Thus, use of the diluent cap would tend to overestimate 
both CO2 mass emission rate and hourly heat input.
Discussion of Proposed Changes
    Today's proposed rule would allow facilities to use diluent cap 
values of 14.0 percent O2 or 5.0 percent CO2 for 
boilers and 19.0 percent O2 or 1.0 percent CO2 
for turbines. For the purpose of calculating NOX emission 
rates in lb/mmBtu, the diluent cap would be allowed to be used for any 
hour in which the average measured CO2 concentration is 
below the cap value or the average measured O2 concentration 
is above the cap value. Diluent cap values would still be allowed to be 
used to calculate CO2 mass emissions or heat input, as well 
as NOX (or SO2) emission rate in lb/mmBtu.
Rationale
    EPA acknowledges that there are periods of low unit operation or 
low load in addition to unit start-up where the calculated 
NOX emission rate would be overestimated if it were based 
upon measured diluent concentrations. Therefore, the Agency believes 
that extending use of the diluent cap is appropriate. The Agency 
believes that allowing use of the diluent cap anytime when the actual 
measured value is above the cap (for O2) or below the cap 
(for CO2) is easier to program and to implement than 
limiting the use of the diluent cap based upon unit load, another 
option that EPA considered. The Agency believes that it is unlikely 
that a unit would ever be able to operate at a high load and still have 
an O2 or CO2 concentration beyond the diluent cap 
value. Therefore, it is not necessary to limit the use of the diluent 
cap value based on unit load.
    The Agency is also proposing new diluent cap values for turbines. 
Turbines tend to operate with much higher levels of excess 
O2 than boilers. For example, Method 20 of Appendix A, 40 
CFR part 60, the procedure for testing SO2, NOX 
and diluent gas from stationary gas turbines subject to the NSPS, 
requires testers to correct data to a typical concentration of 15.0 
percent O2. Emissions data reported to EPA confirms that for 
turbines, hourly concentrations of O2 are typically between 
14.0 and 16.0 percent and hourly concentrations of CO2 are 
typically between 3.0 and 4.0 percent. Thus, a turbine's diluent gas 
concentration is likely to consistently exceed the diluent cap value of 
14.0 percent O2 and to be consistently below the cap value 
of 5.0 percent CO2 promulgated in the May 17, 1995 direct 
final rule. If these values were allowed to be used by turbines at all 
times rather than just during unit start-up, a turbine

[[Page 28106]]

could conceivably report its NOX emission rate using only 
the diluent cap value and never report the actual monitored diluent 
concentrations, thereby consistently underestimating the NOX 
emission rate. Therefore, today's proposal provides diluent cap values 
of 19.0 percent O2 or 1.0 percent CO2 that are 
clearly beyond the typical O2 or CO2 
concentrations measured at turbines, while still providing some relief 
at extreme diluent concentrations. It is EPA's observation that 
turbines with NOX CEMS have not reported emissions using the 
diluent cap thus far. Thus, no turbines should need to reprogram 
software in order to report the use of the new diluent cap value for 
turbines with a new method of determination code.
    EPA considered removing the option for facilities to use the 
diluent cap for heat input rate and CO2 concentration, as 
well as for NOX (and SO2) emission rate in lb/
mmBtu, but is not proposing to do so in today's proposal. As explained 
previously, the diluent cap was created in order to calculate more 
representative NOX emission rate data during certain unusual 
circumstances. However, when a diluent cap value is used to calculate 
the hourly CO2 mass emission rate or the heat input rate, 
the final calculation would often be less representative of actual 
emissions or heat input during those hours. The Agency also found that 
allowing some facilities to use the diluent cap only for NOX 
emission rate and others to use the diluent cap also for hourly 
CO2 mass emission rate and heat input rate makes it 
difficult to check emissions and heat input rate data to verify that 
calculations are performed correctly. This is because a data 
acquisition and handling system could use either the actual reported 
diluent gas concentration or the diluent cap value to calculate 
NOX emission rate, CO2 mass emission rate, or 
heat input rate, but there is currently no provision in the electronic 
data reporting format for a facility to indicate which value was used 
to calculate the heat input. However, some utilities have indicated 
that making a change to discontinue using the diluent cap for 
calculations of heat input rate and CO2 mass emission rate 
would require a significant change in their software calculations (see 
Docket A-97-35, Item II-E-25). Therefore, today's proposed rule would 
allow facilities the options of (1) not using the diluent cap at all, 
(2) using the diluent cap only for calculating NOX (or 
SO2) emission rate in lb/mmBtu, or (3) using the diluent cap 
for calculating NOX (or SO2) emission rate in lb/
mmBtu, heat input rate, and CO2 emissions. In addition, EPA 
is proposing to add a minor additional reporting requirement to 
indicate whether the diluent cap is used in calculating CO2 
and heat input in the electronic data reporting format. This would 
allow EPA to verify facilities' calculations, while requiring less 
reprogramming than changing the calculations for heat input and 
CO2 emissions.
    The Agency solicits comment on the proposed revisions relating to 
the diluent cap.
4. Complex Stacks--General Issues
Background
    Many power plants regulated under part 75 have relatively simple 
stack and monitoring configurations. Many utilities have one stack for 
each affected unit and have CEMS installed on the stack. Other plants 
have more than one unit discharging to the atmosphere through a common 
stack, with CEMS installed on the common stack. Still others have 
individual units that exhaust into multiple stacks and have CEMS 
installed on each stack. The monitoring requirements for these various 
configurations are addressed in Secs. 75.13, 75.16, 75.17, and 75.18. 
EPA has issued guidance to assist utilities in preparing quarterly 
reports for these unit and stack configurations (see Docket A-97-35, 
Items II-I-4 and II-I-9, Policy Manual, Section 17).
    For the configurations described above, the process of accounting 
for emissions and heat input from the units and stacks will follow 
simple mathematical rules. For example, for single unit-single stack 
configurations, the emissions and heat input for the unit are directly 
determined from the stack CEMS (or from an excepted methodology, where 
applicable). For units discharging through a common stack with CEMS on 
the common stack, the combined emissions and heat input are determined 
from the CEMS, and the heat input to each individual unit is determined 
by apportionment of the combined heat input, using a ratio of the unit 
load to the combined load of all units utilizing the common stack. For 
a single unit exhausting through multiple stacks, the sum of the 
SO2 and CO2 mass emissions and heat input for the 
different stacks equals the total SO2 and CO2 
mass emissions and heat input for the unit.
    However, in implementing part 75, EPA has become aware of a number 
of affected units that have stack exhaust configurations which are more 
complex than the configurations described above. For example, one 
utility has a configuration in which two units can emit through two 
different stacks at the same time, combining their emissions in both 
stacks (see Docket A-97-35, Items, II-C-1, II-D-12). In this case, the 
stack configuration is both a common stack and a multiple stack 
configuration. EPA has had significant problems in determining the 
emissions and heat input from these units, and in one case, EPA 
rejected the quarterly reports for the units (see Docket A-97-35, Item 
II-C-8). The utility worked closely with EPA to resolve the reporting 
issues resulting from this unusual situation (see Docket A-97-35, Item 
II-D-21). Other utilities with similar situations have contacted the 
Agency to ensure there would not be problems with their reporting (see, 
e.g. Docket A-97-35, Item II-D-5).
    There have been other cases in which a unit that is accountable for 
holding SO2 allowances shares a common stack with a unit 
that does not hold SO2 allowances (e.g., where an affected 
unit and a non-affected unit share a common stack or, prior to 1/1/
2000, where a Phase I unit and a Phase II unit share a common stack). 
These are termed ``subtractive stack'' situations in the following 
discussion. Utilities with subtractive stack situations have generally 
used the provisions of Sec. 75.16(a)(2)(ii)(C) or 
Sec. 75.16(b)(2)(ii)(B). These provisions allow a facility to monitor 
separately the common stack and the unit with no allowance requirement 
and to subtract the emissions from the non-affected or Phase II unit 
from the common stack emissions. In some cases, it has not been clear 
in the electronic quarterly reports whether a utility is reporting 
combined emissions from all of the units using the common stack or 
whether the emissions from the non-affected unit(s) have already been 
subtracted out of the reported emissions (see Docket A-97-35, Item II-
C-18). This confusion in interpreting the quarterly emissions reports 
has made compliance determination difficult.
    The Agency found that there is a potential problem with the 
underestimation of emissions using this subtractive approach. In some 
cases, the error in the monitors' measurements might be such that a 
larger emissions value is subtracted from a smaller value, resulting in 
the reporting of false negative emissions (see Docket A-97-35, Item A-
94-16-IV-D-18, Comments from Monitor Labs). In other cases, there may 
be an incentive for making inaccurate measurements with the monitoring 
systems installed on a unit with no allowance requirement. For

[[Page 28107]]

example, if the SO2 pollutant concentration monitor on a 
unit with no allowance requirement did not operate properly and had a 
significant amount of missing data, the facility would calculate 
SO2 emissions from the unit using a conservative, high 
concentration value. Therefore, emissions reported for the units with 
allowance requirements would, as a result of the subtraction, be less 
than the actual emissions. Thus, a facility might have a disincentive 
for good monitor performance and accuracy, because it could lower the 
emissions reported for the units with allowance requirements. Though 
allowed under the current wording of Appendix A to part 75 and subpart 
D of part 75, this is contrary to the intent of the missing data 
substitution procedures, which is to encourage good monitor performance 
while preventing any systematic underestimation of emissions. (See 
Docket A-97-35, Items II-B-13, II-E-4, and II-I-12.)
Discussion of Proposed Changes
    Today's proposed rulemaking would add a general regulatory 
requirement to Secs. 75.16 and 75.17 for facilities with complex stack 
configurations (i.e., subtractive stack situations or configurations 
involving combinations of common stacks and multiple stacks) to receive 
approval from EPA's Administrator for a method of calculating and 
reporting emissions from the units and stacks in the configuration. The 
facility would be required to reach agreement with the Agency on issues 
such as: identification of the stack in its quarterly report, 
representation of the configuration in its monitoring plan, groups of 
units for which cumulative emissions must be reported, testing 
procedures, use of the bias test, and use of the missing data 
substitution procedures. This would apply both to sources that already 
have certified monitoring equipment and are submitting quarterly 
reports and to units that do not yet have certified monitoring systems 
(e.g. new units).
Rationale
    The Agency evaluated two basic approaches to resolving issues in 
these complex stack monitoring configurations. First, EPA considered 
resolving the issues through policy guidance and through instructions 
for submitting quarterly reports. Second, the Agency considered putting 
detailed instructions in part 75 for reporting from and testing of 
monitoring systems installed in these complex stack configurations. 
These rule provisions would have explicitly addressed missing data 
substitution to ensure that when emissions are reported, they are not 
underestimated from units with an allowance requirement or a 
NOX emission limitation. For example, EPA could have 
required, for the subtracted unit(s), that the facility only use those 
provisions of the standard missing data procedures that are not 
intended to be conservative estimates, such as the average 
SO2 concentration during the hour before and the hour after 
a missing data period. Another approach for missing data substitution 
could have been to count zero emissions for the unit with no allowance 
requirement during any missing data periods. Or perhaps creation of a 
site-specific missing data procedure could have been required (see 
Docket A-97-35, Items II-E-4 and II-I-12). To prevent a potential 
underestimation of emissions and a disincentive for more accurate 
monitoring due to application of a bias adjustment on a monitor on a 
unit with no allowance requirement where its emissions are subtracted 
from a common stack, EPA could have required that the bias calculation 
be based upon both the monitors on the common stack and the monitors on 
units with no allowance requirement, resulting in a single bias 
adjustment factor for the subtractive stack situation.
    However, EPA's experience thus far in implementing the program 
indicates that each complex monitoring configuration tends to be 
unique. Thus, the Agency has rejected the two approaches discussed 
above and has decided instead to make General regulatory revisions that 
allow for case-by-case resolution of issues in individual plant 
situations, rather than making extensive, detailed revisions to part 75 
to address each unique situation.
    The Agency prefers to make regulatory revisions rather than 
addressing issues solely through policy and guidance. In some cases, 
the Agency has given advice to utilities on how to report emissions, 
and the utility involved has not followed the Agency guidance (see 
Docket A-97-35, Items II-C-7, II-C-24, and II-D-8). In another case, 
the current provisions of part 75 for missing data substitution and for 
the bias test appeared to be in conflict with guidance that the Agency 
wanted to issue in order to ensure that emissions are not 
underestimated in a subtractive stack situation (see Docket A-97-35, 
Item II-B-13). Therefore, today's proposed rule would require owners or 
operators of facilities with complex stack configurations to apply for 
approval of their monitoring plans and reporting methodologies from 
EPA's Administrator on a case-by-case basis. The Agency believes that 
the General regulatory provisions requiring approval of a complex 
monitoring situation by EPA's Administrator will give both facilities 
and the Agency flexibility to deal with site-specific cases, while also 
giving the Agency regulatory authority to resolve any case-specific 
problems.
    It is possible that any final rule resulting from today's proposal 
may not be promulgated until 1999. Thus, EPA is proposing to require 
the Administrator's approval of the monitoring plans and reporting 
methodologies only for those situations that will exist on and after 
January 1, 2000. Any subtractive stack situations that exist only 
during the duration of Phase I would not fall under this requirement. 
However, complex stack situations that exist where affected and non-
affected units share a common stack would need to meet today's proposed 
requirement. Similarly, in situations where coal-fired units sharing a 
common stack have different NOX emission limitations under 
part 76, or situations where some units sharing a common stack have a 
NOX emission limitation under part 76 and others have no 
NOX emission limitations under part 76, any complex 
monitoring configuration would need to be approved by EPA's 
Administrator.
5. Complex Stacks--Heat Input at Common Stacks
Background
    For a unit that utilizes a flow monitor to determine SO2 
mass emissions, section 5 of Appendix F to part 75 requires heat input 
to be calculated using the installed flow monitor and a diluent gas 
(O2 or CO2) monitor. The January 11, 1993 final 
rule indicated that units with common stacks, multiple stacks, or 
bypass stacks should follow the same General procedures for monitoring 
heat input as are used for monitoring SO2 under Sec. 75.16. 
As written, those procedures allowed facilities to monitor their heat 
input either by placing individual monitors on each unit that serves a 
common stack or by placing monitors only on the common stack and 
measuring a combined heat input from all of the units sharing the 
common stack. The May 17, 1995 rule required the combined heat input 
measured by monitors on the common stack to be apportioned to the 
individual units, in two specific provisions. First, unit level heat 
input was required under Sec. 75.16(e)(2) for cases in which a 
knowledge of the heat input for each unit is critical to compliance 
determination (i.e., for situations where any units using the common 
stack have

[[Page 28108]]

a NOX emission limit). Second, Sec. 75.16(e)(3) required 
unit level heat input to be determined for all other common stacks, but 
only until the year 2000. The November 20, 1996 rule outlined the 
acceptable methodology for apportioning heat input, i.e., by using the 
ratio of the unit load in MWe or lb of steam per hour to the combined 
load of all units utilizing the common stack (provided that all of the 
units utilizing the common stack are combusting fuel with the same F-
factor).
Discussion of Proposed Changes
    Today's proposed rule would revise the existing requirements found 
in Sec. 75.54(b) and two specific provisions of Sec. 75.16(e) for 
accounting of heat input for units serving a common stack, a by-pass 
stack, or multiple stacks. First, EPA would require determination and 
reporting of the unit level heat input to be continued after the year 
2000 for all affected units, rather than restricting it to certain 
situations after 2000. Second, EPA would clarify that the proper units 
of measure for load to be used in an apportionment of common stack heat 
input to determine unit level heat input are totals of MWe-hr and 1000 
lb of steam, rather than rates of MWe and 1000 lb/hr of steam.
Rationale
    EPA considered leaving the current provisions of Sec. 75.16(e) and 
Sec. 75.54(b) from the May 17, 1995 and November 20, 1996 rules 
unchanged. However, this would have the serious drawback of requiring 
the facilities to reprogram their computer software for certain units 
and not for others. Corresponding monitoring plan changes would also be 
required. Additionally, EPA would have to reprogram its emission 
tracking software to accommodate two different heat input reporting 
methodologies for common stacks. In view of these considerations, EPA 
is proposing to continue to receive individual heat input data from all 
affected units. This information is useful for developing inventories 
of total NOX mass emissions in tons in support of other 
Agency rulemakings. Without such information, the inventories would be 
based on assumptions about how units operate, rather than being based 
on unit level heat input as reported from the facility.
    The Agency believes that a relatively small number of sources would 
be affected by this proposed change. This is because (1) most coal-
fired units would still need to report unit level heat input under the 
current provisions of Sec. 75.16(e)(2), even after the year 2000; and 
(2) gas-fired and oil-fired units using fuel flowmeters to determine 
heat input and to implement the procedures of Appendix D or Appendix E 
would still be required to monitor heat input for each unit under 
section 2.1 of Appendix D. Because of the usefulness of having heat 
input data for individual units, because of the burden of reprogramming 
software to remove the heat input apportionment by the year 2000, and 
because of the small number of sources that would benefit from 
retaining the current provisions of Sec. 75.16(e)(3), EPA believes it 
is reasonable to require all units that measure combined heat input at 
a common stack to continue to apportion heat input to the individual 
units. The Agency solicits comment on the number of sources that would 
be affected by this revision.
6. Start-Up Reporting--Units Shutdown Over the Compliance Deadline
Background
    As currently written, part 75 requires that units which are 
shutdown over an applicable compliance date specified in Sec. 75.4 must 
submit a notice of the planned and (if different) actual shutdown date. 
In addition, Sec. 75.4(d) provides an extended certification deadline 
for such units of ``the earlier of 45 unit operating days or 180 
calendar days after the date that the unit recommences commercial 
operation of the affected unit.'' If an owner or operator subsequently 
recommences commercial operation of the unit, a notice related to the 
planned and (if different) actual date of recommencement of commercial 
operation is required. In addition to these notices, Sec. 75.64 
requires that after the applicable compliance date passes, the owner or 
operator must submit quarterly reports for such units. If the unit 
remains shut down and does not operate during the quarter, the 
quarterly report must show zero emissions. Utility commenters (see, 
e.g., Docket A-97-35, Items II-D-20, II-D-30) have recommended that 
this quarterly report requirement for shutdown units be deleted because 
it is unnecessary and burdensome.
Discussion of Proposed Changes
    Section 75.64(a) would be modified so that quarterly reporting is 
not required until the first quarter in which a previously shutdown 
unit recommences commercial operation. In this case, the first 
quarterly report would contain data beginning with the hour in which 
the unit recommences commercial operation.
Rationale
    Units that are shutdown over their applicable certification 
deadlines are required to submit notice, pursuant to Sec. 75.61(a)(3), 
of the planned date of recommencement of commercial operation and also 
must submit a follow-up notice if the actual date of recommencement of 
commercial operation is different from the planned date. As a result of 
these notice provisions, EPA will know whenever the status of a 
shutdown unit changes. Because shutdown units have no emissions, the 
Agency believes that quarterly reporting in addition to the notice 
provisions is unnecessary to fulfill the emission reporting objectives 
of the Act.
    The Agency notes, however, that the proposed revision differs from 
that suggested by certain utilities (see Docket A-97-35, Item II-D-30). 
The utilities proposed tying the reporting requirement to the 
certification deadline in Sec. 75.4(d). However, under Sec. 75.4(d), 
facilities are required to report emissions data using special 
provisions in that section prior to the extended certification deadline 
in Sec. 75.4(d). Thus, the proposed revisions would tie the obligation 
for quarterly reporting to the quarter in which commercial operation is 
recommenced.
7. Start-Up Reporting--New Units
Background
    As currently written, Sec. 75.64(a) requires the first quarterly 
report for new units to be submitted for the quarter corresponding to 
the compliance date in Sec. 75.4. However, the current provision is 
unclear about which hourly emissions data need to be included in the 
first quarterly report if the compliance deadline does not correspond 
to the first hour in the quarter.
Discussion of Proposed Changes
    Section 75.64(a) would be modified to clarify that a new unit must 
start reporting data beginning with the earlier of the date and time of 
provisional certification or the compliance deadline in Sec. 75.4(b).
Rationale
    These proposed revisions are generally consistent with existing 
implementation of the new unit reporting requirements, and primarily 
would serve to clarify ambiguous elements of the current rule.

[[Page 28109]]

8. Recordkeeping and Reporting Provisions
Background
    Subpart F and subpart G of the existing part 75 regulation set 
forth the recordkeeping and reporting requirements that accompany the 
monitoring provisions of part 75. Specifically, in subpart F, 
Sec. 75.53 contains the monitoring plan requirements, Sec. 75.54 
contains the general recordkeeping provisions, Sec. 75.55 lists the 
general recordkeeping provisions for specific situations, and 
Sec. 75.56 consists of the certification, quality assurance and quality 
control record provisions. In subpart G, Sec. 75.62 lists the 
monitoring plan reporting provisions, Sec. 75.62 contains the reporting 
requirements for initial certification and recertification 
applications, and Sec. 75.64 discusses the provisions for quarterly 
reports. Quarterly reports are electronic data files containing 
emissions and operating data from affected units, as well as monitoring 
plan information and the results of certification and quality assurance 
tests. Under Sec. 75.64, these electronic data reports are required to 
be submitted to the Agency each calendar quarter. This electronic 
information is used by the Agency for many different purposes, 
including implementation of the SO2 allowance trading 
program, determination of compliance with emission limits, development 
of reports on utility emissions, and modeling of air quality to assess 
the effectiveness of the Act.
    In order to effectively use the electronic quarterly report 
information, EPA created a standardized reporting format, the 
electronic data reporting (EDR) format. The electronic file formats and 
record structures of the EDR provide the vehicle by which required 
information is submitted to the Agency every calendar quarter. The EDR 
primarily defines the order, length, and placement of information 
within the electronic report or file. The individual tables of the EDR 
define the record type, type code, start column, data element 
description, units, range, length, and FORTRAN format for each data 
element in the electronic report. The information in the EDR fields 
mirrors the required information set forth in subparts F and G of part 
75. Considering both the volume of information contained in each 
quarterly report (e.g, operating and emissions data for each of the 
hours in the quarter) and the number of reports submitted to the Agency 
(i.e., currently, 1765 reports are received each quarter for the 2055 
affected units; some reports contain information for more than one unit 
if several units are interrelated, as in a common stack configuration), 
a standard format is critical in order for the Agency to review, 
verify, and use the information reported. A standard format allows the 
Agency to develop software to receive and verify the files and to 
correlate and separate out specific information for compliance 
determinations. A standard format also allows software vendors to 
create standard software which can be utilized by many affected units. 
This is more cost effective than developing site-specific software and 
thus reduces the software cost to industry.
    Today's rulemaking proposes a number of revisions to subparts F and 
G of part 75 (the reporting and recordkeeping sections of the rule). 
The majority of these changes are necessary to implement the proposed 
substantive revisions to the sections of the rule and appendices 
discussed elsewhere in this notice. In addition, EPA is 
proposingrevisions to these subparts in order to streamline 
implementation of the program and to coordinate reporting under the 
Acid Rain Program with other programs.
    To support the changes to the recordkeeping provisions, new 
Secs. 75.57, 75.58, and 75.59 would be added. These sections would 
replace existing Secs. 75.54, 75.55, and 75.56. The addition of new 
sections is necessary because the proposed revisions would not be 
mandatory until January 1, 2000, and to have the proposed revisions 
listed throughout existing effective sections could lead to confusion. 
However, an owner or operator would be free to follow the provisions of 
Secs. 75.57, 75.58, and 75.59 before January 1, 2000, if he chooses to 
do so. In addition, the owner or operator would be required to satisfy, 
prior to January 1, 2000, the elements in these sections that support a 
regulatory option proposed in other sections of part 75 if the owner or 
operator elects to implement that option prior to January 1, 2000.
    Because, as discussed above, the Acid Rain Program relies on a 
standardized electronic data reporting format, EPA has also developed 
draft revisions to the EDR formats and instructions (draft EDR version 
2.1). The following discussion refers to both the rule sections and EDR 
record types (RTs) that would be affected by the proposed revisions.
Discussion of Proposed Changes
    There are a number of proposed rule changes to the recordkeeping 
and reporting requirements of part 75 and corresponding draft EDR 
revisions that would be necessary to implement the substantive 
revisions proposed by EPA and discussed elsewhere in this preamble. 
These include the following requirements:
    (1) Changes to support new CO2 missing data requirements 
(see Sec. 75.57 and RT 202, 210, and 211);
    (2) Changes to support new reporting, QA and missing data 
requirements for moisture monitoring (see Secs. 75.53, 75.57, and 
75.59, and RT 211, 212, 220, and 618);
    (3) Changes to support optional Appendix I (flow methodology for 
gas and oil units) (see Secs. 75.57 and 75.58, and RT 220, 302, 303, 
608, and 609);
    (4) Changes to support more flexibility for units that have 
multiple range analyzers (see Secs. 75.53 and 75.59, and RT 230, 530, 
600, 601, and 602);
    (5) Changes to support the use of the diluent cap during all hours 
(see Sec. 75.57 and RT 300 and 330);
    (6) Changes to support test exemptions and extensions for units 
that operate infrequently (see Secs. 75.59 and 75.64, and RT 301, 697, 
and 698);
    (7) Changes to support increased flexibility in fuel sampling (see 
Sec. 75.58 and RT 302, 303, 313, and 314);
    (8) Changes to allow reporting of hourly total values in addition 
to hourly rates (see Sec. 75.57 and RT 300, 310, and 330);
    (9) Changes to support the proposed re-definition of unit operating 
loads (see Secs. 75.53 and 75.59, and RT 535 and 611);
    (10) Changes to support reporting of conditional data during 
recertification events (see Sec. 75.59, and RT 556);
    (11) Changes to support a new quarterly flow-to-load QA check for 
flow monitors (see Sec. 75.59, and RT 605 and 606);
    (12) Changes to allow QA test grace periods (see Sec. 75.59, and RT 
699);
    (13) Changes to support simplified reporting for low mass emissions 
units (see Secs. 75.53, 75.58, and 75.63, and RT 360, 508, and 531);
    (14) Changes to support fuel flow-to-load QA checks for fuel flow 
meters (see Sec. 75.59, and RT 628 and 629); and
    (15) Changes to support expanded reporting of RATA supporting 
information (see Sec. 75.59, and RT 614, 615, 616, 617, and 618).
    In addition, since the EDR version 1.3 was released, EPA has 
developed additional record types to aid in the implementation of the 
program, by allowing the designated representative to certify the 
validity of quarterly reports using an electronic certification 
statement. The proposed revisions would adopt the necessary rule 
language to implement these miscellaneous record types (see Sec. 75.64, 
and RT 900, 901, 910, and 920).

[[Page 28110]]

    The proposed revisions would also set forth optional requirements 
for reporting of NOX mass emissions that states or EPA could 
adopt as part of a NOX mass trading program, such as the OTC 
NOX Budget Program. In this situation both a rule change and 
an EDR change would be needed (see Secs. 75.57 and 75.64 and RT 301, 
307, and 328).
    The proposed rule revisions also include a number of changes that 
EPA believes will facilitate implementation of the program. These 
include:
    (1) Reporting of test numbers, reasons for tests and indicators of 
aborted tests (see Sec. 75.59, and RT 560, 600, 601, 602, 603, 610, and 
611);
    (2) Changing the deadlines for reporting the RATA supporting 
information that was originally required on January 1, 1998 (see 
Sec. 75.59, and RT 614, 615, 616, 617, and 618);
    (3) Reporting of an optional record type that will allow facilities 
to provide contact person information that many facilities currently 
provide in quarterly report cover letters (see Sec. 75.59, and RT 999);
    (4) Based on comments received, the rule would be revised so that 
reporting the reasons for missing data as part of the quarterly report 
would become optional, but would still need to be maintained on-site 
(see Secs. 75.56 and 75.59, and RT 550);
    (5) Reporting of facility location, identification, and EDR version 
numbers to support the transition from EDR 1.3 to EDR 2.1 (see 
Sec. 75.64, and RT 100 and 102);
    (6) Reporting of information documenting the calculation of heat 
input (see Sec. 75.57, and RT 300);
    (7) Reporting of reference method backup QA data (see 
Sec. 75.59(a)(11), and RTs 260, 261, and 262);
    (8) Expanded reporting of unit definition information (see 
Secs. 75.53, and RTs 504, 585, 586, and 587);
    (9) Reporting of Appendix E segment ID information (see Sec. 75.58, 
and RT 323, 324, and 560);
    (10) Reporting of qualification data for peaking units or gas-fired 
units (see Sec. 75.53, and RT 507);
    (11) Reporting of the qualifying test for off-line calibrations 
(see Sec. 75.59, and RT 623);
    (12) Reporting of Appendix E emission rate test data (see 
Secs. 75.59, and RT 650-653);
    (13) Reporting of span effective date information and flow rate 
span values (see Sec. 75.53, and RT 530); and
    (14) Removal of the recordkeeping provisions of Secs. 75.50, 75.51, 
and 75.52 that are no longer effective.
Rationale
    The majority of the proposed changes to subparts F and G are needed 
to support proposed substantive changes elsewhere in part 75. EPA is 
also proposing certain minor revisions to the order and wording of 
provisions in these subparts so that the records required by the rule 
match up consistently with the record type descriptions in the EDR. 
Certain utility groups previously had objected that EPA had not made 
the EDR format available for formal public notice and comment. The 
Agency maintains that it is not required to provide notice and comment 
for the EDR. The data included in (or proposed to be included in) the 
EDR are also listed in the rule (or the proposed rule revisions) as 
requirements under the recordkeeping and/or reporting provisions of 
Secs. 75.53 through 75.64, which have already undergone (or are 
undergoing) public notice and comment. Since the EDR simply shows how 
to present electronically the data whose submission is (or will be) 
required by the rule, it is the rule, not the EDR, that imposes the 
data requirements. Notice and comment on the contents of the EDR would 
therefore be unnecessary and duplicative. Moreover, the requirement to 
present the rule's data requirements in a specified format is 
authorized by Sec. 75.64(d), which requires a quarterly report to be 
submitted in the format specified by the Administrator. Like the data 
requirements, this format requirement in part 75 was adopted after 
public notice and comment.
    In today's rulemaking, EPA has developed draft EDR revisions 
simultaneously with the proposed rule revisions and is therefore 
including the draft EDR revisions in the docket for comment at the same 
time as the proposed rule revisions (see Docket A-97-35, Item II-A-12). 
EPA is also posting the draft EDR v2.1 revisions and draft EDR v2.1 
reporting instructions on the Acid Rain Homepage (www.epa.gov/
acidrain). However, the Agency maintains that notice and comment are 
not necessary for revisions to the EDR so long as the data included in 
the EDR is the same as the data required by rule provisions that have 
undergone or are undergoing notice and comment. Thus, future EDR 
revisions may be made without prior notice and comment on the EDR in 
order to implement rule revisions for which notice and opportunity for 
comment are provided. However, the Agency will continue its informal 
procedures for involving the affected stakeholders in any such EDR 
revisions.
    There are a number of other proposed changes to Secs. 75.54-75.64 
that have been included to implement existing provisions in other 
sections of part 75. First, information on test numbers and reasons for 
tests would be required so that quality-assurance test data can be more 
easily correlated and interpreted. Second, the reporting of various 
run-specific and point-specific RATA support information would be 
required (e.g., point velocity head readings, gas reference method 
quality-assurance data, moisture reference method data, etc.). The 
Agency believes that most testing companies currently either collect 
these data electronically or enter the data into computer programs 
manually to determine RATA results. By requiring the reporting of these 
data elements in a standard electronic format, the Agency believes that 
both facilities and regulatory personnel would be able to more easily 
interpret data that are currently provided by test contractors in many 
different hardcopy formats.
    The Agency is proposing not to require the electronic reporting of 
RATA support information prior to the year 2000. Sections 75.56 
(a)(5)(iii)(F) and (a)(7) and Sec. 75.64(a)(1) of part 75 currently 
require RATA supporting information to be reported in the electronic 
quarterly report. EPA believes, however, that it would be more cost 
effective to require the more detailed RATA support records to be 
electronically reported beginning in the year 2000, rather than having 
a two-stage implementation. The Agency has notified all designated 
representatives that this RATA supporting information will not be 
required to be reported electronically, in RT612 and 613 of the 
quarterly report, prior to January 1, 2000.
    The Agency notes that certain data elements (e.g., yaw angle, pitch 
angle, axial velocity, wall effect point identifier, etc.) have been 
included in anticipation of future revisions to EPA Reference Method 2. 
EPA is presently evaluating a number of alternative flow rate 
measurement methodologies, such as the use of a 3-dimensional probe. 
Depending on the outcome of the Agency's evaluation, one or more of 
these alternative flow measurement techniques may be allowed beginning 
in the year 2000. Therefore, EPA believes it is appropriate to include 
data elements to support these anticipated Method 2 revisions in draft 
EDR version 2.1.
    Finally, by changing the requirements for reporting the results of 
the most recent RATA from requiring it to be reported in the quarter in 
which it was

[[Page 28111]]

performed, to requiring it to be reported in the quarter in which it 
was performed and each subsequent quarter in which a BAF that was 
calculated using the results of that RATA are used, EPA would make the 
individual quarterly reports more self contained and make it easier for 
people who are using the reported data to understand how the BAFs 
reported in those reports were applied. EPA considered adding a field 
to the hourly emissions data record for each pollutant to indicate the 
BAF applied in that hour. However, the Agency received requests from 
utilities on an early draft of the EDR revisions that the hourly 
emissions data record types not be revised to add a field for BAF. The 
Agency believes that reporting the results of the most recent RATA, 
including the BAF, in each quarterly report would accommodate the 
utilities' requests not to add the BAF to each hourly record type and 
would achieve the objective of making the quarterly reports easier to 
interpret because the BAF being applied will be found in each quarterly 
report. In addition, since electronic RATA results involve a relatively 
small amount of information that can be copied into subsequent reports 
and does not have to be recreated, it should not be a significant 
burden to reporting facilities.
    The proposed revisions would also remove the requirement to report 
the reasons for missing data and make it optional. However, even if the 
information is not reported, the reasons for missing data would have to 
be maintained on site in a manner suitable for inspection. Based on the 
high data availability achieved during initial implementation of the 
program, the Agency believes that this type of information is not 
needed in the review of most quarterly reports. For those situations in 
which the Agency may wish to review this information, the records would 
still be on-site for audit purposes or for submittal to the Agency.
    The EPA is also proposing to incorporate additions which would 
allow the reporting of electronic signatures and certification 
statements so that no hardcopy reporting of any kind (e.g., cover 
letters) would be necessary to meet the quarterly report requirements.
    Finally, the removal of recordkeeping Secs. 75.50, 75.51, and 75.52 
(and the corresponding explanatory text included in Appendix J to the 
existing rule) is necessary because those sections were scheduled for 
replacement during the May 17, 1995 rule revisions. At that time, 
Secs. 75.54, 75.55, and 75.56 were added as replacements for 
Secs. 75.50, 75.51, and 75.52, effective January 1, 1996. Because the 
effective date is now past, the old sections and Appendix J will be 
removed and reserved in order to prevent any confusion.
9. Electronic Transfer of Quarterly Reports
Background
    Sections 75.64(a) and (d) of the original January 11, 1993 Acid 
Rain rule requires emissions, monitoring, and quality assurance data to 
be electronically reported to the Administrator on a quarterly basis in 
a format to be specified by the Administrator. Version 1.3 of the 
Electronic Data Reporting (EDR) format (see Docket A-97-35, Item II-I-
5) further specifies the record structures to be used to report the 
required data elements. Page 3-3 of the May 1995 Acid Rain Program CEMS 
Submission Instructions (see Docket A-97-35, Item II-I-4) further 
specifies the mode of transmission of the electronic data file to the 
Agency. Three modes of transfer are listed as options: (a) by mail on 
diskette, (b) by mail on magnetic tape, or (c) through direct 
electronic transfer.
    Since the beginning of the program, the Agency has received 
quarterly reports by mail on diskette and through direct electronic 
transfer. To date, the magnetic tape option has never been utilized. 
Based on the first four years of implementation of part 75, the Agency 
believes that the use of the direct electronic transfer mode of 
transmission has many advantages to the Agency and to the affected 
sources. In fact, more than seventy percent of the reports for sources 
currently affected by part 75 were submitted directly to the EPA 
mainframe with EPA-provided software in second quarter 1997, and the 
number of sources using this option has steadily increased over time 
(see Docket A-97-35, Item II-I-8).
Discussion of Proposed Changes
    Today's proposal would require quarterly reports to be submitted 
via direct electronic transfer unless otherwise approved by the 
Administrator. This would remove the option of sending files through 
the mail on interceding media except for hardship cases where a modem 
is not available or where technical difficulties prevent the successful 
transmission of files via modem.
    An additional revision to section 4 of Appendix A to part 75 would 
require data acquisition and handling systems (DAHS) to be capable of 
transmitting a record of measurements and other required information by 
direct computer-to-computer electronic transfer via modem and EPA-
provided software.
Rationale
    For each quarterly report submitted, the Agency performs an 
assessment which results in a feedback report for the submitting 
designated representative. This feedback report provides information to 
the facility that may be used in making trading decisions, that may 
indicate that a change is needed to the facility software, and/or that 
may indicate that the file needs to be corrected and resubmitted. A 
major advantage of submission through direct electronic transfer with a 
modem and EPA-provided software is that the designated representative 
submitting the file receives the EPA assessment of the submitted data 
much more quickly than for a file that is transmitted through the mail 
on diskette. Currently, for a file that is submitted to the Agency by 
electronic transfer via modem and EPA-provided software, the EPA 
assessment is received by the designated representative, via modem and 
EPA-provided software, immediately (typically within ten minutes) after 
the transmission of the quarterly report file. However, for files 
submitted on diskette that must travel through the mail system and be 
processed by Agency personnel, a letter containing the EPA assessment 
is currently sent to the designated representative through the mail and 
arrives 45 days or later from when the submission was originally 
received by the Agency. Therefore, with direct electronic transfer, 
potential errors get corrected and resolved more quickly and trading 
decisions can be made with assurance that submitted data meets the 
minimum quality standards acceptable to the Agency. Additionally, the 
source may electronically submit the quarterly report, via modem and 
EPA software, prior to the deadline, immediately receive the EPA 
assessment, fix any errors, and resubmit the file by the deadline. Many 
utilities have indicated that this is an important advantage over 
submission of the quarterly report by diskette.
    Another benefit of direct electronic transfer is the reduced risk 
of error in transmission to the Agency or handling at the Agency. 
Throughout the implementation of the program, many files submitted on 
diskette through the mail have been lost, returned to the sender, 
damaged in transit, or contained viruses (see Docket A-97-35, Item II-
I-8). When a file is submitted using direct electronic transfer of a 
quarterly report, the designated representative submitting the file(s) 
receives an immediate

[[Page 28112]]

confirmation that the file was received by the Agency.
    Further, immediate feedback from the agency on quarterly report 
submissions may also contribute to cost savings for facilities if a 
file submitted via direct electronic transfer is rejected and required 
to be amended and resubmitted. Utilities have indicated that submitting 
the report to EPA, receiving feedback, and making the necessary 
corrections to the file in a single work session significantly reduces 
the cost of reworks, particularly for facilities that retain their 
master file at the individual plant locations.
    An additional advantage to direct electronic transfer is the 
reduced cost to the Agency resulting from the minimized EPA labor hours 
required to process a diskette. For instance, a diskette transmitted 
through the mail must be catalogued, scanned for readability and 
viruses, uploaded to the EPA mainframe Emissions Tracking System, and 
renamed. On the other hand, transmission of a file by direct computer-
to-computer electronic transfer using EPA software eliminates all of 
those manual steps because they are performed automatically by the EPA 
software used for transmission of the report.
    A possible concern about a requirement to submit the quarterly 
report via modem is the possibility that source may not be equipped 
with a modem and electronic transfer capability. Although the Agency 
believes that most sources currently have a modem or will have a modem 
by the year 2000, the Agency understands that a very small percentage 
might not. Therefore, the Agency would accept petitions from sources 
unable to transmit files via modem in order to allow transmission via 
diskette for hardship cases.
    Additionally, a utility group representative raised a concern about 
the possibility of a computer at either the facility source or at the 
EPA being inoperative at the time of the deadline for transmission, 
preventing a source from successfully transferring the quarterly report 
to the Agency. In order to minimize the risk of this type of problem, 
there is a wide window, currently thirty days, during which EPA will 
accept quarterly report transmissions each quarter. Additionally, EPA 
has instituted preventative measures to minimize the possibility that 
the EPA computer would be inoperative for an extended length of time, 
preventing quarterly report transmission. Nevertheless, the Agency 
accepts that it is conceivable that a technical difficulty could 
prevent the successful electronic submission of a quarterly report and, 
therefore, would also approve diskette submission on an as-needed basis 
for sources unable to transfer a file via modem and EPA-provided 
software due to technical difficulties. Furthermore, EPA solicits 
comment on whether it should allow a grace period for late submissions 
due to a technical difficulty with the EPA computer.
    Finally, section 4 of Appendix A to part 75 would be amended to 
require the DAHS to be capable of transmitting the required information 
by direct electronic transfer via modem and EPA-provided software, for 
consistency with the proposed Sec. 75.64(f). In addition, section 4 of 
Appendix A to part 75 would retain the requirement for the DAHS to be 
capable of transmitting a record of measurements and other required 
information via an IBM-compatible personal computer diskette so that an 
on-site inspector could collect electronic data on a diskette for 
review.

S. Revised Traceability Protocol for Calibration Gases

Background
    Currently, Appendix H to part 75 requires affected units to follow 
a 1987 version of EPA Protocol procedures for developing calibration 
gases. This protocol document has been superseded by a later version, 
the ``EPA Traceability Protocol for Assay and Certification of Gaseous 
Calibration Standards,'' September 1997, EPA 600/R-97/121. The 1997 
document is actually five protocols. Two of these protocols (formerly 
known as Protocols 1 and 2) have been combined to allow both CEMS and 
ambient air analyzers to be calibrated from gases produced either 
without dilution (Procedure G1) or with dilution (Procedure G2). The 
remaining three protocols (Procedures P1, P2, and P3) describe 
procedures that are mandatory for ambient air quality analyzers (not 
continuous emission monitoring systems).
    The 1997 Protocol document, described above, is required by other 
parts of the CFR, such as the NSPS provisions in part 60. Because the 
old and new protocols specify different certification periods (i.e., 
useful shelf lives) for most calibration gases, some affected units 
that must comply with both part 60 and part 75 have been forced to 
replace calibration gas cylinders more frequently because of the 
shorter certification period in the 1987 Protocol procedures required 
by part 75.
    Under the 1987 Protocol document, affected units with low 
SO2 emission rates occasionally had difficulty finding 
calibration gases that were within the concentration ranges required by 
Appendix A to part 75. The 1997 Protocol document allows calibration 
gases to be developed over a wider range of concentrations than was 
previously allowed.
    Under the current part 75 rule, ``Protocol 1 gases must be vendor-
certified to be within 2.0 percent of the concentration specified on 
the cylinder label (tag value).'' However, no method is specified to 
determine the uncertainty value. The overall uncertainty in the 
concentration estimated for a calibration gas comes from many different 
sources, including uncertainty in the reference standards, uncertainty 
in the analyzer multi-point calibration, uncertainty in the zero/span 
correction factors, and measurement imprecision.
Discussion of Proposed Changes and Rationale
    Today's rule proposes to remove Appendix H and revise parts 72 and 
75 to be consistent with the 1997 Protocol document. The following 
sections of part 75 would be revised: Secs. 72.2 and 72.3; sections 
5.1.1 through 5.1.6, 6.2, and 6.3.1 of Appendix A; and all of Appendix 
H.
    The final rule would incorporate by reference the 1997 Protocol 
document. This is the preferred option for the following reasons: (a) 
calibration gas certification periods would be identical under parts 60 
and 75, thereby allowing affected units to reduce expenditures on 
calibration gas without sacrificing accuracy or performance; (b) lower 
emitting affected units would more easily be able to comply with the 
required range of calibration gas concentrations; (c) improved assaying 
procedures and accuracy determinations would be allowed; and (d) a 
wider selection of calibration gases would be allowed.
    While today's proposal would retain the requirement for EPA 
protocol gases to be within 2.0 percent of the tag value, section 5.1.3 
in Appendix A would be revised to specify the use of the uncertainty 
calculation procedure in section 2.1.8 of the 1997 Protocol document 
for estimating the analytical uncertainty associated with the assay of 
the calibration gas. This uncertainty estimate includes the uncertainty 
of the reference standard and any gas manufacturer's intermediate 
standard (GMIS) and interference correction equation that may be used 
in developing the calibration gas.
    EPA proposes to change the term ``Protocol 1 gas'' to ``EPA 
protocol gas'' because the 1997 Protocol document combines the Protocol 
1 and Protocol 2

[[Page 28113]]

procedures; therefore, the term ``Protocol 1 gas'' would no longer be 
used.
    Today's proposal would also continue to allow a ``research gas 
mixture'' to be used as a calibration gas. However, an RGM would need 
to meet the same 2.0 percent uncertainty requirement that a protocol 
gas would meet.
    The proposed rule would explicitly allow GMISs to be used as 
calibration gas for two reasons. First, an EPA protocol gas may be made 
from a GMIS. Therefore, GMISs are at least as accurate as EPA protocol 
gases. Second, GMISs are more readily available and less expensive than 
standard reference material or National Institute of Standards and 
Technology (NIST) traceable reference material, both of which are 
allowable as calibration gas under part 75.
    Today's proposal clarifies that NIST/EPA-approved certified 
reference materials (CRMs) would be acceptable as calibration gas by 
adding those CRMs to the definition of ``calibration gas'' in 
Sec. 72.2.
    The 1997 Protocol document accepts primary reference standards from 
the Netherlands Measurement Institute as being equivalent to standard 
reference materials from the NIST. As a result, today's proposal adds 
``standard reference material-equivalent compressed gas primary 
reference material'' to the ``calibration gas'' definition in Sec. 72.2 
and to section 5.1.2 of Appendix A.
    Finally, the definition of ``zero air material'' would be revised 
to accommodate other acceptable procedures.
    Major differences between the 1987 Protocol procedures and the 1997 
Protocol procedures are explained on pages 1-1 through 1-3 of the 1993 
Protocol document and on pages 1-1 through 1-2 of the 1997 Protocol 
document (see Docket A-97-35, Items II-I-23 and 24).

T. Appendix I--New Optional Stack Flow Monitoring Methodology

Background
    Section 412 of the Act requires that units subject to title IV 
install SO2 concentration monitors and volumetric flow 
monitors for the purpose of determining SO2 emissions. The 
purpose of the volumetric flow requirement is to enable a unit to 
convert SO2 concentrations into mass emission rates of 
pounds per hour (lbs/hr). Volumetric flow is also used to determine 
heat input rate in mmBtu/hr and CO2 mass emission rate in 
ton/hr.
    In December 1991, 56 FR 63002 (December 3, 1991), EPA proposed an 
exception to the requirement to install SO2 concentration 
monitors and volumetric flow monitors at oil- and gas-fired units in 
Appendix D to part 75. The exception relies on fuel flowmeters and fuel 
sampling and analysis to determine SO2 emissions from oil- 
and gas-fired units. In comments on the December 1991 proposed rule, 
some industry commenters also advocated allowing oil- and gas-fired 
units to use a diluent monitor, an F-factor, and a fuel flowmeter as an 
alternative to a volumetric flow monitor. An F-factor is a fuel-
specific constant that relates the heat content of a fuel and the 
volume of gases given off upon combustion. It is used to convert 
pollutant concentrations into units of pounds of pollutant per million 
British thermal units of heat input (lb/mmBtu). EPA already allows the 
use of F-factors in emissions monitoring under part 75 and under 40 CFR 
part 60, subparts Da and Db. Method 19 of Appendix A to part 60 uses F-
factors as the reference methods for calculating SO2 and 
NOX emissions in terms of lb/mmBtu for subpart Da and Db 
units. F-factors also are used in the performance tests for certain 
pollutants required under Sec. 60.8 to determine if a source is in 
compliance with a particular emission standard in lb/mmBtu. Part 75 
also uses F-factors in conjunction with diluent gas and volumetric flow 
data to determine heat input under section 5 of Appendix F to part 75. 
Table 19-1 of Method 19 in Appendix A to part 60 and Table 1 in section 
3.3.5 of Appendix F to part 75 list the appropriate F-factors for 
different types of fuel, including oil and natural gas.
    Although the commenters supported the two exceptions included in 
Appendix D, some commenters did not believe the exceptions would be 
economical at all oil- and gas-fired units. According to one commenter, 
fuel sampling protocols have an inherently high bias because they 
assume a 100 percent conversion of fuel sulfur into SO2, 
which results in higher emissions reporting from fuel sampling 
protocols than from CEMS. The commenter claimed that the high bias 
appears to be in the range of 5 to 10 percent. According to the 
commenter, the higher emissions reporting ``penalty'' that is inherent 
in fuel sampling protocols would justify installing SO2 CEMS 
at some oil- and gas-fired units, particularly large, base-loaded oil-
fired units. In addition, the commenter claimed that, for oil- and gas-
fired units which install SO2 CEMS, use of the ``F-factor/
fuel flow method''--which includes use of an F-factor, a fuel 
flowmeter, fuel sampling data, and a diluent (CO2 or O2) 
concentration monitor--would provide much more accurate and precise 
information than volumetric flow monitors (see Docket A-90-51, Item IV-
D-184).
    In a four-day experiment performed in 1991 by one commenter, 
measurements from the F-factor/fuel flow method were compared to those 
generated by a combined SO2 CEMS and a volumetric flow 
monitor. However, EPA did not believe that four consecutive days of 
data were sufficient to support a conclusive equivalency determination. 
Instead, in the January 11, 1993 final rule (58 FR 3590, 3643), EPA 
reserved Appendix I to part 75 for the F-factor/fuel flow method and 
stated that, to be approved, the method would have to meet the criteria 
for alternative methods as required by section 412 of the Act and the 
provisions of Sec. 75.40 in a 30-day (720 hour) trial.
    Section 412 of the Act requires that an alternative monitoring 
system provide information with ``the same precision, reliability, 
accessibility, and timeliness as that provided by CEMS . . .'' 42 
U.S.C. 7651k. To be approved, the alternative monitoring system must 
meet the criteria for alternative methods in a 720 hour trial as 
required by the provisions of subpart E of part 75. The rule designates 
a certified CEMS or a reference method according to Appendix A to part 
60 as the reference for evaluating the alternative monitoring system's 
performance.
    In order to meet the precision and reliability criteria, an 
alternative monitoring system must achieve performance specifications 
and quality assurance requirements equivalent to those for CEMS. In 
addition, to demonstrate precision, an alternative monitoring system 
must pass three statistical tests evaluating the flow CEMS and 
alternative method in terms of their respective systematic error, 
random error, and correlation. Additionally, to meet the reliability 
criterion, the alternative monitoring system is required to match a 
certified CEMS in terms of annual availability. Finally, to meet the 
accessibility and timeliness criteria, an alternative monitoring system 
must match the CEMS' ability to record requisite emissions data on an 
hourly basis and report results within 24 hours.
    In 1995, Long Island Lighting Company (LILCO) sponsored an 
``alternative flow monitor demonstration project'' to demonstrate the 
equivalency of fuel flow measurements and F-factor calculations to 
stack instrument flue gas measurements for the determination of 
volumetric flow. The project was

[[Page 28114]]

performed by Entropy at LILCO's Port Jefferson Unit 4, a 180 MW oil-
fired unit that burns residual oil with a maximum sulfur content of one 
percent. The components of the alternative method consisted of a fuel 
flowmeter and a CO2 CEMS. The alternative F-factor/fuel flow 
method was compared to a flue gas volumetric flow CEMS.
    Testing of the F-factor/fuel flow method took place in April-May 
1995, and 739 hours of data were collected over a wide range of 
operating loads (40 MW--190 MW). Fuel oil samples were taken daily and 
analyzed for density and carbon content. The alternative method 
successfully passed statistical tests but showed statistically 
significant bias (see Docket A-97-35, Item II-D-14). Due to the bias 
uncovered during the test, EPA concluded that the alternative flow 
monitor demonstration project did not meet the requirements of subpart 
E of part 75 for an alternative monitoring system. However, EPA is 
proposing that a default multiplier, derived from the demonstration 
data, be incorporated into the equations used under Appendix I to 
compensate for the detected systematic bias and thereby help to ensure 
that emissions are not underestimated when using the F-factor/fuel flow 
method. With these provisions, EPA proposes to include the F-factor/
fuel flow method as an excepted method for determining flow in Appendix 
I to part 75. The proposed default multiplier, 1.12, is based on the 
data and results of the LILCO demonstration and is supported by EPA and 
the Class of `85 Regulatory Response Group. The default multiplier 
would be incorporated into the equations used under Appendix I whenever 
a relative accuracy test audit is performed on a component-by-component 
basis as was proposed in the LILCO demonstration.
Discussion of Proposed Changes
    EPA proposes to include the F-factor/fuel flow method in Appendix I 
as an excepted method for use in place of a volumetric flow monitor for 
oil- and gas-fired units that burn only natural gas and/or fuel oil. 
The F-factor/fuel flow method uses fuel flow measurement, fuel sampling 
data, CO2 (or O2) CEMS data and F-factors to 
determine the flow rate of the stack gas. EPA proposes limiting use of 
the F-factor/fuel flow method to oil- and gas-fired units that burn 
only natural gas and/or fuel oil because of the greater fuel 
consistency of oil and natural gas and because the fuel flow rates of 
oil and natural gas can be monitored accurately with a fuel flowmeter, 
unlike the feed rate of coal.
    Appendix I flow monitoring would be done using any of the following 
combinations of components: a CO2 monitor and a volumetric 
oil flowmeter, a CO2 monitor and a mass oil flowmeter, a 
CO2 monitor and a volumetric gas flowmeter, an O2 
monitor and a volumetric oil flowmeter, an O2 monitor and a 
mass oil flowmeter, or an O2 monitor and a volumetric gas 
flowmeter.
    Today's proposal would amend Sec. 75.20, ``Certification and 
Recertification Procedures,'' to add certification and recertification 
procedures for units using Appendix I flow monitoring systems. Initial 
certification of the components of the F-factor/fuel flow method would 
be performed either component by component or on a system basis. If 
each component is tested separately, then the fuel flowmeter would be 
tested in accordance with section 2.1.5 of Appendix D, and the 
CO2 or O2 monitor would have to pass a 7-day 
calibration test, a linearity check, a cycle time test and a relative 
accuracy test audit (RATA) using Method 3A from Appendix A to part 60. 
A bias test would also have to be conducted. If the excepted Appendix I 
flow monitoring system is tested as an entire system, then the 
following tests would be performed: a 7-day calibration error test, a 
linearity check, and a cycle time test on the CO2 or 
O2 monitor, and a relative accuracy test audit on the entire 
excepted flow monitoring system using Method 2 from Appendix A to part 
60, and a bias test. The owner or operator would also test the data 
acquisition and handling system. Upon successful completion of all 
certification tests, the Appendix I system would be considered 
provisionally certified.
    Today's proposal would amend Sec. 75.21, ``Quality Assurance and 
Quality Control Requirements,'' to include Appendix I flow monitoring 
systems. A unit utilizing the optional F-factor/fuel flow method would 
have to meet ongoing quality assurance testing requirements. First, the 
daily and quarterly assessment requirements for a CO2 or 
O2 monitor in sections 2.1 and 2.2 of Appendix B would have 
to be followed. Second, one of the following would have to be met, 
depending on whether the owner or operator chooses to test the method 
on a component-by-component basis or on a system level: (1) the fuel 
flow meter quality assurance requirements and a separate RATA on the 
CO2 (or O2) monitor; or (2) a system level flow 
RATA. If the components are tested separately, the applicable 
procedures in section 2.1.6 of Appendix D would have to be followed for 
the fuel flowmeter quality assurance (i.e., a flow meter accuracy test, 
a transmitter accuracy test and primary element inspection, and/or the 
supplemental quarterly fuel flow-to-load quality assurance testing) and 
the applicable RATA procedures in sections 6.5 through 6.5.2.2 of 
Appendix A for the CO2 (or O2) monitor would be 
followed. In addition, the bias test would have to be performed on the 
CO2 (or O2) monitor and, if the bias test is 
failed, a bias adjustment factor (BAF) would have to be calculated and 
applied to hourly data.
    If the entire system is tested, the applicable procedures in 
sections 6.5 through 6.5.2.2 of Appendix A would have to be used to 
meet the performance specifications for flow relative accuracy in 
section 3.3.4 of Appendix A. The bias test would have to be performed 
on the volumetric flow data and, if the bias test is failed, a BAF 
would have to be calculated using the procedures in section 7.6 of 
Appendix A.
    Several other sections of the rule would be modified or added in 
order to incorporate the new excepted method described in Appendix I, 
including Secs. 75.30, 75.57, 75.58, and 75.59. Section 75.30, 
``General Provisions'' (for missing data substitution procedures), 
would be modified by adding quality assured data from a certified 
excepted flow monitoring system under Appendix I to the list of 
monitoring systems that measure flow rate data, for which the missing 
data substitution procedures of subpart D are required. If fuel 
sampling data, fuel flow rate data, and diluent gas data are missing, 
then the data acquisition and handling system would have to substitute 
for missing volumetric flow data. In addition, Sec. 75.57, would 
include additional information that Appendix I flow monitoring systems 
must record. This includes fuel flow rate data and data from component 
monitors. Section 75.58(g) would be added to address specific 
volumetric flow rate record provisions for units using the optional 
protocol in Appendix I. Section 75.59, ``Certification, Quality 
Assurance and Quality Control Record Provisions,'' would also include 
certification and quality assurance information that facilities must 
record for Appendix I flow monitoring system tests.
    Finally, the new proposed Appendix I would describe the 
applicability, procedures, calculations, missing data, and 
recordkeeping and reporting requirements for units using Appendix I to 
determine flow.
    The Appendix I formulas are more complex if an O2 
monitor is used. EPA proposes to allow the use of an O2 
monitor for Appendix I; however, the

[[Page 28115]]

initial programming of the formulas and monitoring plan development may 
take longer for Appendix I flow monitoring systems that use an 
O2 monitor.
    Volumetric stack flow rate during oil combustion would be 
calculated from (1) a bias adjustment factor from the applicable bias 
test results; (2) the fuel flow rate (in gal/hr); (3) the fuel density 
(in lb/gal); (4) the percent carbon by weight; (5) the CO2 
(or O2) concentration percent by volume; and (6) the 
appropriate conversion factor. The carbon content of the fuel would 
have to be determined according to the procedures in section 2.1 of 
Appendix G and the density of the oil would have to be determined 
according to the procedures in section 2.2 of Appendix D.
    Rationale: EPA is proposing an F-factor/fuel flow method in 
Appendix I to part 75 as an excepted method to measure volumetric flow 
directly with a flow monitor because this method would allow fuel flow 
measurement with a gas or oil flowmeter, fuel sampling data, 
CO2 (or O2) CEMS data, and F-factors to determine 
the flow rate of the stack gas rather than a volumetric flow monitor. 
The F-factor/fuel flow method would be available for use by oil-fired 
and gas-fired units, as defined under Sec. 72.2, provided that they 
only burn natural gas and/or fuel oil. For these units, EPA believes 
that the proposed method would provide acceptably accurate measurements 
of volumetric flow, while affording cost savings that some industry 
representatives estimate could be substantial. The Agency solicits 
comment on the proposed Appendix I and associated changes to part 75.
    Appendix I may offer cost savings to some oil and gas fired units. 
Representatives from oil- and gas-fired units have estimated that the 
costs of operating, maintaining and testing volumetric flow monitors 
range from approximately $15,000 to $25,000 per year. In contrast, 
using the F-factor/fuel flow method is estimated to result in costs of 
only approximately $5,000 to $7,000 per year due to elimination of the 
operating, maintenance, testing and fuel costs associated with the 
volumetric flow monitor.

U. The Use of Predictive Emissions Modeling Systems (PEMS)

    A number of parties have submitted preliminary field test data 
designed to demonstrate that EPA should set forth specific requirements 
for alternative monitoring methodologies that predict NOX 
emission rates at gas-fired units. These ``predictive emissions 
modeling systems'' (PEMS) use mathematical models to predict 
NOX emission rates based on sensor readings of key operating 
parameters. The agency is evaluating the submitted data and will 
consider taking further action under a future rulemaking if additional 
study demonstrates the equivalency of PEMS to CEMS for well defined 
classes of units.

IV. Administrative Requirements

A. Public Hearing

    If requested as specified in the DATES section of this preamble, a 
public hearing will be held to discuss the proposed regulations. 
Persons wishing to make oral presentations at the public hearing should 
contact EPA at the address given in the ADDRESSES section of this 
preamble. If necessary, oral presentations will be limited to 15 
minutes each. Any member of the public may file a written statement 
with EPA before, during, or within 30 days of the hearing. Written 
statements should be addressed to the Air Docket address given in the 
ADDRESSES section of this preamble.
    A verbatim transcript of the public hearing, if held, and all 
written statements will be available for public inspection and copying 
during normal working hours at EPA's Air Docket in Washington, DC (see 
the ADDRESSES section of this preamble).

B. Public Docket

    The Docket for this regulatory action is A-97-35. The docket is an 
organized and complete file of all the information submitted to or 
otherwise considered by EPA in the development of this proposed 
rulemaking. The principal purposes of the docket are: (1) to allow 
interested parties a means to identify and locate documents so that 
they can effectively participate in the rulemaking process, and (2) to 
serve as the record in case of judicial review. The docket is available 
for public inspection at EPA's Air Docket, which is listed under the 
ADDRESSES section of this preamble.

C. Executive Order 12866

    Under Executive Order 12866 (58 FR 51735, October 4, 1993), the 
Administrator must determine whether the regulatory action is 
``significant'' and therefore subject to Office of Management and 
Budget (OMB) review and the requirements of the Executive Order. The 
Order defines ``significant regulatory action'' as one that is likely 
to result in a rule that may:

    (1) Have an annual effect on the economy of $100 million or more 
or adversely affect in a material way the economy, a sector of the 
economy, productivity, competition, jobs, the environment, public 
health or safety, or State, local or tribal governments or 
communities;
    (2) Create a serious inconsistency or otherwise interfere with 
an action taken or planned by another agency;
    (3) Materially alter the budgetary impact of entitlements, 
grants, user fees, or loan programs or the rights and obligations of 
recipients thereof; or
    (4) Raise novel legal or policy issues arising out of legal 
mandates, the President's priorities, or the principles set forth in 
the Executive Order.

    This proposed rule is not expected to have an annual effect on the 
economy of $100 million or more. However, pursuant to the terms of 
Executive Order 12866, it has been determined that this proposed rule 
is a significant action because it raises novel policy issues. As such, 
the proposed rule has been submitted for OMB review. Any written 
comments from OMB and any EPA response to OMB comments are in the 
public docket for this proposal.

D. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), P.L. 
104-4, establishes requirements for Federal agencies to assess the 
effects of their regulatory actions on State, local, and tribal 
governments and the private sector. Under section 202 of the UMRA, EPA 
generally must prepare a written statement, including a cost-benefit 
analysis, for proposed and final rules with ``Federal mandates'' that 
may result in expenditures to State, local, and tribal governments, in 
the aggregate, or to the private sector, of $100 million or more in any 
one year. Before promulgating an EPA rule for which a written statement 
is needed, section 205 of the UMRA generally requires EPA to identify 
and consider a reasonable number of regulatory alternatives and adopt 
the least costly, most cost-effective, or least burdensome alternative 
that achieves the objectives of the rule. The provisions of section 205 
do not apply when they are inconsistent with applicable law. Moreover, 
section 205 allows EPA to adopt an alternative other than the least 
costly, most cost-effective, or least burdensome alternative if the 
Administrator publishes with the final rule an explanation why that 
alternative was not adopted. Before EPA establishes any regulatory 
requirements that may significantly or uniquely affect small 
governments, including tribal governments, it must have developed under 
section 203 of the UMRA a small government agency plan. The plan must 
provide for notifying potentially affected small governments, enabling 
officials of affected small governments

[[Page 28116]]

to have meaningful and timely input in the development of EPA 
regulatory proposals with significant Federal intergovernmental 
mandates, and informing, educating, and advising small governments on 
compliance with the regulatory requirements.
    This proposed rule is not expected to result in expenditures of 
more than $100 million in any one year and, as such, is not subject to 
section 202 of the UMRA. Although the proposed rule is not expected to 
significantly or uniquely affect small governments, the Agency has 
notified all potentially affected small governments that own or operate 
units potentially affected by the proposal in order to assure that they 
have the opportunity to have meaningful and timely input on the 
proposed rule. EPA will continue to use its outreach efforts related to 
part 75 implementation, including a policy manual that is generally 
updated on a quarterly basis, to inform, educate, and advise all 
potentially impacted small governments about compliance with part 75.

E. Paperwork Reduction Act

    The information collection requirements in this proposal have been 
submitted for approval to the OMB under the Paperwork Reduction Act, 44 
U.S.C. 3501, et seq. An Information Collection Request (ICR) document 
has been prepared by EPA (ICR No. 1835.01), and a copy may be obtained 
from Sandy Farmer, OPPE Regulatory Information Division; U.S. 
Environmental Protection Agency (2137); 401 M Street, SW, Washington, 
DC 20460, by calling (202) 260-2740, or via the Internet at www.gov/
icr.
    Currently, all affected utilities are required to keep records and 
submit electronic quarterly reports under the provisions of part 75. 
The proposed rule includes several new options for compliance with part 
75 which have been requested by affected utilities. To implement these 
options, EPA would have to modify the existing recordkeeping and 
reporting requirements. In some circumstances, these changes would 
result in significant reductions in the reporting and recordkeeping 
burdens or costs for some units (such as low mass emissions units). 
However, these changes would require modifications to the software used 
to generate electronic reports. In addition, there would be some 
increased burden or costs for certain units to fulfill the new quality 
assurance procedures proposed in these proposed revisions. Finally, 
several other technical revisions to the existing reporting and 
recordkeeping requirements have been proposed to clarify existing 
provisions or to facilitate reporting for other regulatory programs in 
the context of Acid Rain Program reporting. Although these one-time 
software changes would tend to increase the short-term burdens 
allocated to the Acid Rain Program, such changes should reduce a 
source's overall long-term burden by streamlining the source's 
reporting obligations under both the Acid Rain Program and the Act.
    The average annual projected hour burden is 2,608,836, which is 
based on an estimated 835 likely respondents (on a per utility basis). 
The projected cost burden resulting from the collection of information 
is $47,555,000, which includes a total projected capital and start-up 
cost of $1,436,000 (for monitoring equipment/software), and a total 
projected operation and maintenance cost (which includes purchase of 
testing contractor services and total projected fuel sampling and 
analysis cost of $716,000) of $46,119,000. Burden means the total time, 
effort, or financial resources expended by persons to generate, 
maintain, retain, disclose, or provide information to or for a Federal 
agency. This includes the time needed to review instructions; develop, 
acquire, install, and utilize technology and systems for purposes of 
collecting, validating, and verifying information, processing and 
maintaining information, and disclosing and providing information; 
adjust the existing ways to comply with any previously applicable 
instructions and requirements; train personnel to be able to respond to 
a collection of information; search data sources; complete and review 
the collection of information; and transmit or otherwise disclose the 
information.
    An agency may not conduct or sponsor and a person is not required 
to respond to a collection of information, unless it displays a 
currently valid OMB control number. The OMB control numbers for EPA's 
regulations are listed in 40 CFR part 9 and 48 CFR chapter 15.
    Comments are requested on the Agency's need for this information, 
the accuracy of the provided burden estimates, and any suggested 
methods for minimizing respondent burden, including through the use of 
automated collection techniques. Send comments on the ICR to the 
Director, OPPE Regulatory Information Division; U.S. Environmental 
Protection Agency (2137); 401 M Street, SW, Washington, DC 20460; and 
to the Office of Information and Regulatory Affairs, Office of 
Management and Budget, 725 17th Street, NW, Washington, DC 20503, 
marked ``Attention: Desk Officer for EPA.'' Include the ICR number in 
any correspondence. Since OMB is required to make a decision concerning 
the ICR between 30 and 60 days after May 21, 1998, a comment to OMB is 
best assured of having its full effect if OMB receives it by June 22, 
1998. The final rule will respond to any OMB or public comments on the 
information collection requirements contained in this proposal.

F. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA), 5 U.S.C. 601, et seq., 
generally requires an agency to conduct a regulatory flexibility 
analysis of any rule subject to notice and comment rulemaking 
requirements unless the agency certifies that the rule will not have a 
significant economic impact on a substantial number of small entities. 
Small entities include small businesses, small not-for-profit 
enterprises, and governmental jurisdictions. This proposed rule would 
not have a significant impact on a substantial number of small 
entities.
    Today's proposed revisions to part 75 result in a net cost 
reduction to utilities affected by the Acid Rain Program, including 
small entities. Most importantly, the proposed changes to Appendix D 
and the addition of an optional calculation procedure instead of actual 
monitoring for oil- and gas-fired units with low mass emissions would 
significantly reduce the cost of complying with part 75 for oil-and 
gas-fired units, many of which are owned or operated by small entities. 
Therefore, I certify this action will not have a significant economic 
impact on a substantial number of small entities.

G. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act of 1995 (``ANTTAA''), Pub L. No. 104-113 15 USC 272 note, directs 
EPA to use voluntary consensus standards in its regulatory activities 
unless to do so would be inconsistent with applicable law or otherwise 
impractical. Voluntary consensus standards are technical standards 
(e.g., materials specifications, test methods, sampling procedures, 
business practices, etc.) that are developed or adopted by voluntary 
consensus standards bodies. The NTTAA requires EPA to provide Congress, 
through OMB, explanations when the Agency decides not to use available 
and applicable voluntary consensus standards.
    This regulatory action proposes to incorporate by reference 
voluntary consensus standards pursuant to Sec. 12(d) of the NTTAA. The 
EPA has adopted the general policy of using voluntary

[[Page 28117]]

consensus standards from technically knowledgeable groups such as the 
Organization for International Standards (ISO), the American Society 
for Testing and Materials (ASTM), the American Society of Mechanical 
Engineers (ASME), the American Gas Association (AGA), the Gas 
Processors Association (GPA), and the American Petroleum Institute 
(API).
    EPA invites public comment on the voluntary consensus standards 
which are proposed to be incorporated by reference for use in part 75. 
EPA has not identified any additional voluntary consensus standards 
which might be applicable to this rulemaking. This does not indicate 
that other applicable standards do not exist or that any other 
standards should not be allowed. Therefore, EPA also invites public 
comment on any other voluntary consensus standards which may be 
appropriate for the proposed regulatory action. Further, if additional 
applicable voluntary consensus standards are identified in the future, 
the designated representative may petition under Sec. 75.66(c) to use 
an alternative to any standard incorporated by reference and prescribed 
in this part.
    EPA proposes to incorporate by reference the following voluntary 
consensus standards for use under part 75:
    a. ASTM D5373-93 ``Standard Methods for Instrumental Determination 
of Carbon, Hydrogen and Nitrogen in laboratory samples of Coal and 
Coke.'' This standard is proposed to be incorporated by reference for 
use under section 2.1 of Appendix G to part 75 and is discussed further 
in section III.Q.1 of this preamble.
    b. API Section 2 ``Conventional Pipe Provers'' from Chapter 4 of 
the Manual of Petroleum Measurement Standards, October 1988 edition. 
This standard is proposed to be incorporated by reference for use under 
paragraph (g)(1)(i) of Sec. 75.20 and under section 2.1.5.1 of Appendix 
D to part 75. The proposal to incorporate this standard by reference is 
discussed further in section III.P.6.(b) of this preamble.

List of Subjects in 40 CFR Parts 72 and 75

    Air pollution control, Carbon dioxide, Continuous emission 
monitors, Electric utilities, Environmental protection, Nitrogen 
oxides, Reporting and recordkeeping requirements, Sulfur dioxide.

    Dated: April 27, 1998.
Carol M. Browner,
Administrator, U.S. Environmental Protection Agency.

    For the reasons set out in the preamble, title 40 chapter 1 of the 
Code of Federal Regulations is proposed to be amended as follows:

PART 72--PERMITS REGULATION

    1. The authority for part 72 continues to read as follows:

    Authority: 42 U.S.C. 7601 and 7651, et seq.

    2. Section 72.2 is amended by revising the definitions of 
``calibration gas,'' ``excepted monitoring system,'' ``gas-fired,'' 
``pipeline natural gas,'' ``span,'' ``stationary gas turbine,'' and 
``zero air material''; by revising paragraph (2) of ``oil-fired'' and 
paragraph (2) of the ``peaking unit''; by adding paragraph (3) to the 
definition of ``peaking unit''; by adding new definitions for 
``conditionally valid data,'' ``EPA protocol gas,'' ``gas 
manufacturer's intermediate standard,'' ``low mass emissions unit,'' 
``maximum rated hourly heat input,'' ``ozone season,'' ``probationary 
calibration error test,'' ``research gas mixture (RGM)'', and 
``standard reference material-equivalent compressed gas primary 
reference material''; and by removing the definition of ``protocol 1 
gas,'' to read as follows:


Sec. 72.2  Definitions.

* * * * *
    Calibration gas means:
    (1) A standard reference material;
    (2) A standard reference material-equivalent compressed gas primary 
reference material;
    (3) A NIST traceable reference material;
    (4) NIST/EPA-approved certified reference materials;
    (5) A gas manufacturer's intermediate standard;
    (6) An EPA protocol gas;
    (7) Zero air material; or
    (8) A research gas mixture.
* * * * *
    Conditionally valid data means data from a continuous monitoring 
system that are not quality assured, but which may become quality 
assured if certain conditions are met. Examples of data that may 
qualify as conditionally valid are: data recorded by an uncertified 
monitoring system prior to its initial certification; or data recorded 
by a certified monitoring system following a significant change to the 
system that may affect its ability to accurately measure and record 
emissions. A monitoring system must pass a probationary calibration 
error test, in accordance with section 2.1.1 of appendix B of part 75 
of this chapter, to initiate the conditionally valid data status. In 
order for conditionally valid emission data to become quality assured, 
one or more quality assurance tests or diagnostic tests must be passed 
within a specified time period.
* * * * *
    EPA protocol gas means a calibration gas mixture prepared and 
analyzed according to section 2 of the ``EPA Traceability Protocol for 
Assay and Certification of Gaseous Calibration Standards,'' September 
1997, EPA-600/R-97/121 or such revised procedure as approved by the 
Administrator.
* * * * *
    Excepted monitoring system means a monitoring system that follows 
the procedures and requirements of Sec. 75.19 of this chapter or of 
appendix D or E to part 75 for approved exceptions to the use of 
continuous emission monitoring systems.
* * * * *
    Gas-fired means:
    (1) For all purposes under the Acid Rain Program, except for part 
75 of this chapter, the combustion of:
    (i) Natural gas or other gaseous fuel (including coal-derived 
gaseous fuel), for at least 90.0 percent of the unit's average annual 
heat input during the previous three calendar years and for at least 
85.0 percent of the annual heat input in each of those calendar years; 
and
    (ii) Any fuel, except coal or solid or liquid coal-derived fuel for 
the remaining heat input, if any.
    (2) For purposes of part 75 of this chapter, the combustion of:
    (i) Natural gas or other gaseous fuel with a total sulfur content 
no greater than the total sulfur content of natural gas (including 
coal-derived gaseous fuel) for at least 90.0 percent of the unit's 
average annual heat input during the previous calendar years and for at 
least 85.0 percent of the annual heat input in each of those calendar 
years; and
    (ii) Fuel oil, for the remaining heat input, if any.
    (3) For purposes of part 75 of this chapter, a unit may initially 
qualify as gas-fired if the designated representative demonstrates to 
the satisfaction of the Administrator that the requirements of 
paragraph (2) of this definition are met, or will in the future be met, 
through one of the following submissions:
    (i) For a unit for which a monitoring plan has not been submitted 
under Sec. 75.62 of this chapter,
    (A) The designated representative submits fuel usage data for the 
unit for

[[Page 28118]]

the three calendar years immediately preceding the date of initial 
submission of the monitoring plan for the unit under Sec. 75.62; or
    (B) For a unit that does not have fuel usage data for one or more 
of the three calendar years immediately preceding the date of initial 
submission of the monitoring plan for the unit under Sec. 75.62, if the 
designated representative submits: the unit's designated fuel usage; 
all available fuel usage data (including the percentage of the unit's 
heat input derived from the combustion of gaseous fuels), beginning 
with the date on which the unit commenced commercial operation; and the 
unit's projected fuel usage.
    (ii) For a unit for which a monitoring plan has already been 
submitted under Sec. 75.62, that has not qualified as gas-fired under 
paragraph (3)(i) of this definition, and whose fuel usage changes, the 
designated representative submits either:
    (A) Three calendar years of data following the change in the unit's 
fuel usage, showing that no less than 90.0 percent of the unit's 
average annual heat input during the previous three calendar years, and 
no less than 85.0 percent of the unit's annual heat input during any 
one of the previous three calendar years is from the combustion of 
gaseous fuels with a total sulfur content no greater than the total 
sulfur content of natural gas and the remaining heat input is from the 
combustion of fuel oil; or
    (B) A minimum of 720 hours of unit operating data following the 
change in the unit's fuel usage, showing that no less than 90.0 percent 
of the unit's heat input is from the combustion of gaseous fuels with a 
total sulfur content no greater than the total sulfur content of 
natural gas and the remaining heat input is from the combustion of fuel 
oil, and a statement that this changed pattern of fuel usage is 
considered permanent and is projected to continue for the foreseeable 
future.
    (iii) If a unit qualifies as gas-fired under paragraph (2)(i) or 
(ii) of this definition, the unit is classified as gas-fired as of the 
date of the submission under such paragraph.
    (4) For purposes of part 75 of this chapter, a unit that initially 
qualifies as gas-fired must meet the criteria in paragraph (2) of this 
definition each year in order to continue to qualify as gas-fired. If 
such a unit fails to meet such criteria for a given year, the unit no 
longer qualifies as gas-fired starting January 1 of the year after the 
first year for which the criteria are not met. If a unit failing to 
meet the criteria in paragraph (2) of this definition initially 
qualified as a gas-fired unit under paragraph (3)(ii) of this 
definition, the unit may qualify as a gas-fired unit for a subsequent 
year only under paragraph (3)(i) of this definition.
* * * * *
    Gas manufacturer's intermediate standard (GMIS) means a compressed 
gas calibration standard that has been assayed and certified by direct 
comparison to a standard reference material (SRM), an SRM-equivalent 
PRM, a NIST/EPA-approved certified reference material (CRM), or a NIST 
traceable reference material (NTRM), in accordance with section 2.1.2.1 
of the ``EPA Traceability Protocol for Assay and Certification of 
Gaseous Calibration Standards,'' September 1997, EPA-600/R-97/121.
* * * * *
    Low mass emissions unit means a gas-fired or oil-fired unit that 
burns only natural gas and/or fuel oil and that qualifies under 
Secs. 75.19(a) and (b) of this chapter.
* * * * *
    Maximum rated hourly heat input means a unit-specific maximum 
hourly heat input (mmBtu) which is the higher of the manufacturer's 
maximum rated hourly heat input or the highest observed hourly heat 
input.
    Oil-fired means:
* * * * *
    (2) For purposes of part 75 of this chapter, a unit may qualify as 
oil-fired if the unit burns only fuel oil and gaseous fuels with a 
total sulfur content no greater than the total sulfur content of 
natural gas and if the unit does not meet the definition of gas-fired.
* * * * *
    Ozone season means the period of time from May 1st to September 
30th, inclusive.
* * * * *
    Peaking unit means:
* * * * *
    (2) For purposes of part 75 of this chapter, a unit may initially 
qualify as a peaking unit if the designated representative demonstrates 
to the satisfaction of the Administrator that the requirements of 
paragraph (1) of this definition are met, or will in the future be met, 
through one of the following submissions:
    (i) For a unit for which a monitoring plan has not been submitted 
under Sec. 75.62,
    (A) The designated representative submits capacity factor data for 
the unit for the three calendar years immediately preceding the date of 
initial submission of the monitoring plan for the unit under 
Sec. 75.62; or
    (B) For a unit that does not have capacity factor data for one or 
more of the three calendar years immediately preceding the date of 
initial submission of the monitoring plan for the unit under 
Sec. 75.62, the designated representative submits: all available 
capacity factor data, beginning with the date on which the unit 
commenced commercial operation; and projected capacity factor.
    (ii) For a unit for which a monitoring plan has already been 
submitted under Sec. 75.62, that has not qualified as a peaking unit 
under paragraph (2)(i) of this definition, and where capacity factor 
changes, the designated representative submits either:
    (A) Three calendar years of data following the change in the unit's 
capacity factor showing an average capacity factor of no more than 10.0 
percent during the three previous calendar years and a capacity factor 
of no more than 20.0 percent in each of those calendar years; or
    (B) One calendar year of data following the change in the unit's 
capacity factor showing a capacity factor of no more than 10.0 percent 
and a statement that this changed pattern of operation resulting in a 
capacity factor less than 10.0 percent is considered permanent and is 
projected to continue for the foreseeable future.
    (3) For purposes of part 75 of this chapter, a unit that initially 
qualifies as a peaking unit must meet the criteria in paragraph (1) of 
this definition each year in order to continue to qualify as a peaking 
unit. If such a unit fails to meet such criteria for a given year, the 
unit no longer qualifies as a peaking unit starting January 1 of the 
year after the year for which the criteria are not met. If a unit 
failing to meet the criteria in paragraph (1) of this definition 
initially qualified as a gas-fired unit under paragraph (2)(ii) of this 
definition, the unit may qualify as a peaking unit for a subsequent 
year only under paragraph (2)(i) of this definition.
* * * * *
    Pipeline natural gas means natural gas that is provided by a 
supplier through a pipeline and that contains 0.3 grains or less of 
hydrogen sulfide per 100 standard cubic feet. The hydrogen sulfide 
content of the natural gas must be documented either through quality 
characteristics specified by a purchase contract or pipeline 
transportation contract, through certification of the gas vendor, based 
on routine vendor sampling and analysis, or through at least one year's 
worth of analytical data on the fuel hydrogen sulfide content from 
samples taken at least monthly, demonstrating that all samples contain

[[Page 28119]]

0.3 grains or less of hydrogen sulfide per 100 standard cubic feet.
* * * * *
    Probationary calibration error test means an on-line calibration 
error test performed in accordance with section 2.1.1 of appendix B of 
part 75 of this chapter that is used to initiate a conditionally valid 
data period.
* * * * *
    Research gas mixture (RGM) means a calibration gas mixture 
developed by agreement of a requestor and NIST that NIST analyzes and 
certifies as ``NIST traceable.'' RGMs may have concentrations different 
from those of standard reference materials.
* * * * *
    Span means the highest pollutant or diluent concentration or flow 
rate that a monitor component is required to be capable of measuring 
under part 75 of this chapter.
* * * * *
    Standard reference material-equivalent compressed gas primary 
reference material (SRM-equivalent PRM) means those gas mixtures listed 
in a declaration of equivalence in accordance with section 2.1.2 of the 
``EPA Traceability Protocol for Assay and Certification of Gaseous 
Calibration Standards,'' September 1997, EPA-600/R-97/121.
* * * * *
    Stationary gas turbine means a turbine that is not self-propelled 
and that combusts natural gas, other gaseous fuel with a total sulfur 
content no greater than the total sulfur content of natural gas, or 
fuel oil in order to heat inlet combustion air and thereby turn a 
turbine, in addition to or instead of producing steam or heating water.
* * * * *
    Zero air material means either:
    (1) A calibration gas certified by the gas vendor not to contain 
concentrations of SO2, NOX, or total hydrocarbons 
above 0.1 parts per million (ppm), a concentration of CO above 1 ppm, a 
concentration of CO2 above 400 ppm; or
    (2) Ambient air conditioned and purified by a CEMS for which the 
CEMS manufacturer or vendor certifies that the particular CEMS model 
produces conditioned gas that does not contain concentrations of 
SO2, NOX, or total hydrocarbons above 0.1 ppm, a 
concentration of CO above 1 ppm, or a concentration of CO2 
above 400 ppm; or
    (3) For dilution-type CEMS, conditioned and purified ambient air 
provided by a conditioning system concurrently supplying dilution air 
to the CEMS; or
    (4) A multicomponent mixture certified by the supplier of the 
mixture that the concentration of the component being zeroed is less 
than or equal to the applicable concentration specified in paragraph 
(1) of this definition, and that the mixture's other components do not 
interfere with the specific CEM readings or cause the CEM being zeroed 
to read concentrations of the gas being zeroed.
    3. Section 72.3 is amended by adding in alphabetical order, new 
acronyms for kacfm, kscfh, and NIST to read as follows:


Sec. 72.3  Measurements, abbreviations, and acronyms.

* * * * *
    kacfm--thousands of cubic feet per minute at actual conditions.
    kscfh--thousands of cubic feet per hour at standard conditions.
    NIST--National Institute of Standards and Technology.
* * * * *


Sec. 72.6  [Amended]

    4. Section 72.6 is amended by removing from paragraph (b)(1) the 
word ``operation'' and adding, in its place, the words ``commercial 
operation.''
    5. Section 72.90 is amended by revising paragraph (c)(3) to read as 
follows:


Sec. 72.90  Annual compliance certification report.

* * * * *
    (c) * * *
    (3) Whether all the emissions from the unit, or a group of units 
(including the unit) using a common stack, were monitored or accounted 
for through the missing data procedures and reported in the quarterly 
monitoring reports, including whether conditional data were reported in 
the quarterly report. If conditional data were reported, the owner or 
operator shall indicate whether the status of all conditional data has 
been resolved and all necessary quarterly report resubmissions have 
been made.
* * * * *

PART 75--CONTINUOUS EMISSION MONITORING

    6. The authority citation for part 75 continues to read as follows:

    Authority: 42 U.S.C. 7601 and 7651k.

    7. Section 75.1 is amended by revising paragraph (a) to read as 
follows:


Sec. 75.1  Purpose and scope.

    (a) Purpose. The purpose of this part is to establish requirements 
for the monitoring, recordkeeping, and reporting of sulfur dioxide, 
nitrogen oxides, and carbon dioxide emissions, volumetric flow, and 
opacity data from affected units under the Acid Rain Program pursuant 
to Sections 412 and 821 of the Clean Air Act, 42 U.S.C. 7401-7671q as 
amended by Public Law 101-549 (November 15, 1990) (the Act). In 
addition, this part sets forth provisions for the monitoring, 
recordkeeping, and reporting of NOX mass emissions with 
which EPA, individual States, or groups of States may require sources 
to comply in order to demonstrate compliance with a NOX mass 
emission reduction program, if these provisions are adopted as 
requirements under such a program.
* * * * *
    8. Section 75.2 is amended by revising paragraph (a) and adding a 
new paragraph (c) to read as follows:


Sec. 75.2 Applicability.

    (a) Except as provided in paragraphs (b) and (c) of this section, 
the provisions of this part apply to each affected unit subject to Acid 
Rain emission limitations or reduction requirements for SO2 
or NOX.
* * * * *
    (c) The provisions of this part may apply to sources subject to a 
State or federal NOX mass emission reduction program, if 
these provisions are adopted as requirements under such a program.
    9. Section 75.4 is amended by revising paragraphs (a) introductory 
text and (d)(1) and adding a new paragraph (i) to read as follows:


Sec. 75.4  Compliance dates.

    (a) The provisions of this part apply to each existing Phase I and 
Phase II unit on February 10, 1993. For substitution or compensating 
units that are so designated under the Acid Rain permit which governs 
that unit and contains the approved substitution or reduced utilization 
plan, pursuant to Sec. 72.41 or Sec. 72.43 of this chapter, the 
provisions of this part become applicable upon the issuance date of the 
Acid Rain permit. For combustion sources seeking to enter the Opt-in 
Program in accordance with part 74 of this chapter, the provisions of 
this part become applicable upon the submission of an Opt-in permit 
application in accordance with Sec. 74.14 of this chapter. The 
provisions of this part for the monitoring, recording, and reporting of 
NOX mass emissions become applicable on the deadlines 
specified in the applicable State or federal NOX mass 
emission reduction program, if these provisions are adopted as 
requirements under such a program. In accordance with Sec. 75.20, the 
owner or operator of each existing affected unit shall ensure that all 
monitoring systems required by

[[Page 28120]]

this part for monitoring SO2, NOX, 
CO2, opacity, and volumetric flow are installed and that all 
certification tests are completed no later than the following dates 
(except as provided in paragraphs (d) through (h) of this section):
* * * * *
    (d) * * *
    (1) The maximum potential concentration of SO2, the 
maximum potential NOX emission rate, the maximum potential 
flow rate, as defined in section 2.1 of appendix A to this part, or the 
maximum potential CO2 concentration, as defined in section 
2.1.3.1 of appendix A to this part.
* * * * *
    (i) In accordance with Sec. 75.20, the owner or operator of each 
affected unit at which SO2 concentration is measured on a 
dry basis or at which moisture corrections are required to account for 
CO2 emissions, NOX emission rate in lb/mmBtu, or 
heat input, shall ensure that the continuous moisture monitoring system 
required by this part is installed and that all applicable initial 
certification tests required under Sec. 75.20(c)(5), (c)(6), or (c)(7) 
for the continuous moisture monitoring system are completed no later 
than the following dates:
    (1) January 1, 2000, for a unit that is existing and has commenced 
commercial operation by October 3, 1999; or
    (2) For a new affected unit which has not commenced commercial 
operation by October 4, 1999, not later than 90 days after the date the 
unit commences commercial operation; or
    (3) For an existing unit that is shutdown and is not yet operating 
by January 1, 2000, not later than the earlier of 45 unit operating 
days or 180 calendar days after the date that the unit recommences 
commercial operation.
    10. Section 75.5 is amended by revising paragraph (f)(2) to read as 
follows:


Sec. 75.5  Prohibitions.

* * * * *
    (f) * * *
    (2) The owner or operator is monitoring emissions from the unit 
with another certified monitoring system or an excepted methodology 
approved by the Administrator for use at that unit that provides 
emission data for the same pollutant or parameter as the retired or 
discontinued monitoring system; or
* * * * *
    11. Section 75.6 is amended by redesignating paragraph (a)(40) as 
paragraph (a)(41) and by adding new paragraphs (a)(40) and (f) to read 
as follows:


Sec. 75.6  Incorporation by reference.

* * * * *
    (a) * * *
    (40) ASTM D5373-93, ``Standard Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples 
of Coal and Coke,'' for appendix G to this part.
* * * * *
    (f) The following materials are available for purchase from the 
following address: American Petroleum Institute, Publications 
Department, 1220 L Street NW, Washington, DC 20005-4070: American 
Petroleum Institute (API) Section 2, ``Conventional Pipe Provers,'' 
from Chapter 4 of the Manual of Petroleum Measurement Standards, 
October 1988 (Reaffirmed 1993), for Sec. 75.20 and appendix D to this 
part.
    12. Section 75.10 is amended by revising paragraphs (d)(3) and (f) 
to read as follows:


Sec. 75.10  General operating requirements.

* * * * *
    (d) * * *
    (3) Failure of an SO2, CO2, or O2 
pollutant concentration monitor, flow monitor, or NOX 
continuous emission monitoring system to acquire the minimum number of 
data points for calculation of an hourly average in paragraph (d)(1) of 
this section, shall result in the failure to obtain a valid hour of 
data and the loss of such component data for the entire hour. An hourly 
average NOX or SO2 emission rate in lb/mmBtu is 
valid only if the minimum number of data points is acquired by both the 
pollutant concentration monitor (NOX or SO2) and 
the diluent monitor (O2 or CO2). For a moisture 
monitoring system consisting of one or more oxygen analyzers capable of 
measuring O2 on a wet-basis and a dry-basis, an hourly 
average percent moisture value is valid only if the minimum number of 
data points is acquired for both the wet-and dry-basis measurements. 
Except for SO2 emission rate data in lb/mmBtu, if a valid 
hour of data is not obtained, the owner or operator shall estimate and 
record emission, moisture, or flow data for the missing hour by means 
of the automated data acquisition and handling system, in accordance 
with the applicable procedure for missing data substitution in subpart 
D of this part.
* * * * *
    (f) Minimum measurement capability requirement. The owner or 
operator shall ensure that each continuous emission monitoring system 
and component thereof is capable of accurately measuring, recording, 
and reporting data, and shall not incur a full scale exceedance, except 
as provided in sections 2.1.1.5, 2.1.2.5, and 2.1.4.3 of appendix A to 
this part.
* * * * *
    13. Section 75.11 is amended by revising paragraphs (a), (b), 
(d)(1), (d)(2), (e)(2), (e)(3) introductory text, (e)(3)(ii), 
(e)(3)(iv), and (e)(4) and by adding paragraph (d)(3), to read as 
follows:


Sec. 75.11  Specific provisions for monitoring SO2 emissions 
(SO2 and flow monitors).

    (a) Coal-fired units. The owner or operator shall meet the general 
operating requirements in Sec. 75.10 for an SO2 continuous 
emission monitoring system and a flow monitoring system for each 
affected coal-fired unit while the unit is combusting coal and/or any 
other fuel, except as provided in paragraph (e) of this section, in 
Sec. 75.16, and in subpart E of this part. During hours in which only 
natural gas or gaseous fuel with a total sulfur content no greater than 
the total sulfur content of natural gas (i.e.,  20 grains 
per 100 standard cubic feet (gr/100 scf)) is combusted in the unit, the 
owner or operator shall comply with the applicable provisions of 
paragraph (e)(1), (e)(2), or (e)(3) of this section.
    (b) Moisture correction. Where SO2 concentration is 
measured on a dry basis, the owner or operator shall install, operate, 
maintain, and quality assure a continuous moisture monitoring system 
for measuring and recording the moisture content of the flue gases, in 
order to correct the measured hourly volumetric flow rates for moisture 
when calculating SO2 mass emissions (in lb/hr) using the 
procedures in appendix F to this part. The following continuous 
moisture monitoring systems are acceptable: a continuous moisture 
sensor; an oxygen analyzer (or analyzers) capable of measuring 
O2 both on a wet basis and on a dry basis; or a stack 
temperature sensor and a moisture look-up table, i.e., a psychrometric 
chart (for saturated gas streams following wet scrubbers, only). The 
moisture monitoring system shall include as a component the automated 
data acquisition and handling system (DAHS) for recording and reporting 
both the raw data (e.g., hourly average wet and dry-basis O2 
values) and the hourly average values of the stack gas moisture content 
derived from those data. When a moisture look-up table is used, the 
moisture monitoring system shall be represented as a single component, 
the certified DAHS, in the monitoring plan for the unit or common 
stack.
* * * * *
    (d) * * *
    (1) By meeting the general operating requirements in Sec. 75.10 for 
an SO2 continuous emission monitoring system

[[Page 28121]]

and flow monitoring system. If this option is selected, the owner or 
operator shall comply with the applicable provisions in paragraph 
(e)(1), (e)(2), or (e)(3) of this section during hours in which the 
unit combusts only natural gas (or gaseous fuel with a total sulfur 
content no greater than the total sulfur content of natural gas);
    (2) By providing other information satisfactory to the 
Administrator using the applicable procedures specified in appendix D 
to this part for estimating hourly SO2 mass emissions. 
Appendix D shall not, however, be used when the unit combusts gaseous 
fuel with a total sulfur content greater than the total sulfur content 
of natural gas (i.e., > 20 gr/100 scf); when such fuel is burned, the 
owner or operator shall comply with the provisions of paragraph (e)(4) 
of this section; or
    (3) By using the low mass emissions excepted methodology in 
Sec. 75.19(c) for estimating hourly SO2 mass emissions if 
the affected unit qualifies as a low mass emissions unit under 
Sec. 75.19(a) and (b).
    (e) * * *
    (2) When gaseous fuel with a total sulfur content no greater than 
the total sulfur content of natural gas (i.e.,  20 gr/100 
scf) is combusted in the unit, the owner or operator may, in lieu of 
operating and recording data from the SO2 monitoring system, 
determine SO2 emissions by certifying an excepted monitoring 
system in accordance with Sec. 75.20 and with appendix D to this part, 
by following the fuel sampling and analysis procedures in section 2.3.1 
of appendix D to this part, by meeting the recordkeeping requirements 
of Sec. 75.55 or Sec. 75.58, as applicable, and by meeting all quality 
control and quality assurance requirements for fuel flowmeters in 
appendix D to this part. If this compliance option is selected, the 
hourly unit heat input reported under Sec. 75.54(b)(5) or 
Sec. 75.57(b)(5), as applicable, shall be determined using a certified 
flow monitoring system and a certified diluent monitor, in accordance 
with the procedures in section 5.2 of appendix F of this part. The flow 
monitor and diluent monitor shall meet all of the applicable quality 
control and quality assurance requirements of appendix B of this part.
    (3) When gaseous fuel with a total sulfur content no greater than 
the total sulfur content of natural gas (i.e.,  20 gr/100 
scf) is burned in the unit, the owner or operator may determine 
SO2 mass emissions by using a certified SO2 
continuous monitoring system, in conjunction with a certified flow rate 
monitoring system. However, on and after January 1, 2000, the 
SO2 monitoring system shall be subject to the following 
provisions; prior to January 1, 2000, the owner or operator may comply 
with these provisions:
* * * * *
    (ii) The calibration response of the SO2 monitoring 
system shall be adjusted, either automatically or manually, in 
accordance with the procedures for routine calibration adjustments in 
section 2.1.3 of appendix B to this part, whenever the zero-level 
calibration response during a required daily calibration error test 
exceeds the applicable performance specification of the instrument in 
section 3.1 of appendix A to this part (i.e.,  2.5 percent 
of the span value or  5 ppm, whichever is less 
restrictive). This calibration adjustment is optional if gaseous fuel 
is burned in the affected unit only during unit startup.
* * * * *
    (iv) In accordance with the requirements of section 2.1.1.2 of 
appendix A to this part, for units that sometimes burn natural gas (or 
gaseous fuel with a total sulfur content no greater than the total 
sulfur content of natural gas) and at other times burn higher-sulfur 
fuel(s) such as coal or oil, a second low-scale SO2 
measurement range is not required when natural gas (or gaseous fuel 
with a total sulfur content no greater than the total sulfur content of 
natural gas) is combusted. For units that burn only natural gas (or 
gaseous fuel with a total sulfur content no greater than the total 
sulfur content of natural gas) and burn no other type(s) of fuel(s), 
the owner or operator shall set the span of the SO2 
monitoring system to a value no greater than 200 ppm.
    (4) During any hours in which a unit combusts only gaseous fuel(s) 
with a total sulfur content no greater than the total sulfur content of 
natural gas (i.e.,  20 gr/100 scf), the owner or operator 
shall meet the general operating requirements in Sec. 75.10 for an 
SO2 continuous emission monitoring system and a flow 
monitoring system.
* * * * *
    14. Section 75.12 is amended by revising the title; by 
redesignating existing paragraphs (b), (c), and (d) as paragraphs (c), 
(d), and (f), respectively; by adding new paragraphs (b) and (e); and 
by revising the newly designated paragraph (c), to read as follows:


Sec. 75.12  Specific provisions for monitoring NOX emission 
rate (NOX and diluent gas monitors).

* * * * *
    (b) Moisture correction. If a correction for the stack gas moisture 
content is needed to properly calculate the NOX emission 
rate in lb/mmBtu, i.e., if the NOX pollutant concentration 
monitor measures on a different moisture basis from the diluent 
monitor, the owner or operator shall install, operate, maintain, and 
quality assure a continuous moisture monitoring system, as defined in 
Sec. 75.11(b).
    (c) Determination of NOX emission rate. The owner or 
operator shall calculate hourly, quarterly, and annual NOX 
emission rates (in lb/mmBtu) by combining the NOX 
concentration (in ppm), diluent concentration (in percent O2 
or CO2), and percent moisture (if applicable) measurements 
according to the procedures in appendix F to this part.
* * * * *
    (e) Low mass emissions units. Notwithstanding the requirements of 
Secs. 75.12(a) and (c), the owner or operator of an affected unit that 
qualifies as a low mass emissions unit under Sec. 75.19(a) and (b) 
shall comply with one of the following:
    (1) Meet the general operating requirements in Sec. 75.10 for a 
NOX continuous emission monitoring system;
    (2) Meet the requirements specified in paragraph (d)(2) of this 
section for using the excepted monitoring procedures in appendix E to 
this part, if applicable; or
    (3) Use the low mass emissions excepted methodology in 
Sec. 75.19(c) for estimating hourly NOX emission rate and 
hourly NOX mass emissions.
* * * * *
    15. Section 75.13 is amended by revising paragraphs (a) and (c) and 
by adding paragraph (d) to read as follows:


Sec. 75.13  Specific provisions for monitoring CO2 
emissions.

    (a) CO2 continuous emission monitoring system. If the 
owner or operator chooses to use the continuous emission monitoring 
method, then the owner or operator shall meet the general operating 
requirements in Sec. 75.10 for a CO2 continuous emission 
monitoring system and flow monitoring system for each affected unit. 
The owner or operator shall comply with the applicable provisions 
specified in Secs. 75.11(a) through (e) or Sec. 75.16, except that the 
phrase ``SO2 continuous emission monitoring system'' is 
replaced with ``CO2 continuous emission monitoring system,'' 
the phrase ``SO2 concentration'' is replaced with 
``CO2 concentration,'' the term ``maximum potential 
concentration of SO2'' is replaced with ``maximum potential 
concentration of CO2,'' and the phrase ``SO2 mass 
emissions'' is replaced with ``CO2 mass emissions.''
* * * * *
    (c) Determination of CO2 mass emissions using an O2 
monitor

[[Page 28122]]

according to appendix F. If the owner or operator chooses to use the 
appendix F method, then the owner or operator may determine hourly 
CO2 concentration and mass emissions with a flow monitoring 
system; a continuous O2 concentration monitor; fuel F and 
Fc factors; and, where O2 concentration is 
measured on a dry basis, a continuous moisture monitoring system, as 
defined in Sec. 75.11(b), using the methods and procedures specified in 
appendix F to this part. For units using a common stack, multiple 
stack, or bypass stack, the owner or operator may use the provisions of 
Sec. 75.16, except that the phrase ``SO2 continuous emission 
monitoring system'' is replaced with ``CO2 continuous 
emission monitoring system,'' the term ``maximum potential 
concentration of SO2'' is replaced with ``maximum potential 
concentration of CO2,'' and the phrase ``SO2 mass 
emissions'' is replaced with ``CO2 mass emissions.''
    (d) Determination of CO2 mass emissions from low mass 
emissions units. The owner or operator of a unit that qualifies as a 
low mass emissions unit under Secs. 75.19(a) and (b) shall comply with 
one of the following:
    (1) Meet the general operating requirements in Sec. 75.10 for a 
CO2 continuous emission monitoring system and flow 
monitoring system;
    (2) Meet the requirements specified in paragraph (b) or (c) of this 
section for use of the methods in appendix G or F to this part, 
respectively; or
    (3) Use the low mass emissions excepted methodology in 
Sec. 75.19(c) for estimating hourly CO2 mass emissions.
    16. Section 75.16 is amended by:
    a. Revising paragraphs (b)(2)(ii)(B), (b)(2)(ii)(D), (d)(2), and 
(e)(1);
    b. Removing paragraphs (e)(2) and (e)(3);
    c. Redesignating existing paragraphs (e)(4) and (e)(5) as 
paragraphs (e)(2) and (e)(3), respectively;
    d. Revising the last sentence and adding a new sentence to the end 
of the newly designated paragraph (e)(3); and
    e. Adding a new paragraph (e)(4), to read as follows:


Sec. 75.16  Special provisions for monitoring emissions from common, 
bypass, and multiple stacks for SO2 emissions and heat input 
determinations.

* * * * *
    (b) * * *
    (2) * * *
    (ii) * * *
    (B) Install, certify, operate, and maintain an SO2 
continuous emission monitoring system and flow monitoring system in the 
duct from each nonaffected unit; determine SO2 mass 
emissions from the affected units as the difference between 
SO2 mass emissions measured in the common stack and 
SO2 mass emissions measured in the ducts of the nonaffected 
units, not to be reported as an hourly average value less than zero; 
combine emissions for the Phase I and Phase II affected units for 
recordkeeping and compliance purposes; calculate and report 
SO2 mass emissions from the Phase I and Phase II affected 
units, pursuant to an approach approved by the Administrator, such that 
these emissions are not underestimated; or
* * * * *
    (D) Petition through the designated representative and provide 
information satisfactory to the Administrator on methods for 
apportioning SO2 mass emissions measured in the common stack 
to each of the units using the common stack and on reporting the 
SO2 mass emissions. The Administrator may approve such 
demonstrated substitute methods for apportioning and reporting 
SO2 mass emissions measured in a common stack whenever the 
demonstration ensures that there is a complete and accurate accounting 
of all emissions regulated under this part and, in particular, that the 
emissions from any affected unit are not underestimated.
* * * * *
    (d) * * *
    (2) Install, certify, operate, and maintain an SO2 
continuous emission monitoring system and flow monitoring system in 
each stack. Determine SO2 mass emissions from each affected 
unit as the sum of the SO2 mass emissions recorded for each 
stack. Notwithstanding the prior sentence, if another unit also 
exhausts flue gases to one or more of the stacks, the owner or operator 
shall also comply with the applicable common stack requirements of this 
section to determine and record SO2 mass emissions from the 
units using that stack and shall calculate and report SO2 
mass emissions from the affected units and stacks, pursuant to an 
approach approved by the Administrator, such that these emissions are 
not underestimated.
    (e) * * *
    (1) The owner or operator of an affected unit using a common stack, 
bypass stack, or multiple stack with a diluent monitor and a flow 
monitor on each stack may choose to install monitors to determine the 
heat input for the affected unit, wherever flow and diluent monitor 
measurements are used to determine the heat input, using the procedures 
specified in paragraphs (a) through (d) of this section, except that 
the terms ``SO2 mass emissions'' and ``emissions'' are 
replaced with the term ``heat input'' and the phrase ``SO2 
continuous emission monitoring system and flow monitoring system'' is 
replaced with the phrase ``a diluent monitor and a flow monitor.'' The 
applicable equation in appendix F to this part shall be used to 
calculate the heat input from the hourly flow rate, diluent monitor 
measurements, and (if the equation in appendix F requires a correction 
for the stack gas moisture content) hourly moisture measurements. 
Notwithstanding the options for combining heat input in paragraphs 
(a)(1)(ii), (a)(2)(ii), (b)(1)(ii), and (b)(2)(ii) of this section, the 
owner or operator of an affected unit with a diluent monitor and a flow 
monitor installed on a common stack to determine the combined heat 
input at the common stack shall also determine and report heat input to 
each individual unit.
* * * * *
    (3) * * * The heat input may be apportioned either by using the 
ratio of load (in MWe-hr) for each individual unit to the total load 
for all units utilizing the common stack or by using the ratio of steam 
flow (in 1000 lb) for each individual unit to the total steam flow for 
all units utilizing the common stack. The heat input should be 
apportioned according to the procedures in appendix F to this part.
    (4) Notwithstanding paragraph (e)(1) of this section, any affected 
unit that is using the procedures in this part to meet the monitoring 
and reporting requirements of a State or federal NOX mass 
emission reduction program must also meet the requirements for 
monitoring heat input in Secs. 75.71 and 75.72.
    17. Section 75.17 is amended by adding introductory text before 
paragraph (a) and by revising paragraph (a)(2)(i)(C) to read as 
follows:


Sec. 75.17  Specific provisions for monitoring emissions from common, 
by-pass, and multiple stacks for NOX emission rate.

    Notwithstanding the provisions of paragraphs (a), (b), and (c) of 
this section, the owner or operator of an affected unit that is using 
the procedures in this part to meet the monitoring and reporting 
requirements of a State or federal NOX mass emission 
reduction program must also meet the provisions for monitoring 
NOX emission rate in Secs. 75.71 and 75.72.
    (a) * * *
    (2) * * *
    (i) * * *
    (C) Each unit's compliance with the applicable NOX 
emission limit will be determined by a method satisfactory to

[[Page 28123]]

the Administrator for apportioning to each of the units the combined 
NOX emission rate (in lb/mmBtu) measured in the common stack 
and for reporting the NOX emission rate, as provided in a 
petition submitted by the designated representative. The Administrator 
may approve such demonstrated substitute methods for apportioning and 
reporting NOX emission rate measured in a common stack 
whenever the demonstration ensures that there is a complete and 
accurate estimation of all emissions regulated under this part and, in 
particular, that the emissions from any unit with a NOX 
emission limitation are not underestimated.
* * * * *
    18. Section 75.19 is added to subpart B to read as follows:


Sec. 75.19  Optional SO2, NOX, and CO2 
emissions calculation for low mass emissions units.

    (a) Applicability. (1) Consistent with the requirements of 
paragraphs (a)(2) and (b) of this section, the low mass emissions 
excepted methodology in paragraph (c) of this section may be used in 
lieu of continuous emission monitoring systems or, if applicable, in 
lieu of excepted methods under appendix D or E to this part, for the 
purpose of determining hourly heat input, hourly NOX 
emission rate, and hourly NOX, SO2, and 
CO2 mass emissions from a low mass emissions unit. A low 
mass emissions unit is a gas-fired or oil-fired unit that burns only 
natural gas and/or fuel oil and that:
    (i) Emits no more than 25 tons of SO2 annually and no 
more than 25 tons of NOX annually; and
    (ii) Has calculated emissions of no more than 25 tons of 
SO2 annually and no more than 25 tons of NOX 
annually based on the maximum rated hourly heat input, the actual 
operating time for each fuel burned, and the low mass emissions 
excepted methodology, calculations, and values in paragraph (c) of this 
section.
    (2) A unit may initially qualify as a low mass emissions unit only 
under the following circumstances:
    (i) The designated representative provides historical actual and 
calculated emissions data from the previous three calendar years 
immediately prior to the submission of an application to use the low 
mass emissions excepted methodology, and the data demonstrates to the 
satisfaction of the Administrator that the unit meets the criteria in 
paragraphs (a)(1)(i) and (ii) of this section; or
    (ii) If a unit does not have the historical data required in 
paragraph (a)(2)(i) of this section for any one or more of the previous 
three calendar years, the designated representative submits:
    (A) Any historical annual emissions and operating data, as required 
in paragraphs (a)(1)(i) and (a)(1)(ii) of this section, beginning with 
the unit's first calendar year of commercial operation, and the data 
demonstrates to the satisfaction of the Administrator that the unit 
meets the criteria in paragraphs (a)(1)(i) and (a)(1)(ii) of this 
section; and
    (B) A demonstration satisfactory to the Administrator that the unit 
will continue to qualify as a low mass emissions unit under the 
requirements of this paragraph (a). The demonstration shall include any 
historical emissions and operating data for less than a calendar year 
for the unit and projected emissions information for the unit, as 
determined using projected operating hours and fuel usage, and the low 
mass emissions excepted methodology, calculations, and values in 
paragraph (c) of this section.
    (b) Disqualification. If a unit that initially qualifies as a low 
mass emissions units under this section changes the fuel that is burned 
in the unit such that a fuel other than natural gas or fuel oil is 
combusted in the unit, the unit is disqualified from using the low mass 
emissions excepted methodology as of the first hour that the new fuel 
is combusted in the unit. In addition, if a unit that initially 
qualifies as a low mass emissions unit under this section emits more 
than 25 tons of SO2 or 25 tons of NOX in any 
calendar year or has calculated emissions greater than 25 tons of 
SO2 or 25 tons of NOX in any calendar year, as 
determined using the low mass emission equations in paragraph (c) of 
this section, the owner or operator of the unit shall have two quarters 
from the end of the quarter in which the exceedance occurs to install, 
certify, and report SO2, NOX, and CO2 
from monitoring systems that meet the requirements of Secs. 75.11, 
75.12, and 75.13, respectively. The unit shall be disqualified as a low 
mass emissions unit as of the end of the second quarter following the 
quarter in which either of the 25 ton limits was exceeded. A unit that 
has been disqualified from using the low mass emissions excepted 
methodology may subsequently qualify again as a low mass emissions unit 
under paragraph (a)(2) of this section, provided that if such unit 
qualified under paragraph (a)(2)(ii) of this section, the unit may 
subsequently qualify again if the unit meets the requirements of 
paragraph (a)(2)(i) of this section.
    (c) Low mass emissions excepted methodology, calculations, and 
values.--(1) Operating time. (i) Report an hourly record if the unit 
operated for any portion of the hour or if records are missing, as to 
whether or not the unit operated for any portion of that hour.
    (ii) Quarterly operating time (hr) is equal to the sum of all of 
the reported operating hours in the quarter, such that any hour in 
which the unit combusted fuel for any portion of the hour is considered 
a full hour.
    (iii) Year-to-date cumulative operating time (hr) is equal to the 
sum of all of the reported operating hours in the year to date, such 
that any hour in which the unit combusted fuel for any portion of the 
hour is considered a full hour.
    (2) Heat input. (i) Hourly heat input (mmBtu) is equal to the 
maximum rated hourly heat input, as defined in Sec. 72.2 of this 
chapter. However, the owner or operator of an affected unit may 
petition the Administrator under Sec. 75.66 for a lower value for 
maximum rated hourly heat input than that defined in Sec. 72.2 of this 
chapter. The Administrator may approve such lower value if the owner or 
operator demonstrates that either the maximum hourly heat input 
specified by the manufacturer or the highest observed hourly heat 
input, or both, are not representative of the unit's current 
capabilities because modifications have been made to the unit, limiting 
its capacity permanently.
    (ii) Calculate the quarterly total heat input (mmBtu) using 
Equation 7a as follows:

HIqtr = Tqtr  x  HIhr

(Eq. 7a)
where:

Tqtr = Actual number of operating hours in the quarter, in 
hr.
HIhr = Hourly heat input under paragraph (c)(2)(i) of this 
section, in mmBtu.

    (iii) Calculate the year-to-date cumulative heat input (mmBtu) as 
the sum of all of the hourly heat input values in the year to date.
    (3) SO2. (i) Calculate the hourly total SO2 
mass emissions (lbs) using Equation 7b and the appropriate fuel-based 
SO2 emission factor from Table 1a for the fuel being burned 
in that hour. If more than one fuel is burned in the hour, use the 
highest emission factor for all of the fuels burned in the hour. If 
records are missing as to which fuel was burned in the hour, use the 
highest emission factor for all of the fuels capable of being burned in 
that unit.

    Table 1a.--SO2 Emission Factors (lb/mmBtu) for Various Fuel Types   
------------------------------------------------------------------------
                 Fuel type                      SO2 Emission factors    
------------------------------------------------------------------------
Pipeline Natural Gas......................  0.0006 lb/mmBtu.            

[[Page 28124]]

                                                                        
Natural Gas...............................  0.06 lb/mmBtu.              
Residual Oil..............................  2.1 lb/mmBtu.               
Diesel Fuel...............................  0.5 lb/mmBtu.               
------------------------------------------------------------------------

WSO2 = EFSO2 x HIhr

(Eq. 7b)

Where:

WSO2 = SO2 mass emissions, in lbs.
EFSO2 = Fuel-based SO2 emission factor 
from Table 1a of this section, in lb/mmBtu.
HIhr = Hourly heat input under paragraph (c)(2)(i) of this 
section, in mmBtu.

    (ii) Calculate the quarterly total SO2 mass emissions 
(tons) by summing all of the hourly SO2 mass emissions under 
paragraph (c)(3)(i) of this section in the quarter and dividing by 2000 
lb/ton.
    (iii) Calculate the year-to-date cumulative SO2 mass 
emissions (tons) by summing all of the SO2 mass emissions 
under paragraph (c)(3)(i) of this section in the year to date.
    (4) NOX. (i) Determine the hourly NOX 
emission rate (lb/mmBtu) by using the appropriate fuel and boiler type 
default NOX emission rate in Table 1b for the fuel being 
burned in that hour. If more than one fuel is burned in the hour, use 
the highest emission rate for all of the fuels burned in the hour. If 
records are missing as to which fuel was burned in the hour, use the 
highest emission factor for all of the fuels capable of being burned in 
that unit.

 Table 1b.--NOX Emission Rates (lb/mmBtu) for Various Boiler/Fuel Types 
------------------------------------------------------------------------
                                                                 NOX    
            Boiler type                     Fuel type          Emission 
                                                                 rate   
------------------------------------------------------------------------
Tangentially fired.................  Oil...................        0.366
Tangentially fired.................  Gas...................        0.290
Dry Bottom Wall fired..............  Oil...................        0.490
Dry Bottom Wall fired..............  Gas...................        0.400
Combustion Turbine.................  Oil...................        0.258
Combustion Turbine.................  Gas...................        0.172
Combined Cycle.....................  Oil...................        0.273
Combined Cycle.....................  Gas...................        0.273
------------------------------------------------------------------------

    (ii) Calculate the hourly total NOX mass emissions (lbs) 
as the product of the NOX emission rate (lb/mmBtu) and 
hourly heat input (mmBtu), using Equation 7c as follows:

WNOX = EFNOX  x  HIhr

(Eq. 7c)
where:

WNOX = NOX mass emissions, in lbs.
EFNOX = Boiler-type and fuel-type NOX emission 
factor from Table 1b of this section, in lb/mmBtu.
HIhr = Hourly heat input under paragraph (c)(2)(i) of this 
section, in mmBtu.

    (iii) Calculate the quarterly average NOX emission rate 
(lb/mmBtu) by summing all of the hourly NOX emission rates 
for the quarter and dividing the total by the number of reported 
operating hours under paragraph (c)(1)(i) of this section in the 
quarter.
    (iv) Calculate the quarterly total NOX mass emissions 
(tons) by summing all of the hourly NOX mass emissions under 
paragraph (c)(4)(ii) of this section in the quarter and dividing the 
total by 2000 lb/ton.
    (v) Calculate the year-to-date cumulative average NOX 
emission rate (lb/mmBtu) by summing all of the hourly NOX 
emission rates for all of the hours in the year to date and dividing 
the total by the number of reported operating hours under paragraph 
(c)(1)(i) of this section in the year to date.
    (vi) Calculate the year-to-date cumulative NOX mass 
emissions total (tons) by summing all of the hourly NOX mass 
emissions under paragraph (c)(4)(ii) of this section in the year to 
date.
    (5) CO2. (i) Calculate the hourly total CO2 
mass emissions (tons) using Equation 7d and the appropriate fuel-based 
CO2 emission factor from Table 1c for the fuel being burned 
in that hour. If more than one fuel is burned in the hour, use the 
highest emission factor for all of the fuels burned in the hour. If 
records are missing as to which fuel was burned in the hour, use the 
highest emission factor for all of the fuels capable of being burned in 
that unit.

       Table 1c.--CO2 Emission Factors (ton/mmBtu) for Gas and Oil      
------------------------------------------------------------------------
                 Fuel type                      CO2 emission factors    
------------------------------------------------------------------------
Natural Gas...............................  0.059 ton/mmBtu.            
Oil.......................................  0.081 ton/mmBtu.            
------------------------------------------------------------------------

WCO2=EFCO2  x  HIhr

(Eq. 7d)

Where:

WCO2 = CO2 mass emissions, in tons.
EFCO2 = Fuel-based CO2 emission factor from Table 
1c, in ton/mmBtu.
HIhr = Hourly heat input under paragraph (c)(2)(i) of this 
section, in mmBtu.

    (ii) Calculate the quarterly total CO2 mass emissions 
(tons) by summing all of the hourly CO2 mass emissions under 
paragraph (c)(5)(i) of this section in the quarter.
    (iii) Calculate the year-to-date cumulative CO2 mass 
emissions (tons) by summing all of the hourly CO2 mass 
emissions under paragraph (c)(5)(i) of this section in the year to 
date.
    (d) The quality control and quality assurance requirements in 
Sec. 75.21 are not required for a low mass emissions unit for which the 
optional low mass emissions excepted methodology in paragraph (c) of 
this section is being used in lieu of a continuous emission monitoring 
system or an excepted monitoring system under appendix D or E to this 
part.

Subpart C--[Amended]

    19. Section 75.20 is amended by:
    a. Revising the title of the section;
    b. Revising the titles of paragraphs (a)(3), (a)(4), (c), (d), (g), 
(g)(1), (g)(2), (g)(4), and (g)(5);
    c. Revising paragraphs (a) introductory text, (a)(1), (a)(3), 
(a)(4) introductory text, (a)(4)(i), (a)(4)(ii), (a)(4)(iii), 
(a)(5)(i), (b), (c) introductory text, (c)(1)(iii), (d)(1), (d)(2), (g) 
introductory text, (g)(1) introductory text, (g)(1)(i), (g)(2), (g)(4), 
and (g)(5);
    d. Removing existing paragraph (c)(3);
    e. Revising and redesignating existing paragraphs (c)(4), (c)(5), 
(c)(6), (c)(7), and (c)(8) as paragraphs (c)(3), (c)(4), (c)(8), 
(c)(9), and (c)(10), respectively; and revising newly designated 
paragraphs (c)(4) introductory text, (c)(8) introductory text, 
(c)(8)(i),

[[Page 28125]]

(c)(9)(ii), and (c)(10) introductory text; and
    f. Adding new paragraphs (c)(5), (c)(6), (c)(7), (g)(6), (g)(7), 
(h), and (i), to read as follows:


Sec. 75.20  Initial certification and recertification procedures.

    (a) Initial certification approval process. The owner or operator 
shall ensure that each continuous emission or opacity monitoring system 
required by this part, which includes the automated data acquisition 
and handling system, and, where applicable, the CO2 
continuous emission monitoring system, meets the initial certification 
requirements of this section and shall ensure that all applicable 
initial certification tests under paragraph (c) of this section are 
completed by the deadlines specified in Sec. 75.4 and prior to use in 
the Acid Rain Program. In addition, whenever the owner or operator 
installs a continuous emission or opacity monitoring system in order to 
meet the requirements of Secs. 75.13 through 75.18, where no continuous 
emission or opacity monitoring system was previously installed, initial 
certification is required.
    (1) Notification of initial certification test dates. The owner or 
operator or designated representative shall submit a written notice of 
the dates of initial certification testing at the unit as specified in 
Sec. 75.61(a)(1).
* * * * *
    (3) Provisional approval of certification (or recertification) 
applications. Upon the successful completion of the required 
certification (or recertification) procedures of this section for each 
continuous emission or opacity monitoring system or component thereof, 
each continuous emission or opacity monitoring system or component 
thereof shall be deemed provisionally certified (or recertified) for 
use under the Acid Rain Program for a period not to exceed 120 days 
following receipt by the Administrator of the complete certification 
(or recertification) application under paragraph (a)(4) of this 
section, provided that no continuous emission or opacity monitor 
systems for a combustion source seeking to enter the Opt-in Program in 
accordance with part 74 of this chapter shall be deemed provisionally 
certified (or recertified) for use under the Acid Rain Program. Data 
measured and recorded by a provisionally certified (or recertified) 
continuous emission or opacity monitoring system or component thereof, 
in accordance with the requirements of appendix B to this part, will be 
considered valid quality-assured data (retroactive to the date and time 
of provisional certification or recertification)), provided that the 
Administrator does not invalidate the provisional certification (or 
recertification) by issuing a notice of disapproval within 120 days of 
receipt by the Administrator of the complete certification (or 
recertification) application. Note that if the data validation 
procedures of paragraph (b)(3) of this section are applied to the 
initial certification (or recertification) of a continuous emissions 
monitoring system, it is possible for data recorded by the CEMS during 
the certification (or recertification) test period to be quality 
assured retrospectively, upon completion of all of the certification 
(or recertification) tests. Therefore, in certain instances, the date 
and time of provisional certification (or recertification) of the CEMS 
may be earlier than the date and time of completion of the required 
certification (or recertification) tests.
    (4) Certification (or recertification) application formal approval 
process. The Administrator will issue a notice of approval or 
disapproval of the certification (or recertification) application to 
the owner or operator within 120 days of receipt of the complete 
certification (or recertification) application. In the event the 
Administrator does not issue such a written notice within 120 days of 
receipt, each continuous emission or opacity monitoring system which 
meets the performance requirements of this part and is included in the 
certification (or recertification) application will be deemed certified 
(or recertified) for use under the Acid Rain Program.
    (i) Approval notice. If the certification (or recertification) 
application is complete and shows that each continuous emission or 
opacity monitoring system meets the performance requirements of this 
part, then the Administrator will issue a written notice of approval of 
the certification (or recertification) application within 120 days of 
receipt.
    (ii) Incomplete application notice. A certification (or 
recertification) application will be considered complete when all of 
the applicable information required to be submitted in Sec. 75.63 has 
been received by the Administrator, the EPA Regional Office, and the 
appropriate State and/or local air pollution control agency. If the 
certification (or recertification) application is not complete, then 
the Administrator will issue a written notice of incompleteness that 
provides a reasonable timeframe for the designated representative to 
submit the additional information required to complete the 
certification (or recertification) application. If the designated 
representative has not complied with the notice of incompleteness by a 
specified due date, then the Administrator may issue a notice of 
disapproval specified under paragraph (a)(4)(iii) of this section. The 
120-day review period shall not begin prior to receipt of a complete 
application.
    (iii) Disapproval notice. If the certification (or recertification) 
application shows that any continuous emission or opacity monitoring 
system or component thereof does not meet the performance requirements 
of this part, or if the certification (or recertification) application 
is incomplete and the requirement for disapproval under paragraph 
(a)(4)(ii) of this section has been met, the Administrator shall issue 
a written notice of disapproval of the certification (or 
recertification) application within 120 days of receipt. By issuing the 
notice of disapproval, the provisional certification (or 
recertification) is invalidated by the Administrator, and the data 
measured and recorded by each uncertified continuous emission or 
opacity monitoring system or component thereof shall not be considered 
valid quality-assured data beginning with the following time: from the 
hour of the probationary calibration error test that began the initial 
certification (or recertification) test period, if the data validation 
procedures of paragraph (b)(3) of this section were used to 
retrospectively validate data; or from the date and time of completion 
of the invalid certification tests until the date and time that the 
owner or operator completes subsequently approved initial certification 
tests, if the data validation procedures of paragraph (b)(3) of this 
section were not used. The owner or operator shall follow the 
procedures for loss of initial certification in paragraph (a)(5) of 
this section for each continuous emission or opacity monitoring system 
or component thereof which is disapproved for initial certification. 
For each disapproved recertification, the owner or operator shall 
follow the procedures of paragraph (b)(5) of this section.
* * * * *
    (5) * * *
    (i) Until such time, date, and hour as the continuous emission 
monitoring system or component thereof can be adjusted, repaired, or 
replaced and certification tests successfully completed, the owner or 
operator shall substitute the following values, as applicable, for each 
hour of unit operation during the period of invalid

[[Page 28126]]

data specified in paragraph (a)(4)(iii) of this section or in 
Sec. 75.21: the maximum potential concentration of SO2 as 
defined in section 2.1.1.1 of appendix A to this part to report 
SO2 concentration; the maximum potential NOX 
emission rate, as defined in Sec. 72.2 of this chapter to report 
NOX emissions; the maximum potential flow rate, as defined 
in section 2.1.4.1 of appendix A to this part to report volumetric 
flow; or the maximum potential concentration of CO2, as 
defined in section 2.1.3.1 of appendix A to this part to report 
CO2 concentration data; and
* * * * *
    (b) Recertification approval process. Whenever the owner or 
operator makes a replacement, modification, or change in a certified 
continuous emission monitoring system or continuous opacity monitoring 
system that is determined by the Administrator to significantly affect 
the ability of the system to accurately measure or record the 
SO2 or CO2 concentration, stack gas volumetric 
flow rate, NOX emission rate, or opacity, or to meet the 
requirements of Sec. 75.21 or appendix B to this part, the owner or 
operator shall recertify the continuous emission monitoring system or 
continuous opacity monitoring system, according to the procedures in 
this paragraph. Furthermore, whenever the owner or operator makes a 
replacement, modification, or change to the flue gas handling system or 
the unit operation that is determined by the Administrator to 
significantly change the flow or concentration profile, the owner or 
operator shall recertify the monitoring system according to the 
procedures in this paragraph. Examples of changes which require 
recertification include: replacement of the analyzer; change in 
location or orientation of the sampling probe or site; changing of flow 
rate monitor polynomial coefficients; and complete replacement of an 
existing continuous emission monitoring system or continuous opacity 
monitoring system. The owner or operator shall recertify a continuous 
opacity monitoring system whenever the monitor path length changes or 
as required by an applicable State or local regulation or permit. Any 
change to a stack flow rate or gas monitoring system for which the 
Administrator determines that a RATA is not necessary shall not be 
considered a recertification event. In such cases, any other tests that 
the Administrator determines to be necessary (linearity checks, 
calibration error tests, DAHS verifications, etc.) shall be performed 
as diagnostic tests, rather than recertification tests. The data 
validation procedures in paragraph (b)(3) of this section shall be 
applied to linearity checks, 7-day calibration error tests, and cycle 
time tests when these are required as diagnostic tests. When the data 
validation procedures of paragraph (b)(3) of this section are applied 
in this manner, replace the word ``recertification'' with the word 
``diagnostic.''
    (1) Tests required. For recertification testing after changing the 
flow rate monitor polynomial coefficients, the owner or operator shall 
complete a 3-level RATA. For all other recertification testing, the 
owner or operator shall complete all initial certification tests in 
paragraph (c) of this section that are applicable to the monitoring 
system, except as otherwise approved by the Administrator.
    (2) Notification of recertification test dates. The owner, 
operator, or designated representative shall submit notice of testing 
dates for recertification under this paragraph as specified in 
Sec. 75.61(a)(1)(ii), unless all of the tests in paragraph (c) of this 
section are required for recertification, in which case the owner or 
operator shall provide notice in accordance with the notice provisions 
for initial certification testing in Sec. 75.61(a)(1)(i).
    (3) Recertification test period requirements and data validation. 
(i) In the period extending from the hour of the replacement, 
modification or change made to a monitoring system that triggers the 
need to perform recertification test(s) of the CEMS to the hour of 
successful completion of a probationary calibration error test 
(according to paragraph (b)(3)(ii) of this section) following the 
replacement, modification, or change to the CEMS, the owner or operator 
shall either substitute for missing data, according to the standard 
missing data procedures in Secs. 75.33 through 75.37, or report 
emission data using a reference method or another monitoring system 
that has been certified or approved for use under this part.
    (ii) Once the modification or change to the CEMS has been completed 
and all of the associated repairs, component replacements, adjustments, 
linearization, and reprogramming of the CEMS have been completed, a 
probationary calibration error test is required to establish the 
beginning point of the recertification test period. In this instance, 
the first successful calibration error test of the monitoring system 
following completion of all necessary repairs, component replacements, 
adjustments, reprogramming, and any preliminary tests (e.g., trial RATA 
runs or a challenge of the monitor with calibration gases other than 
those used to perform the daily calibration error test) shall be the 
probationary calibration error test. The probationary calibration error 
test must be passed before any of the required recertification tests 
are commenced.
    (iii) Beginning with the hour of commencement of a recertification 
test period, emission data recorded by the CEMS are considered to be 
conditionally valid, contingent upon the results of the subsequent 
recertification tests.
    (iv) Each required recertification test shall be completed no later 
than the following number of unit operating hours after the 
probationary calibration error test that initiates the test period:
    (A) For a linearity test and/or cycle time test, 168 consecutive 
unit operating hours;
    (B) For a RATA (whether normal-load or multiple-load), 720 
consecutive unit operating hours; and
    (C) For a 7-day calibration error test, 21 consecutive unit 
operating days.
    (v) All recertification tests shall be performed hands-off, as 
follows. No adjustments to the calibration of the CEMS, other than the 
adjustments described in section 2.1.3 of appendix B to this part, are 
permitted prior to or during the recertification test period. Routine 
daily calibration error tests shall be performed throughout the 
recertification test period, in accordance with section 2.1.1 of 
appendix B to this part. The additional calibration error test 
requirements in section 2.1.3 of appendix B to this part shall also 
apply during the recertification test period.
    (vi) If all of the required recertification tests and required 
daily calibration error tests are successfully completed in succession 
with no failures, and if each recertification test is completed within 
the time period specified in paragraph (b)(3)(iv)(A), (B), or (C) of 
this section, then all of the conditionally valid emission data 
recorded by the CEMS shall be considered quality assured, from the hour 
of commencement of the recertification test period until the hour of 
completion of the required test(s).
    (vii) If a required recertification test is failed or aborted due 
to a problem with the CEMS, or if a calibration error test is failed 
during a recertification test period, data validation shall be done as 
follows:
    (A) If any required recertification test is failed, it shall be 
repeated. If any recertification test other than a 7-day calibration 
error test is failed or aborted due to a problem with the CEMS, the 
original recertification test period is ended, and a new 
recertification test period must be commenced with a

[[Page 28127]]

probationary calibration error test. The tests that are required in 
this new recertification test period will include any tests that were 
required for the initial recertification event which were not 
successfully completed and any recertification or diagnostic tests that 
are required as a result of changes made to the monitoring system to 
correct the problems that caused the failure of the recertification 
test. The new recertification test sequence shall not be commenced 
until all necessary maintenance activities, adjustments, 
linearizations, and reprogramming of the CEMS have been completed;
    (B) If a linearity test, RATA, or cycle time test is failed or 
aborted due to a problem with the CEMS, all conditionally valid 
emission data recorded by the CEMS are invalidated, from the hour of 
commencement of the recertification test period to the hour in which 
the test is failed or aborted. Data from the CEMS remain invalid until 
the hour in which a new recertification test period is commenced, 
following corrective action, and a probationary calibration error test 
is passed, at which time the conditionally valid status of emission 
data from the CEMS begins;
    (C) If a 7-day calibration error test is failed within the 
recertification test period, previously-recorded conditionally valid 
emission data from the CEMS are not invalidated, provided that the 
calibration error on the day of the failed 7-day calibration error test 
does not exceed twice the performance specification in section 3 of 
appendix A to this part; and
    (D) If a calibration error test is failed (i.e., the results of the 
test exceed twice the performance specification in section 3 of 
appendix A to this part) during a recertification test period, the CEMS 
is out-of-control as of the hour in which the calibration error test is 
failed. Emission data from the CEMS shall be invalidated prospectively 
from the hour of the failed calibration error test until the hour of 
completion of a subsequent successful calibration error test following 
corrective action, at which time the conditionally valid status of data 
from the monitoring system resumes. Failure to perform a required daily 
calibration error test during a recertification test period shall also 
cause data from the CEMS to be invalidated prospectively, from the hour 
in which the calibration error test was due until the hour of 
completion of a subsequent successful calibration error test. 
Previously-passed recertification tests in the sequence and previously-
recorded conditionally valid data shall not be affected by a late 
calibration error test. Whenever a calibration error test is failed or 
missed during a recertification test period, no further recertification 
tests shall be performed until the required subsequent calibration 
error has been passed, re-establishing the conditionally valid status 
of data from the monitoring system.
    (viii) If any required recertification test is not completed within 
its allotted time period, data validation shall be done as follows. For 
a late linearity test, RATA, or cycle time test that is passed on the 
first attempt, data from the monitoring system shall be invalidated 
from the hour of expiration of the recertification test period until 
the hour of completion of the late test. For a late 7-day calibration 
error test, whether or not it is passed on the first attempt, data from 
the monitoring system shall also be invalidated from the hour of 
expiration of the recertification test period until the hour of 
completion of the late test. For a late linearity test, RATA, or cycle 
time test that is failed on the first attempt or aborted on the first 
attempt due to a problem with the monitor, all conditionally valid data 
from the monitoring system shall be considered invalid back to the hour 
of the first probationary calibration error test which initiated the 
recertification test period. Data from the monitoring system shall 
remain invalid until the hour of successful completion of the late 
recertification test and any additional recertification or diagnostic 
tests that are required as a result of changes made to the monitoring 
system to correct problems that caused failure of the late 
recertification test.
    (ix) If any required recertification test of a monitoring system 
has not been completed by the end of a calendar quarter and if data 
contained in the quarterly report is conditionally valid pending the 
results of test(s) to be completed in a subsequent quarter, the owner 
or operator shall indicate this by means of a suitable conditional data 
flag in the electronic quarterly report for that quarter. The owner or 
operator shall resubmit the report for that quarter if the required 
recertification test is subsequently failed. In the resubmitted report, 
the owner or operator shall use the appropriate missing data routine in 
Sec. 75.31 or Sec. 75.33 to replace with substitute data each hour of 
conditionally valid data that was invalidated by the failed 
recertification test. In addition, if the owner or operator submits any 
conditionally valid data (as defined in Sec. 72.2 of this chapter) in 
any of the four quarterly reports for a given year, the owner or 
operator shall indicate the status of the conditionally valid data 
(i.e., resolved or unresolved) in the annual compliance certification 
report required under Sec. 72.90 of this chapter for that year. 
Alternatively, if any required recertification test is not completed by 
the end of a particular calendar quarter but is completed no later than 
30 days after the end of that quarter (i.e., prior to the deadline for 
submitting the quarterly report under Sec. 75.64), the test data and 
results may be submitted with the earlier quarterly report even though 
the test date(s) are from the next calendar quarter. In such instances, 
if the recertification test(s) are passed in accordance with the 
provisions of paragraph (b)(3) of this section, conditionally valid 
data may be reported as quality-assured, in lieu of reporting a 
conditional data flag. If the recertification test(s) is failed and if 
conditionally valid data are replaced, as appropriate, with substitute 
data, then neither the reporting of a conditional data flag nor 
resubmission is required.
    (x) If the replacement, modification, or change requiring 
recertification of the CEMS is such that the data collected by the 
prior certified monitoring system are no longer representative, such as 
after a change to the flue gas handling system or unit operation that 
requires changing the span value to be consistent with section 2.1 of 
appendix A to this part, the owner or operator shall substitute for 
missing data as follows, in the period extending from the hour of 
commencement of the replacement, modification, or change requiring 
recertification of the CEMS to the hour of commencement of the 
recertification test period:
    (A) For a change that results in a significantly higher 
concentration or flow rate, substitute maximum potential values 
according to the procedures in paragraph (a)(5) of this section; or
    (B) For a change that results in a significantly lower 
concentration or flow rate, substitute data using the standard missing 
data procedures.
    (C) The owner or operator shall then use the initial missing data 
procedures in Sec. 75.31, beginning with the first hour of quality 
assured data obtained with the recertified monitoring system, unless 
otherwise provided by Sec. 75.34 for units with add-on emission 
controls.
    (4) Recertification application. The designated representative 
shall apply for recertification of each continuous emission or opacity 
monitoring system used under the Acid Rain Program. The owner or 
operator shall submit the recertification application in accordance 
with Sec. 75.60, and each complete recertification application shall 
include the information specified in Sec. 75.63.
    (5) Approval or disapproval of request for recertification. The 
procedures for

[[Page 28128]]

provisional certification in paragraph (a)(3) of this section shall 
apply to recertification applications. The Administrator will issue a 
written notice of approval or disapproval according to the procedures 
in paragraph (a)(4) of this section. In the event that a 
recertification application is disapproved, data from the monitoring 
system are invalidated and the applicable missing data procedures in 
Sec. 75.31 or Sec. 75.33 shall be used from the date and hour of 
receipt of such notice back to the hour of the probationary calibration 
error test that began the recertification test period. Data from the 
monitoring system remain invalid until a subsequent probationary 
calibration error test is passed, beginning a new recertification test 
period. The owner or operator shall repeat all recertification tests or 
other requirements, as indicated in the Administrator's notice of 
disapproval, no later than 30 unit operating days after the date of 
issuance of the notice of disapproval. The designated representative 
shall submit a notification of the recertification retest dates, as 
specified in Sec. 75.61(a)(1)(ii), and shall submit a new 
recertification application according to the procedures in paragraph 
(b)(4) of this section.
    (c) Initial certification and recertification procedures. Prior to 
the deadline in Sec. 75.4, the owner or operator shall conduct initial 
certification tests and in accordance with Sec. 75.63, the designated 
representative shall submit an application to demonstrate that the 
continuous emission or opacity monitoring system and components thereof 
meet the specifications in appendix A to this part. The owner or 
operator shall compare reference method values with output from the 
automated data acquisition and handling system that is part of the 
continuous emission monitoring system being tested. Except as specified 
in paragraphs (b)(1), (d), and (e) of this section, the owner or 
operator shall perform the following tests for initial certification or 
recertification of continuous emission or opacity monitoring systems or 
components according to the requirements of appendix A to this part:
    (1) * * *
    (iii) A relative accuracy test audit. For the NOX-
diluent system, the RATA shall be done on a system basis, in units of 
lb/mmBtu.
* * * * *
    (3) The initial certification test data from an O2-or a 
CO2-diluent gas monitor certified for use in a 
NOX continuous emission monitoring system may be submitted 
to meet the requirements of paragraph (c)(4) of this section. Also, for 
a diluent monitor that is used both as a CO2 monitoring 
system and to determine heat input, only one set of diluent monitor 
certification data need be submitted (under the component and system 
identification numbers of the CO2 monitoring system).
    (4) For each CO2 pollutant concentration monitor, each 
O2 monitor which is part of a CO2 continuous 
emission monitoring system, each diluent monitor used to monitor heat 
input and each SO2-diluent continuous emission monitoring 
system:
* * * * *
    (5) For each continuous moisture monitoring system consisting of 
wet-and dry-basis O2 analyzers:
    (i) A 7-day calibration error test of each O2 analyzer;
    (ii) A cycle time test of each O2 analyzer;
    (iii) A linearity test of each O2 analyzer; and
    (iv) A RATA, directly comparing the percent moisture measured by 
the monitor to a reference method.
    (6) For each continuous moisture sensor:
    (i) A 7-day calibration error test; and
    (ii) A RATA, directly comparing the percent moisture measured by 
the monitor sensor to a reference method.
    (7) For a continuous moisture monitoring system consisting of a 
temperature sensor and a data acquisition and handling system (DAHS) 
software component programmed with a moisture lookup table:
    (i) A demonstration that the correct moisture value for each hour 
is being taken from the moisture lookup tables and applied to the 
emission calculations. At a minimum, the demonstration shall be made at 
three different temperatures covering the normal range of stack 
temperatures.
    (ii) [Reserved]
    (8) The owner or operator shall ensure that initial certification 
or recertification of a continuous opacity monitor for use under the 
Acid Rain Program is conducted according to one of the following 
procedures:
    (i) Performance of the tests for initial certification or 
recertification, according to the requirements of Performance 
Specification 1 in appendix B to part 60 of this chapter; or
* * * * *
    (9) * * *
    (ii) Proper computation and application of the missing data 
substitution procedures in subpart D of this part and the bias 
adjustment factors in section 7 of appendix A to this part.
    (10) The owner or operator shall provide, or cause to be provided, 
adequate facilities for initial certification or recertification 
testing that include:
* * * * *
    (d) Initial certification and recertification and quality assurance 
procedures for optional backup continuous emission monitoring systems.
    (1) Redundant backups. The owner or operator of an optional 
redundant backup continuous emission monitoring system shall comply 
with all the requirements for initial certification and recertification 
according to the procedures specified in paragraphs (a), (b), and (c) 
of this section. The owner or operator shall operate the redundant 
backup continuous emission monitoring system during all periods of unit 
operation, except for periods of calibration, quality assurance, 
maintenance, or repair. The owner or operator shall perform upon the 
redundant backup continuous emission monitoring system all quality 
assurance and quality control procedures specified in appendix B to 
this part, except that the daily assessments in section 2.1 of appendix 
B to this part are optional for days on which the redundant backup 
monitoring system is not used to report emission data under this part. 
For any day on which a redundant backup monitoring system is used to 
report emission data, the system must meet all of the applicable daily 
assessment criteria in appendix B to this part.
    (2) Non-redundant backups. The owner or operator of an optional 
non-redundant backup continuous emission monitoring system shall comply 
with all of the following requirements for initial certification, 
quality assurance, recertification, and data reporting:
    (i) For a non-redundant backup gas monitoring system that has its 
own separate probe, sample interface, and analyzer or for a non-
redundant backup flow monitor, all of the tests in paragraph (c) of 
this section are required for initial certification of the system, 
except for the 7-day calibration error test.
    (ii) For a non-redundant backup gas monitoring system consisting of 
one or more like-kind replacement analyzers that use the same probe and 
sample interface as a primary monitoring system, no initial 
certification of the non-redundant backup monitoring system is 
required. Note that a non-redundant backup analyzer, connected to the 
same probe and interface as a primary analyzer in order to satisfy the 
dual span requirements of section

[[Page 28129]]

2.1.1.4 or 2.1.2.4 of appendix A to this part, shall be considered a 
like-kind, non-redundant backup analyzer.
    (iii) Each non-redundant backup monitoring system shall comply with 
the daily and quarterly quality assurance and quality control 
requirements in appendix B to this part for each day and quarter that 
the non-redundant backup monitoring system is used to report data, 
except that the requirements for when a linearity test must be 
performed are superseded by the requirements of this section. The owner 
or operator shall ensure that each non-redundant backup continuous 
emission monitoring system passes a linearity check (for pollutant 
concentration and diluent gas monitors) or a calibration error test 
(for flow monitors) prior to each use for recording and reporting 
emissions. For a non-redundant backup NOX-diluent or 
SO2-diluent monitoring system consisting of a primary 
pollutant analyzer and a like-kind replacement diluent analyzer (or 
vice-versa), provided that the primary analyzer is operating and is not 
out-of-control with respect to any of its quality assurance 
requirements, only the like-kind replacement analyzer must pass a 
linearity check before the system is used for data reporting. When a 
non-redundant backup monitoring system is brought into service prior to 
conducting the linearity test, a probationary calibration error test 
(as described in paragraph (b)(3)(ii) of this section), which will 
begin a period of conditionally valid data, may be performed in order 
to allow the use of data retrospectively, as follows. Conditionally 
valid data from the CEMS are validated back to the hour of completion 
of the probationary calibration error test if the following conditions 
are met: if no adjustments are made to the monitor other than those 
specified in section 2.1.3 of appendix B to this part between the 
probationary calibration error test and the successful completion of 
the linearity test, and if the linearity test is passed within 168 unit 
operating hours of the probationary calibration error test. However, if 
the linearity test is either failed, aborted due to a problem with the 
CEMS, or not completed as required, then all of the conditionally valid 
data are invalidated back to the hour of the probationary calibration 
error test, and data from the CEMS remain invalid until the hour of 
completion of a successful linearity test.
    (iv) When data are reported from a non-redundant backup monitoring 
system, the appropriate bias adjustment factor (BAF) shall be 
determined as follows:
    (A) Apply the BAF from the most recent RATA of the non-redundant 
backup system (even if that RATA was done more than 12 months 
previously); or
    (B) If no RATA results are available for the non-redundant backup 
system (e.g., for a non-redundant backup gas monitoring system that 
uses the same probe and sample interface as the primary monitoring 
system), apply the primary monitoring system BAF.
    (v) A non-redundant backup system may not be used for reporting 
data from a particular affected unit or common stack for more than 720 
hours in any one calendar year, unless the monitoring system passes a 
RATA at that same unit or stack.
    (vi) For each non-redundant backup gas monitoring system that has 
its own separate probe, sample interface, and analyzer and for each 
non-redundant backup flow monitor, no more than eight successive 
calendar quarters shall elapse following the quarter in which the last 
RATA of the monitoring system was done at a particular unit or stack, 
without performing a subsequent RATA. Otherwise, the monitoring system 
may not be used to report data from that unit or stack until the hour 
of completion of a successful RATA at that location.
* * * * *
    (g) Initial certification and recertification procedures for 
excepted monitoring systems under appendices D and E. The owner or 
operator of a gas-fired unit, oil-fired unit, or diesel-fired unit 
using the optional protocol under appendix D or E to this part shall 
ensure that an excepted monitoring system under appendix D or E to this 
part meets the applicable general operating requirements of Sec. 75.10, 
the applicable requirements of appendices D and E to this part, and the 
initial certification or recertification requirements of this 
paragraph.
    (1) Initial certification and recertification testing. The owner or 
operator shall use the following procedures for initial certification 
and recertification of an excepted monitoring system under appendix D 
or E to this part.
    (i) When the optional SO2 mass emissions estimation 
procedure in appendix D to this part or the optional NOX 
emissions estimation protocol in appendix E to this part is used, the 
owner or operator shall provide data from a flowmeter accuracy test (or 
shall provide a statement of calibration if the flowmeter meets the 
accuracy standard by design) for each fuel flowmeter, according to the 
appropriate calibration procedures using one of the following standard 
methods: ASME MFC-3M-1989 with September 1990 Errata, ``Measurement of 
Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi''; ASME MFC-4M-
1986 (Reaffirmed 1990) ``Measurement of Gas Flow by Turbine Meters''; 
ASME MFC-5M-1985, ``Measurement of Liquid Flow in Closed Conduits Using 
Transit-Time Ultrasonic Flowmeters''; ASME MFC-6M-1987 with June 1987 
Errata, ``Measurement of Fluid Flow in Pipes Using Vortex Flow 
Meters''; ASME MFC-7M-1987 (Reaffirmed 1992), ``Measurement of Gas Flow 
by Means of Critical Flow Venturi Nozzles''; ASME MFC-9M-1988 with 
December 1989 Errata, ``Measurement of Liquid Flow in Closed Conduits 
by Weighing Method''; ISO 8316: 1987(E) ``Measurement of Liquid Flow in 
Closed Conduits--Method by Collection of the Liquid in a Volumetric 
Tank''; Section 8, Calibration from American Gas Association 
Transmission Measurement Committee Report No. 7: Measurement of Gas by 
Turbine Meters (1985 Edition); American Gas Association Report No. 3: 
Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids 
Part 1: General Equations and Uncertainty Guidelines (October 1990 
Edition), Part 2: Specification and Installation Requirements (February 
1991 Edition), and Part 3: Natural Gas Applications (August 1992 
Edition), excluding the modified calculation procedures of Part 3; or 
American Petroleum Institute (API) Section 2, ``Conventional Pipe 
Provers,'' from Chapter 4 of the Manual of Petroleum Measurement 
Standards, October 1988 (Reaffirmed 1993), as required by appendices D 
and E to this part (all methods incorporated by reference under 
Sec. 75.6).
* * * * *
    (2) Initial certification and recertification testing notification. 
The designated representative shall provide initial certification 
testing notification and periodic retesting notification for an 
excepted monitoring system under appendix E to this part as specified 
in Sec. 75.61. The designated representative shall submit 
recertification testing notification, as specified in Sec. 75.61, for 
quality assurance related NOX emission rate testing under 
section 2.3 of appendix E to this part for an excepted monitoring 
system under appendix E to this part. Initial certification testing 
notification or periodic retesting notification is not required for 
testing of a fuel flowmeter or for testing of an excepted monitoring 
system under appendix D to this part.
* * * * *

[[Page 28130]]

    (4) Initial certification or recertification application. The 
designated representative shall submit an initial certification or 
recertification application in accordance with Secs. 75.60 and 75.63.
    (5) Provisional approval of initial certification and 
recertification applications. Upon the successful completion of the 
required initial certification or recertification procedures for each 
excepted monitoring system under appendix D or E to this part, each 
excepted monitoring system under appendix D or E to this part shall be 
deemed provisionally certified for use under the Acid Rain Program 
during the period for the Administrator's review. The provisions for 
the initial certification or recertification application formal 
approval process in paragraph (a)(4) of this section shall apply, 
except that ``continuous emission or opacity monitoring system'' shall 
be replaced with ``excepted monitoring system'' and except that ``shall 
follow the procedures for loss of initial certification in paragraph 
(a)(5)'' or ``shall follow the procedures of paragraph (b)(5)'' shall 
be replaced with ``shall follow the procedures for loss of 
certification in paragraph (g)(7)''. Data measured and recorded by a 
provisionally certified excepted monitoring system under appendix D or 
E to this part will be considered quality assured data from the date 
and time of completion of the last initial certification or 
recertification test, provided that the Administrator does not revoke 
the provisional certification by issuing a notice of disapproval in 
accordance with the provisions in paragraph (a)(4) or (b)(5) of this 
section.
    (6) Recertification requirements. Recertification of an excepted 
monitoring system under appendix D or E to this part is required for 
any modification to the system or change in operation that could 
significantly affect the ability of the system to accurately account 
for emissions and for which the Administrator determines that an 
accuracy test of the fuel flowmeter or a retest under appendix E to 
this part to re-establish the NOX correlation curve is 
required. Examples of such changes or modifications include fuel 
flowmeter replacement, changes in unit configuration, or exceedance of 
operating parameters.
    (7) Procedures for loss of certification or recertification for 
excepted monitoring systems under appendices D and E to this part. In 
the event that a certification or recertification application is 
disapproved for an excepted monitoring system, data from the monitoring 
system are invalidated, and the applicable missing data procedures in 
section 2.4 of appendix D or section 2.5 of appendix E to this part 
shall be used from the date and hour of receipt of such notice back to 
the hour of the provisional certification. Data from the excepted 
monitoring system remain invalid until all required tests are repeated 
and the excepted monitoring system is again provisionally certified. 
The owner or operator shall repeat all certification or recertification 
tests or other requirements, as indicated in the Administrator's notice 
of disapproval, no later than 30 unit operating days after the date of 
issuance of the notice of disapproval. The designated representative 
shall submit a notification of the certification or recertification 
retest dates if required under paragraph (g)(2) of this section and 
shall submit a new certification or recertification application 
according to the procedures in paragraph (g)(4) of this section.
    (h) Initial certification and recertification procedures for low 
mass emission units using the excepted methodologies under Sec. 75.19. 
The owner or operator of a gas-fired, oil-fired, or diesel-fired unit 
using the optional low mass emissions excepted methodologies under 
Sec. 75.19 shall meet the applicable general operating requirements of 
Sec. 75.10, the applicable requirements of Sec. 75.19, and the 
applicable certification requirements of this paragraph (h).
    (1) Monitoring plan. The designated representative shall submit a 
monitoring plan in accordance with Secs. 75.53 and 75.62.
    (2) Certification application. The designated representative shall 
submit a certification application in accordance with 
Sec. 75.63(a)(1)(iii).
    (3) Approval of certification applications. Upon submission of the 
required certification application for approval to use the low mass 
emissions excepted methodology under Sec. 75.19, the excepted 
methodology shall be deemed provisionally certified for use under the 
Acid Rain Program during the period for the Administrator's review. The 
provisions for the certification application formal approval process in 
the introductory text of paragraph (a)(4) and in paragraphs (a)(4)(i), 
(ii), and (iv) of this section shall apply, except that ``continuous 
emission or opacity monitoring system'' shall be replaced with 
``excepted methodology.''
    (4) Disapproval of certification applications. If the Administrator 
determines that the certification application does not demonstrate that 
the unit meets the requirements of Secs. 75.19(a) and (b), the 
Administrator shall issue a written notice of disapproval of the 
certification application within 120 days of receipt. By issuing the 
notice of disapproval, the provisional certification is invalidated by 
the Administrator, and the data recorded under the excepted methodology 
shall not be considered valid. The owner or operator shall follow the 
procedures for loss of certification:
    (i) The owner or operator shall substitute the following values, as 
applicable, for each hour of unit operation during the period of 
invalid data specified in paragraph (a)(4)(iii) of this section or in 
Secs. 75.21(e) (introductory paragraph) and 75.21(e)(1): the maximum 
potential concentration of SO2, as defined in section 2.1 of 
appendix A to this part to report SO2 concentration; the 
maximum potential NOX emission rate, as defined in Sec. 72.2 
of this chapter to report NOX emissions; the maximum 
potential flow rate, as defined in section 2.1 of appendix A to this 
part to report volumetric flow; or the maximum CO2 
concentration used to determine the maximum potential concentration of 
SO2 in section 2.1.1.1 of appendix A to this part to report 
CO2 concentration data until such time, date, and hour as a 
continuous emission monitoring system or excepted monitoring system, 
where applicable, is installed and provisionally certified;
    (ii) The designated representative shall submit a notification of 
certification test dates, as specified in Sec. 75.61(a)(1)(ii), and a 
new certification application according to the procedures in paragraph 
(a)(2) of this section; and
    (iii) The owner or operator shall install and provisionally certify 
continuous emission monitoring systems or excepted monitoring systems, 
where applicable, no later than 180 unit operating days after the date 
of issuance of the notice of disapproval.
    (i) Initial certification and recertification procedures for 
excepted flow monitoring systems under appendix I. The owner or 
operator of a gas-fired unit, oil-fired unit, or diesel-fired unit 
using the optional protocol under appendix I to this part shall ensure 
that an excepted flow monitoring system under appendix I to this part 
meets the applicable general operating requirements of Sec. 75.10, the 
applicable requirements of appendix I to this part, and the initial 
certification and recertification requirements of this paragraph.
    (1) Initial certification and recertification testing. The owner or 
operator shall, where applicable, use the

[[Page 28131]]

following procedures for certification and recertification of an 
excepted flow monitoring system under appendix I to this part.
    (i) For an excepted flow monitoring system under appendix I to this 
part where each component is tested separately, perform the following 
tests on each O2 or CO2 component monitor:
    (A) 7-day calibration error test;
    (B) Linearity check;
    (C) Cycle time test;
    (D) Relative accuracy test audit using Test Method 3A from appendix 
A to part 60 of this chapter; and
    (E) Bias test.
    (ii) For an excepted flow monitoring system under appendix I to 
this part where each component is tested separately, meet the 
certification procedures under paragraph (g)(1)(i) of this section and 
the recertification procedures under paragraph (g)(6) of this section 
on each fuel flowmeter component using the standards specified, or meet 
the testing procedure under section 2.1.5.2 of appendix D to this part.
    (iii) For an excepted flow monitoring system under appendix I to 
this part that is tested as an entire system, perform the following 
tests:
    (A) 7-day calibration error test on the O2 or 
CO2 monitor,
    (B) Linearity check on the O2 or CO2 monitor,
    (C) Cycle time test on the O2 or CO2 monitor,
    (D) Relative accuracy test audit on the entire excepted flow 
monitoring system under appendix I to this part, using Test Method 2 
(or its allowable alternatives) from appendix A to part 60 of this 
chapter, and
    (E) Bias test on the entire excepted flow monitoring system under 
appendix I to this part.
    (iv) For the automated data acquisition and handling system used as 
part of an excepted flow monitoring system under appendix I to this 
part, the owner or operator shall perform tests designed to verify:
    (A) The proper computation of hourly averages for volumetric flow 
rates, heat input, and pollutant mass emissions; and
    (B) The proper computation and application of the missing data 
substitution procedures for volumetric flow in subpart D of this part.
    (2) Initial certification and recertification testing notification. 
The designated representative shall provide initial certification and 
recertification testing notification for an excepted flow monitoring 
system under appendix I to this part, as specified in Sec. 75.61, for 
any relative accuracy test audit.
    (3) Monitoring plan. The designated representative shall submit a 
monitoring plan in accordance with Secs. 75.53 and 75.62. For a unit 
that previously had a flow monitoring system or an excepted monitoring 
system under appendix D to this part and later submits a revised 
monitoring plan for an excepted flow monitoring system under appendix I 
to this part, the designated representative shall submit the revised 
monitoring plan no later than 45 days prior to the first day of 
certification testing.
    (4) Certification or recertification application. The designated 
representative shall submit an initial certification or recertification 
application in accordance with Secs. 75.60 and 75.63.
    (5) Approval of initial certification and recertification 
applications. Upon successful completion of the required initial 
certification or recertification procedures for each excepted 
monitoring system under appendix I to this part, each excepted 
monitoring system under appendix I to this part shall be deemed 
provisionally certified for use under the Acid Rain Program during the 
period for the Administrator's review. The provisions for the initial 
certification (or recertification) application formal approval process 
in paragraph (a)(4) of this section shall apply, except that 
``continuous emission or opacity monitoring system'' shall be replaced 
with ``excepted monitoring system'' and except that ``shall follow the 
procedures for loss of initial certification in paragraph (a)(5)'' or 
``shall follow the procedures of paragraph (b)(5)'' shall be replaced 
with ``shall follow the procedures for loss of certification in 
paragraph (i)(7)''. Data measured and recorded by a provisionally 
certified excepted monitoring system under appendix I to this part will 
be considered quality assured data from the date and time of completion 
of the final certification test, provided that the Administrator does 
not revoke the provisional certification by issuing a notice of 
disapproval within 120 days of receipt of the complete initial 
certification or recertification application in accordance with the 
provisions in paragraph (a)(4) of this section.
    (6) Recertification requirements. A recertification of an excepted 
flow monitoring system under appendix I to this part is required for 
any modification to the equipment used in the appendix I excepted flow 
monitoring system that would require recertification under paragraph 
(b) or (g) of this section.
    (7) Procedures for loss of certification for excepted monitoring 
systems under appendix I to this part. In the event that a 
certification or recertification application is disapproved for an 
excepted monitoring system under appendix I to this part, data from the 
monitoring system are invalidated, and the applicable missing data 
procedures in section 4 of appendix I to this part shall be used from 
the date and hour of receipt of such notice back to the hour of the 
provisional certification. Data from the excepted monitoring system 
remain invalid until all required tests are repeated and the excepted 
monitoring system is again provisionally certified. The owner or 
operator shall repeat all certification or recertification tests or 
other requirements, as indicated in the Administrator's notice of 
disapproval, no later than 30 unit operating days after the date of 
issuance of the notice of disapproval. The designated representative 
shall submit a notification of the certification or recertification 
retest dates, if required under paragraph (i)(2) of this section, and 
shall submit a new certification or recertification application 
according to the procedures in paragraph (i)(4) of this section.
    20. Section 75.21 is amended by:
    a. Revising paragraphs (a)(2), (a)(4), (a)(5), (a)(6) and (e);
    b. Redesignating existing paragraphs (a)(7) and (a)(8) as 
paragraphs (a)(9) and (a)(10), respectively; revising newly designated 
paragraph (a)(9); and
    c. Adding new paragraphs (a)(7), (a)(8), and (f), to read as 
follows:


Sec. 75.21  Quality assurance and quality control requirements.

    (a) * * *
    (2) The owner or operator shall ensure that each non-redundant 
backup continuous emission monitoring system meets the quality 
assurance requirements of Sec. 75.20(d) for each day and quarter that 
the system is used to report data.
* * * * *
    (4) When a unit combusts only natural gas or gaseous fuel with a 
total sulfur content no greater than the total sulfur content of 
natural gas and SO2 emissions are determined in accordance 
with Sec. 75.11(e)(3), the owner or operator of a unit with an 
SO2 continuous emission monitoring system is not required to 
perform the daily or quarterly assessments of the SO2 
monitoring system under appendix B to this part on any day or in any 
calendar quarter in which only natural gas (or gaseous fuel with a 
total sulfur content no greater than the total sulfur content

[[Page 28132]]

of natural gas) is combusted in the unit. Notwithstanding, the results 
of any daily calibration error test and linearity test of the 
SO2 monitoring system performed while the unit is combusting 
only natural gas (or gaseous fuel with a total sulfur content no 
greater than the total sulfur content of natural gas) shall be 
considered valid. If any such test is failed, the SO2 
monitoring system shall be considered to be out-of-control. The length 
of the out-of-control period shall be determined in accordance with the 
applicable procedures in section 2.1.4 or 2.2.3 of appendix B to this 
part.
    (5) For a unit with an SO2 continuous monitoring system, 
in which natural gas (or gaseous fuel with a total sulfur content no 
greater than the total sulfur content of natural gas) is sometimes 
burned as a primary and/or backup fuel and in which higher-sulfur 
fuel(s) such as oil or coal are, at other times, burned as primary or 
backup fuel(s), the owner shall perform the relative accuracy test 
audits of the SO2 monitoring system (as required by section 
6.5 of appendix A to this part and section 2.3.1 of appendix B to this 
part) only when the higher-sulfur fuel is combusted in the unit and 
shall not perform SO2 relative accuracy test audits when 
gaseous fuel is the only fuel being combusted.
    (6) If the designated representative certifies that a unit with an 
SO2 monitoring system burns only fuel(s) with a total sulfur 
content no greater than the total sulfur content of natural gas, the 
SO2 monitoring system is exempted from the relative accuracy 
test audit requirements in appendices A and B to this part. For the 
purposes of this part, a fuel having a total sulfur content no greater 
than 0.05 percent sulfur by weight shall be deemed to qualify as a 
``fuel with a total sulfur content no greater than the total sulfur 
content of natural gas.''
    (7) If the designated representative certifies that a particular 
unit with an SO2 monitoring system combusts fuel(s) with a 
total sulfur content greater than the total sulfur content of natural 
gas (i.e., >0.05 percent sulfur by weight) only as emergency backup 
fuel(s) or for short-term testing, the SO2 monitoring system 
shall be conditionally exempted from the RATA requirements of 
appendices A and B to this part, provided that the unit combusts the 
higher-sulfur fuel(s) for no more than 480 hours per calendar year. If, 
in a particular calendar year, the higher-sulfur fuel usage exceeds 480 
hours, a RATA of the SO2 monitor shall be performed (while 
combusting the higher-sulfur fuel) either by the end of the calendar 
quarter in which the exceedance occurs or by the end of a 720 unit 
operating hour grace period following the quarter in which the 
exceedance occurs (see SO2 RATA provisions in section 2.3.3 
of appendix B to this part for further discussion of the grace period).
    (8) On and after January 1, 2000, the quality assurance provisions 
of Secs. 75.11(e)(3)(i) through 75.11(e)(3)(iv) shall apply (except 
that the term ``gaseous fuel'' shall be replaced with ``fuel'') to all 
units with SO2 monitoring systems during hours in which only 
fuel having a total sulfur content no greater than the total sulfur 
content of natural gas (i.e., 0.05 percent sulfur by weight) 
is combusted in the unit, except for units that use such fuel only for 
unit startup.
    (9) Provided that a unit with an SO2 monitoring system 
is not exempted under paragraph (a)(6) or (a)(7) of this section from 
the SO2 RATA requirements of this part, any calendar quarter 
during which a unit combusts only fuel(s) with a total sulfur content 
no greater than the total sulfur content of natural gas (i.e. 
0.05 percent sulfur by weight) shall be excluded in 
determining the quarter in which the next relative accuracy test audit 
must be performed for the SO2 monitoring system. However, no 
more than eight successive calendar quarters shall elapse after a 
relative accuracy test audit of an SO2 monitoring system, 
without a subsequent relative accuracy test audit having been 
performed. The owner or operator shall ensure that a relative accuracy 
test audit is performed either by the end of the eighth successive 
elapsed calendar quarter since the last RATA or in the next calendar 
quarter in which a fuel with a total sulfur content greater than the 
total sulfur content of natural gas is burned in the unit.
* * * * *
    (e) Consequences of audits. The owner or operator shall invalidate 
data from a continuous emission monitoring system or continuous opacity 
monitoring system upon failure of an audit under paragraph (a)(4)(iv) 
of Sec. 75.20, an audit under appendix B to this part, or any other 
audit, beginning with the unit operating hour of completion of a failed 
audit as determined by the Administrator. The owner or operator shall 
not use invalidated data for reporting either emissions or heat input, 
nor for calculating monitor data availability.
    (1) Audit decertification. Whenever both an audit of a continuous 
emission or opacity monitoring system (or component thereof, including 
the data acquisition and handling system), or an audit of any excepted 
monitoring system under appendix D, E, or I to this part, or of any 
alternative monitoring system under subpart E of this part, and a 
review of the initial certification application or of a recertification 
application, reveal that any system or component should not have been 
certified or recertified because it did not meet a particular 
performance specification or other requirement of this part, both at 
the time of the initial certification or recertification application 
submission and at the time of the audit, the Administrator will issue a 
notice of disapproval of the certification status of such system or 
component. For the purposes of this paragraph, an audit shall be either 
a field audit of the facility or an audit of any information submitted 
to EPA or the State agency regarding the facility. By issuing the 
notice of disapproval, the certification status is revoked, 
prospectively, by the Administrator. The data measured and recorded by 
each system shall not be considered valid quality-assured data from the 
date of issuance of the notification of the revoked certification 
status until the date and time that the owner or operator completes 
subsequently approved initial certification or recertification tests. 
The owner or operator shall follow the procedures in Sec. 75.20(a)(5) 
for initial certification or Sec. 75.20(b)(5) for recertification to 
replace, prospectively, all of the invalid, non-quality-assured data 
for each disapproved system.
    (2) Out-of-control period. Whenever a continuous emission 
monitoring system or continuous opacity monitoring system fails a 
quality assurance audit, an audit under Sec. 75.20(a)(4)(iv), or 
another audit, the system is out-of-control. The owner or operator 
shall follow the procedures for out-of-control periods in Sec. 75.24.
    (f) Excepted flow monitoring systems under appendix I. The owner or 
operator of an affected unit shall operate, calibrate, and maintain 
each excepted flow monitoring system under appendix I to this part used 
under the Acid Rain Program according to the quality assurance and 
quality control procedures in appendices B and I to this part.
    21. Section 75.22 is amended by revising paragraphs (a)(2), (a)(4), 
and (c)(1) introductory text to read as follows:


Sec. 75.22  Reference test methods.

    (a) * * *
    (2) Method 2 or its allowable alternatives, except for 2B and 2E, 
are the reference methods for determination of volumetric flow.
* * * * *

[[Page 28133]]

    (4) Method 4 (either the standard procedure described in section 2 
of the method or the moisture approximation procedure described in 
section 3 of the method) shall be used to correct pollutant 
concentrations from a dry basis to a wet basis (or from a wet basis to 
a dry basis) and shall be used when relative accuracy test audits of 
continuous moisture monitoring systems are conducted. For the purpose 
of determining the stack gas molecular weight, however, the alternative 
techniques for approximating the stack gas moisture content described 
in section 1.2 of Method 4 may be used in lieu of the procedures in 
sections 2 and 3 of the method.
* * * * *
    (c) * * *
    (1) Instrumental EPA Reference Methods 3A, 6C, 7E, and 20 shall be 
conducted using calibration gases as defined in section 5 of appendix A 
to this part. Otherwise, performance tests shall be conducted and data 
reduced in accordance with the test methods and procedures of this part 
unless the Administrator:
* * * * *
    22. Section 75.24 is amended by revising paragraph (d) to read as 
follows:


Sec. 75.24  Out-of-control periods.

* * * * *
    (d) When the bias test indicates that an SO2 monitor, 
volumetric flow monitor, or NOX continuous emission 
monitoring system is biased low (i.e., the arithmetic mean of the 
differences between the reference method value and the monitor or 
monitoring system measurements in a relative accuracy test audit exceed 
the bias statistic in section 7 of appendix A to this part), the owner 
or operator shall adjust the monitor or continuous emission monitoring 
system to eliminate the cause of bias such that it passes the bias test 
or calculate and use the bias adjustment factor as specified in section 
2.3.4 of appendix B to this part and in accordance with Sec. 75.7.
* * * * *
    23. Section 75.30 is amended by revising paragraphs (a)(2) and (d) 
to read as follows:


Sec. 75.30  General provisions.

    (a) * * *
    (2) A valid quality assured hour of flow data (in scfh) has not 
been measured and recorded for an affected unit from a certified flow 
monitor, or from a certified excepted flow monitoring system under 
appendix I to this part, or by an approved alternative monitoring 
system under subpart E of this part; or
* * * * *
    (d) The owner or operator shall comply with the applicable 
provisions of this paragraph during hours in which a unit with an 
SO2 continuous emission monitoring system combusts only 
natural gas or gaseous fuel with a total sulfur content no greater than 
the total sulfur content of natural gas.
    (1) Whenever a unit with an SO2 continuous emission 
monitoring system combusts only pipeline natural gas and the owner or 
operator is using the procedures in section 7 of appendix F to this 
part to determine SO2 mass emissions pursuant to 
Sec. 75.11(e)(1), the owner or operator shall, for purposes of 
reporting heat input data under Sec. 75.54(b)(5) or Sec. 75.57(b)(5), 
as applicable, and for the calculation of SO2 mass emissions 
using Equation F-23 in section 7 of appendix F to this part, substitute 
for missing data from a flow monitoring system, CO2-diluent 
monitor or O2-diluent monitor using the missing data 
substitution procedures in Sec. 75.36.
    (2) Whenever a unit with an SO2 continuous emission 
monitoring system combusts gaseous fuel with a total sulfur content no 
greater than the total sulfur content of natural gas (i.e., 
20 gr/100 scf) and the owner or operator uses the gas 
sampling and analysis and fuel flow procedures in appendix D to this 
part to determine SO2 mass emissions pursuant to 
Sec. 75.11(e)(2), the owner or operator shall substitute for missing 
total sulfur content, gross calorific value, and fuel flowmeter data 
using the missing data procedures in appendix D to this part and shall 
also, for purposes of reporting heat input data under Sec. 75.54(b)(5) 
or Sec. 75.57(b)(5), substitute for missing data from a flow monitoring 
system, CO2-diluent monitor, or O2-diluent 
monitor using the missing data substitution procedures in Sec. 75.36.
    (3) The owner or operator of a unit with an SO2 
monitoring system shall not include hours, when the unit combusts only 
natural gas (or a gaseous fuel with total sulfur content no greater 
than the total sulfur content of natural gas), in the SO2 
data availability calculations in Sec. 75.32 or in the calculations of 
substitute SO2 data using the procedures of either 
Sec. 75.31 or Sec. 75.33, when SO2 emissions are determined 
in accordance with Sec. 75.11(e)(1) or (e)(2). For the purpose of the 
missing data and availability procedures for SO2 pollutant 
concentration monitors in Secs. 75.31 and 75.33 only, all hours during 
which the unit combusts only natural gas, or gaseous fuel with a total 
sulfur content no greater than the total sulfur content of natural gas, 
shall be excluded from the definition of ``monitor operating hour,'' 
``quality assured monitor operating hour,'' ``unit operating hour,'' 
and ``unit operating day,'' when SO2 emissions are 
determined in accordance with Sec. 75.11(e)(1) or (e)(2).
    (4) During all hours in which a unit with an SO2 
continuous emission monitoring system combusts only natural gas (or 
gaseous fuel with a total sulfur content no greater than the total 
sulfur content of natural gas) and the owner or operator uses the 
SO2 monitoring system to determine SO2 mass 
emissions pursuant to Sec. 75.11(e)(3), the owner or operator shall 
determine the percent monitor data availability for SO2 in 
accordance with Sec. 75.32 and shall use the standard SO2 
missing data procedures of Sec. 75.33.
    24. Section 75.32 is amended by revising the last sentence in 
paragraph (a)(3) to read as follows:


Sec. 75.32  Determination of monitor data availability for standard 
missing data procedures.

    (a) * * *
    (3) * * * The owner or operator of a unit with an SO2 
monitoring system shall, when SO2 emissions are determined 
in accordance with Sec. 75.11(e)(1) or (e)(2), exclude hours in which a 
unit combusts only natural gas (or gaseous fuel with a total sulfur 
content no greater than the total sulfur content of natural gas) from 
calculations of percent monitor data availability for SO2 
pollutant concentration monitors, as provided in Sec. 75.30(d).
* * * * *
    25. Section 75.33 is amended by adding a new paragraph (d) to read 
as follows:


Sec. 75.33  Standard missing data procedures.

* * * * *
    (d) On and after January 1, 2000, failure to maintain a monitor 
data availability, as calculated pursuant to Sec. 75.32, of at least 
80.0 percent for SO2, NOX, flow rate, or 
CO2 shall be considered a violation of the primary 
measurement requirement of Sec. 75.10(a). This paragraph (d) shall not 
apply: if, for a particular unit or stack for which the monitor data 
availability drops below 80.0 percent, less than 3,000 unit operating 
hours have been accumulated in the previous 12 calendar quarters; or if 
a data availability percentage of less than 80.0 percent results from a 
sudden and reasonably unforeseeable event beyond the control of the 
owner or operator, such as catastrophic monitor failure or destruction 
of monitoring equipment by fire, flood, etc. If such

[[Page 28134]]

circumstances have caused (or are projected to cause) the monitor data 
availability to drop below 80.0 percent, the owner or operator shall 
notify the Administrator, in writing, within 7 days of the event(s). 
Notification, in writing, shall also be provided to the EPA Regional 
Office and to the appropriate State agency. The written notifications 
shall fully explain the circumstances that have caused (or may cause) 
the low monitor data availability and shall contain an action plan and 
a projected time schedule for correction of the problem. Failures that 
are caused in part by poor maintenance or careless operation shall not, 
for the purposes of this paragraph, be considered reasonably 
unforeseeable events beyond the control of the owner or operator.
    26. Section 75.34 is amended by revising paragraph (a)(3) to read 
as follows:


Sec. 75.34  Units with add-on emission controls.

    (a) * * *
    (3) The designated representative may petition the Administrator 
under Sec. 75.66 for approval of site-specific parametric monitoring 
procedure(s) for calculating substitute data for missing SO2 
pollutant concentration and NOX emission rate data in 
accordance with the requirements of paragraphs (b) and (c) of this 
section and appendix C to this part. The owner or operator shall record 
the data required in appendix C to this part, pursuant to Sec. 75.55(b) 
or Sec. 75.58(b), as applicable.
* * * * *
    27. Section 75.35 is amended by revising paragraphs (a) and (c) to 
read as follows:


Sec. 75.35  Missing data procedures for CO2 data.

    (a) On and after January 1, 2000, the owner or operator of a unit 
with a CO2 continuous emission monitoring system (or an 
O2-diluent monitor that is used to determine CO2 
concentration in accordance with appendix F to this part) shall 
substitute for missing CO2 concentration data using the 
procedures of this section. Prior to January 1, 2000, the owner or 
operator may substitute for missing CO2 or O2 
concentration data using the procedures of this section.
* * * * *
    (c) Upon completion of the first 720 quality assured monitor 
operating hours following initial certification of the CO2 
continuous emission monitoring system, the owner or operator shall 
provide substitute data for CO2 concentration or 
CO2 mass emissions required under this subpart, including 
CO2 data calculated from O2 measurements using 
the procedures in appendix F to this part, in accordance with the 
procedures in Sec. 75.33(b), except that the terms ``SO2 
concentration'' and ``SO2 pollutant concentration monitor'' 
shall be replaced, respectively, with ``CO2 concentration'' 
and ``CO2 pollutant concentration monitor.''
    28. Section 75.36 is amended by revising paragraphs (a), (b), and 
(c) to read as follows:


Sec. 75.36  Missing data procedures for heat input.

    (a) When hourly heat input is determined using a flow monitoring 
system and a diluent gas (O2 or CO2) monitor, 
substitute data must be provided to calculate the heat input whenever 
quality assured data are unavailable from the flow monitor, the diluent 
gas monitor, or both. When flow rate data are unavailable, substitute 
flow rate data for the heat input calculation shall be provided 
according to Sec. 75.31 or Sec. 75.33, as applicable. On and after 
January 1, 2000, when diluent gas data are unavailable, the owner or 
operator shall provide substitute O2 or CO2 data 
for the heat input calculations in accordance with this section. Prior 
to January 1, 2000, the owner or operator may substitute for missing 
CO2 or O2 concentration data using the procedures 
in this section.
    (b) During the first 720 quality assured monitor operating hours 
following initial certification (i.e., following the date and time of 
completion of successful certification tests of the CO2 or 
O2 monitor), the owner or operator shall provide substitute 
CO2 or O2 data, as applicable, for the 
calculation of heat input (under section 5.2 of appendix F to this 
part) according to Sec. 75.31(b).
    (c) Upon completion of the first 720 quality assured monitor 
operating hours following initial certification of the CO2 
(or O2) monitor, the owner or operator shall provide 
substitute data for CO2 or O2 concentration to 
calculate heat input according to the procedures in Sec. 75.33(b), 
except that the term ``SO2 concentration'' shall be replaced 
with ``CO2 concentration'' or ``O2 
concentration'' (as applicable) and the term ``SO2 pollutant 
concentration monitor'' shall be replaced with ``CO2-diluent 
monitor'' or ``O2-diluent monitor'' (as applicable).
* * * * *
    29. Section 75.37 is added to subpart D to read as follows:


Sec. 75.37  Missing data procedures for moisture.

    The owner or operator shall substitute for missing moisture data 
(beginning no later than January 1, 2000 or the date and hour on which 
the unit or stack is required to begin reporting under Sec. 75.64, 
whichever date is earlier) as follows:
    (a) Where no prior quality assured percent moisture data exist, 
substitute 0.0 percent moisture for each unit operating hour;
    (b) For the first 720 quality assured monitor operating hours, 
substitute for each hour of the missing data period the average of the 
percent moisture values obtained during the hour before and the hour 
after the missing data period;
    (c) Once 720 quality assured monitor operating hours have been 
obtained, begin calculating the percent data availability of the 
moisture monitoring system, in accordance with Sec. 75.32;
    (d) When the percent data availability, as of the last hour in the 
missing data period, is 90.0 percent, substitute for each 
hour of the missing data period the average of the percent moisture 
values obtained during the hour before and the hour after the missing 
data period;
    (e) If the percent data availability of the moisture monitor is < 
90.0 percent as of the last hour in the missing data period, substitute 
0.0 percent moisture for each hour of the missing data period.

Subpart E--[Amended]

    30. Section 75.48 is amended by revising paragraphs (a)(3)(ii) and 
(a) (3)(iii) to read as follows:


Sec. 75.48  Petition for an alternative monitoring system.

    (a) * * *
    (3) * * *
    (ii) Hourly test data for the alternative monitoring system at each 
required operating level and fuel type. The fuel type, operating level 
and gross unit load shall be recorded.
    (iii) Hourly test data for the continuous emissions monitoring 
system at each required operating level and fuel type. The fuel type, 
operating level and gross unit load shall be recorded.
* * * * *
    31. Section 75.50 is removed and reserved.


Sec. 75.50  [Removed and Reserved]

    32. Section 75.51 is removed and reserved.


Sec. 75.51  [Removed and Reserved]

    33. Section 75.52 is removed and reserved.


Sec. 75.52  [Removed and Reserved]

    34. Section 75.53 is amended by revising paragraphs (a) and (b) and 
adding paragraphs (e) through (f) to read as follows:

[[Page 28135]]

Sec. 75.53  Monitoring plan.

    (a) General Provisions.
    (1) Compliance dates. Beginning on January 1, 2000, the owner or 
operator shall comply with the provisions in paragraphs (a), (b), (e) 
and (f) of this section only. Before January 1, 2000, the owner or 
operator shall comply with either paragraphs (a) through (d) or 
paragraphs (a), (b), (c), and (f) of this section, except that the 
owner or operator shall comply with provisions in paragraphs (e) and 
(f) of this section only before January 1, 2000, when those provisions 
support a regulatory option provided in another section of this part 75 
and the regulatory option is exercised before January 1, 2000.
    (2) The owner or operator of an affected unit shall prepare and 
maintain a monitoring plan. Except as provided in paragraphs (d) (or 
(f), as applicable) of this section, a monitoring plan shall contain 
sufficient information on the continuous emission or opacity monitoring 
systems, excepted methodology under Sec. 75.19, or excepted monitoring 
systems under appendix D or E to this part and the use of data derived 
from these systems to demonstrate that all unit SO2 
emissions, NOX emissions, CO2 emissions, and 
opacity are monitored and reported.
    (b) Whenever the owner or operator makes a replacement, 
modification, or change in the certified continuous emission monitoring 
system, continuous opacity monitoring system, excepted methodology 
under Sec. 75.19, excepted monitoring system under appendix D, E, or I 
to this part, or alternative monitoring system under subpart E of this 
part, including a change in the automated data acquisition and handling 
system or in the flue gas handling system, that affects information 
reported in the monitoring plan (e.g., a change to a serial number for 
a component of a monitoring system), then the owner or operator shall 
update the monitoring plan.
* * * * *
    (e) Contents of the monitoring plan. Each monitoring plan shall 
contain the information in paragraph (e)(1) of this section in 
electronic format and the information in paragraph (e)(2) of this 
section in hardcopy format.
    (1) Electronic. (i) ORISPL numbers developed by the Department of 
Energy and used in the National Allowance Database, for all affected 
units involved in the monitoring plan, with the following information 
for each unit:
    (A) Short name;
    (B) Classification of unit as one of the following: Phase I 
(including substitution or compensating units), Phase II, new, or 
nonaffected;
    (C) Type of boiler (or boilers for a group of units using a common 
stack);
    (D) Type of fuel(s) fired by boiler, fuel type start and end date, 
primary/secondary fuel indicator, and, if more than one fuel, the fuel 
classification of the boiler;
    (E) Type(s) of emission controls for SO2, 
NOX, and particulates installed or to be installed, 
including specifications of whether such controls are pre-combustion, 
post-combustion, or integral to the combustion process; control 
equipment code, installation date, and optimization date; control 
equipment retirement date (if applicable); and, an indicator for 
whether the controls are an original installation;
    (F) Maximum hourly heat input capacity;
    (G) Date of first commercial operation;
    (H) Unit retirement date (if applicable);
    (I) Maximum hourly gross load (in MW, rounded to the nearest MW, or 
steam load in 1000 lb/hr, rounded to the nearest 100 lb/hr);
    (J) Identification of all units using a common stack;
    (K) Activation date for the stack/pipe;
    (L) Retirement date of the stack/pipe (if applicable); and
    (M) Indicator of whether the stack is a bypass stack.
    (ii) For each unit and parameter required to be monitored, 
identification of monitoring methodology information, consisting of 
monitoring methodology, type of fuel associated with the methodology, 
missing data approach for the methodology, methodology start date, and 
methodology end date (if applicable).
    (iii) The following information:
    (A) Program(s) for which the EDR is submitted;
    (B) Unit classification;
    (C) Reporting frequency;
    (D) Program participation date;
    (E) State regulation code (if applicable); and
    (F) State or local regulatory agency code.
    (iv) Identification and description of each monitoring component 
(including each monitor and its identifiable components, such as 
analyzer and/or probe) in the continuous emission monitoring systems 
(i.e., SO2 pollutant concentration monitor, flow monitor, 
moisture monitor; NOX pollutant concentration monitor and 
diluent gas monitor), the continuous opacity monitoring system, or 
excepted monitoring system (i.e., fuel flowmeter, data acquisition and 
handling system), including:
    (A) Manufacturer, model number and serial number;
    (B) Component/system identification code assigned by the utility to 
each identifiable monitoring component (such as the analyzer and/or 
probe). Each code shall use a three-digit format, unique to each 
monitoring component and unique to each monitoring system;
    (C) Designation of the component type or method of operation, such 
as in situ pollutant concentration monitor or thermal flow monitor;
    (D) Designation of the system as a primary, redundant backup, non-
redundant backup, like kind non-redundant backup, data backup, or 
reference method backup system, as provided in Sec. 75.10(e);
    (E) First and last dates the system reported data; and
    (F) Status of the monitoring component.
    (v) Identification and description of all major hardware and 
software components of the automated data acquisition and handling 
system, including:
    (A) For hardware components, the manufacturer and model number; and
    (B) For software components, identification of the provider and 
model/version number.
    (vi) Explicit formulas for each measured emission parameter, using 
component/system identification codes for the primary system used to 
measure the parameter to link continuous emission monitoring system or 
excepted monitoring system observations with reported concentrations, 
mass emissions, or emission rates, according to the conversions listed 
in appendix D, E, or F to this part. Formulas for backup monitoring 
systems are required only if different formulas for the same parameter 
are used for the primary and backup monitoring systems (e.g., if the 
primary system measures pollutant concentration on a different moisture 
basis from the backup system). The formulas must contain all constants 
and factors required to derive mass emissions or emission rates from 
component/system code observations and an indication of whether the 
formula is being added, corrected, deleted, or is unchanged. Each 
emissions formula is identified with a unique three digit code. The 
owner or operator of a low mass emissions unit for which the owner or 
operator is using the optional low mass emissions excepted methodology 
in Sec. 75.19(c) is not required to report such formulas.
    (vii) Inside cross-sectional area (ft2) at flue exit 
(for all units) and at flow monitoring location (for units with flow 
monitors, only).

[[Page 28136]]

    (viii) Stack height (ft) above ground level and stack base 
elevation above sea level.
    (ix) Flue identification number, as reported to the Energy 
Information Administration (EIA).
    (x) For each parameter monitored: scale, maximum potential 
concentration (and method of calculation), maximum expected 
concentration (if applicable) (and method of calculation), maximum 
potential flow rate (and method of calculation), maximum potential 
NOX emission rate, span value, full-scale range, daily 
calibration units of measure, span effective date/hour, span 
inactivation date/hour, indication of whether dual spans are required, 
default high range value, flow rate span, and flow rate span value and 
full scale value (in scfh) for each unit or stack using SO2, 
NOX, CO2, O2, or flow component 
monitors.
    (xi) If the monitoring system or excepted methodology provides for 
the use of a constant, assumed, or default value for a parameter under 
specific circumstances, then include the following information for each 
such value for each parameter:
    (A) Identification of the parameter;
    (B) Default, maximum, minimum, or constant value, and units of 
measure for the value;
    (C) Purpose of the value;
    (D) Indicator of use during controlled/uncontrolled hours;
    (E) Type of fuel;
    (F) Source of the value;
    (G) Value effective date and hour;
    (H) Date and hour value is no longer effective (if applicable); and
    (I) For units using the excepted methodology under Sec. 75.19, the 
applicable SO2 emission factor.
    (2) Hardcopy. (i) Information, including (as applicable) 
identification of the test strategy; protocol for the relative accuracy 
test audit; other relevant test information; calibration gas levels 
(percent of span) for the calibration error test and linearity check; 
calculations for determining maximum potential concentration, maximum 
expected concentration (if applicable), maximum potential flow rate, 
maximum potential NOX emission rate, and span; and 
apportionment strategies under Secs. 75.13 through 75.17.
    (ii) Description of site locations for each monitoring component in 
the continuous emission or opacity monitoring systems, including 
schematic diagrams and engineering drawings specified in paragraphs 
(e)(2)(iv) and (e)(2)(v) of this section and any other documentation 
that demonstrates each monitor location meets the appropriate siting 
criteria.
    (iii) A data flow diagram denoting the complete information 
handling path from output signals of continuous emission monitoring 
system components to final reports.
    (iv) For units monitored by a continuous emission or opacity 
monitoring system, a schematic diagram identifying entire gas handling 
system from boiler to stack for all affected units, using 
identification numbers for units, monitor components, and stacks 
corresponding to the identification numbers provided in paragraphs 
(e)(1)(i), (e)(1)(ii), (e)(1)(vi), and (e)(1)(vii) of this section. The 
schematic diagram must depict stack height and the height of any 
monitor locations. Comprehensive and/or separate schematic diagrams 
shall be used to describe groups of units using a common stack.
    (v) For units monitored by a continuous emission or opacity 
monitoring system, stack and duct engineering diagrams showing the 
dimensions and location of fans, turning vanes, air preheaters, monitor 
components, probes, reference method sampling ports, and other 
equipment that affects the monitoring system location, performance, or 
quality control checks.
    (f) Contents of monitoring plan for specific situations. The 
following additional information shall be included in the monitoring 
plan for the specific situations described:
    (1) For each gas-fired unit or oil-fired unit for which the owner 
or operator uses the optional protocol in appendix D to this part for 
estimating heat input and/or SO2 mass emissions or in 
appendix I to this part for estimating stack flow rate, or for each 
gas-fired or oil-fired peaking unit for which the owner/operator uses 
the optional protocol in appendix E to this part for estimating 
NOX emission rate (using a fuel flowmeter), the designated 
representative shall include the following additional information in 
the monitoring plan:
    (i) Electronic. (A) Parameter monitored;
    (B) Type of fuel measured, maximum fuel flow rate, units of 
measure, and basis of maximum fuel flow rate (i.e., upper range value 
or unit maximum) for each fuel flowmeter;
    (C) Test method used to check the accuracy of each fuel flowmeter;
    (D) Submission status of the data; and
    (E) Monitoring system identification code.
    (ii) Hardcopy. (A) A schematic diagram identifying the relationship 
between the unit, all fuel supply lines, the fuel flowmeter(s), and the 
stack(s). The schematic diagram must depict the installation location 
of each fuel flowmeter and the fuel sampling location(s). Comprehensive 
and/or separate schematic diagrams shall be used to describe groups of 
units using a common pipe.
    (B) For units using the optional protocol for gaseous fuel in 
appendix D to this part, historical fuel sampling information on the 
sulfur content of the gaseous fuel according to section 2.3.3 of 
appendix D to this part.
    (2) For each gas-fired peaking unit and oil-fired peaking unit for 
which the owner or operator uses the optional procedures in appendix E 
to this part for estimating NOX emission rate, the 
designated representative shall include in the monitoring plan:
    (i) Electronic. Unit operating and capacity factor information 
demonstrating that the unit qualifies as a peaking unit or gas-fired 
unit, as defined in Sec. 72.2 of this chapter.
    (ii) Hardcopy. (A) A protocol containing methods used to perform 
the baseline or periodic NOX emission test; and
    (B) Unit operating parameters related to NOX formation 
by the unit.
    (3) For each gas-fired unit and diesel-fired unit or unit with a 
wet flue gas pollution control system for which the designated 
representative claims an opacity monitoring exemption under Sec. 75.14, 
the designated representative shall include in the hardcopy monitoring 
plan the information specified under Sec. 75.14(b), (c), or (d), 
demonstrating that the unit qualifies for the exemption.
    (4) For each monitoring system recertification, maintenance, or 
other event, the designated representative shall include the following 
additional information in electronic format in the monitoring plan:
    (i) Component/system identification code;
    (ii) Event code or code for required test;
    (iii) Event begin date and hour;
    (iv) Conditional data period begin date and hour (if applicable);
    (v) Date and hour that last test is successfully completed; and
    (vi) Indicator of whether conditionally valid data were reported at 
the end of the quarter.
    35. Section 75.54 is amended by adding new paragraphs (g) and (h) 
to read as follows:


Sec. 75.54  General recordkeeping provisions.

* * * * *
    (g) Missing data records. The owner or operator shall record the 
causes of any missing data periods and the actions

[[Page 28137]]

taken by the owner or operator to cure such causes.
    (h) Compliance dates. On January 1, 2000, the provisions of this 
section are no longer applicable. Before January 1, 2000, the owner or 
operator shall comply with either this section or Sec. 75.57. Beginning 
on January 1, 2000, the owner or operator shall comply with Sec. 75.57 
only.
    36. Section 75.55 is amended by adding a new paragraph (g) to read 
as follows:


Sec. 75.55  General recordkeeping provisions for specific situations.

* * * * *
    (g) Compliance dates. On January 1, 2000, the provisions of this 
section are no longer applicable. Before January 1, 2000, the owner or 
operator shall comply with either this section or Sec. 75.58. Beginning 
on January 1, 2000, the owner or operator shall comply with Sec. 75.58 
only.
    37. Section 75.56 is amended by adding new paragraphs (a)(5)(vii) 
and (e) to read as follows:


Sec. 75.56  Certification, quality assurance, and quality control 
record provisions.

    (a) * * *
    (5) * * *
    (vii) For flow monitors, the flow polynomial equation used to 
linearize the flow monitor and the numerical values of the polynomial 
coefficients of that equation.
* * * * *
    (e) Compliance dates. On January 1, 2000, the provisions of this 
section are no longer applicable. Before January 1, 2000, the owner or 
operator shall comply with either this section or Sec. 75.59. Beginning 
on January 1, 2000, the owner or operator shall comply with Sec. 75.59 
only.
    38. Section 75.57 is added to Subpart F to read as follows:


Sec. 75.57  General recordkeeping provisions.

    (a) Recordkeeping requirements for affected sources. The owner or 
operator of any affected source subject to the requirements of this 
part shall maintain for each affected unit a file of all measurements, 
data, reports, and other information required by this part at the 
source in a form suitable for inspection for at least three (3) years 
from the date of each record. Unless otherwise provided, throughout 
this subpart the phrase ``for each affected unit'' also applies to each 
group of affected or nonaffected units utilizing a common stack and 
common monitoring systems, pursuant to Secs. 75.13 through 75.18, or 
utilizing a common pipe header and common fuel flowmeter, pursuant to 
section 2.1.2 of appendix D to this part. The file shall contain the 
following information:
    (1) The data and information required in paragraphs (b) through (f) 
of this section, beginning with the earlier of the date of provisional 
certification or the deadline in Sec. 75.4(a), (b), or (c);
    (2) The supporting data and information used to calculate values 
required in paragraphs (b) through (f) of this section, excluding the 
subhourly data points used to compute hourly averages under 
Sec. 75.10(d), beginning with the earlier of the date of provisional 
certification or the deadline in Sec. 75.4(a), (b), or (c);
    (3) The data and information required in Sec. 75.55 or Sec. 75.58 
for specific situations, as applicable, beginning with the earlier of 
the date of provisional certification or the deadline in Sec. 75.4(a), 
(b), or (c);
    (4) The certification test data and information required in 
Sec. 75.56 or Sec. 75.59 for tests required under Sec. 75.20, beginning 
with the date of the first certification test performed; the quality 
assurance and quality control data and information required in 
Sec. 75.56 or Sec. 75.59 for tests; and the quality assurance/quality 
control plan required under Sec. 75.21 and appendix B to this part, 
beginning with the date of provisional certification;
    (5) The current monitoring plan as specified in Sec. 75.53, 
beginning with the initial submission required by Sec. 75.62; and
    (6) The quality control plan as described in section 1 of appendix 
B to this part, beginning with the date of provisional certification.
    (b) Operating parameter record provisions. The owner or operator 
shall record for each hour the following information on unit operating 
time, heat input rate, and load, separately for each affected unit and 
also for each group of units utilizing a common stack and a common 
monitoring system or utilizing a common pipe header and common fuel 
flowmeter.
    (1) Date and hour;
    (2) Unit operating time (rounded up to the nearest fraction of an 
hour (in equal increments that can range from one hundredth to one 
quarter of an hour, at the option of the owner or operator));
    (3) Hourly gross unit load (rounded to nearest MWge) (or steam load 
in 1000 lb/hr at stated temperature and pressure, rounded to the 
nearest 1000 lb/hr, if elected in the monitoring plan);
    (4) Operating load range corresponding to hourly gross load of 1 to 
10, except for units using a common stack or common pipe header, which 
may use up to 20 load ranges for stack or fuel flow, as specified in 
the monitoring plan;
    (5) Hourly heat input rate (mmBtu/hr, rounded to the nearest 
tenth);
    (6) Identification code for formula used for heat input, as 
provided in Sec. 75.53; and
    (7) For CEMS units only:
    (i) F-factor for heat input calculation; and
    (ii) Indication of whether the diluent cap was used for heat input 
calculations for the hour.
    (c) SO2 emission record provisions. The owner or 
operator shall record for each hour the information required by this 
paragraph for each affected unit or group of units using a common stack 
and common monitoring systems, except as provided under Sec. 75.11(e) 
or for a gas-fired or oil-fired unit for which the owner or operator is 
using the optional protocol in appendix D to this part or for a low 
mass emissions unit for which the owner or operator is using the 
optional low mass emissions methodology in Sec. 75.19(c) for estimating 
SO2 mass emissions:
    (1) For SO2 concentration during unit operation, as 
measured and reported from each certified primary monitor, certified 
back-up monitor, or other approved method of emissions determination:
    (i) Component-system identification code, as provided in 
Sec. 75.53;
    (ii) Date and hour;
    (iii) Hourly average SO2 concentration (ppm, rounded to 
the nearest tenth);
    (iv) Hourly average SO2 concentration (ppm, rounded to 
the nearest tenth), adjusted for bias if bias adjustment factor is 
required, as provided in Sec. 75.24(d);
    (v) Percent monitor data availability (recorded to the nearest 
tenth of a percent), calculated pursuant to Sec. 75.32; and
    (vi) Method of determination for hourly average SO2 
concentration using Codes 1-55 in Table 4a of this section.
    (2) For flow rate during unit operation, as measured and reported 
from each certified primary monitor, certified back-up monitor, or 
other approved method of emissions determination:
    (i) Component system identification code, as provided in Sec. 75.53 
(including the separate identification code for the moisture monitoring 
system, if applicable);
    (ii) Date and hour;
    (iii) Hourly average volumetric flow rate (in scfh, rounded to the 
nearest thousand);
    (iv) Hourly average volumetric flow rate (in scfh, rounded to the 
nearest thousand), adjusted for bias if bias

[[Page 28138]]

adjustment factor required, as provided in Sec. 75.24(d);
    (v) Hourly average moisture content of flue gas (percent, rounded 
to the nearest tenth), where SO2 concentration is measured 
on a dry basis. If the continuous moisture monitoring system consists 
of wet- and dry-basis oxygen analyzers, record both the wet- and dry-
basis oxygen hourly averages (in percent O2, rounded to the 
nearest tenth);
    (vi) Percent monitor data availability (recorded to the nearest 
tenth of a percent), for the flow monitor, and, if applicable, 
separately for the moisture monitoring system, calculated pursuant to 
Sec. 75.32; and
    (vii) Method of determination for hourly average flow rate using 
Codes 1-55 in Table 4a of this section.
    (3) For SO2 mass emission rate during unit operation, as 
measured and reported from the certified primary monitoring system(s), 
certified redundant or non-redundant back-up monitoring system(s), or 
other approved method(s) of emissions determination:
    (i) Date and hour;
    (ii) Hourly SO2 mass emission rate (lb/hr, rounded to 
the nearest tenth);
    (iii) Hourly SO2 mass emission rate (lb/hr, rounded to 
the nearest tenth), adjusted for bias if bias adjustment factor 
required, as provided in Sec. 75.24(d); and
    (iv) Identification code for emissions formula used to derive 
hourly SO2 mass emission rate from SO2 
concentration and flow data in paragraphs (c)(1) and (c)(2) of this 
section, as provided in Sec. 75.53.

     Table 4a.--Codes for Method of Emissions and Flow Determination    
------------------------------------------------------------------------
                        Hourly emissions/flow measurement or estimation 
         Code                                method                     
------------------------------------------------------------------------
1....................  Certified primary emission/flow monitoring       
                        system.                                         
2....................  Certified backup emission/flow monitoring system.
3....................  Approved alternative monitoring system.          
4....................  Reference method: SO2: Method 6C. Flow: Method 2.
                        NOX: Method 7E. CO2 or O2: Method 3A.           
5....................  For units with add-on SO2 and/or NOX emission    
                        controls: SO2 concentration or NOX emission rate
                        estimate from Agency preapproved parametric     
                        monitoring method.                              
6....................  Average of the hourly SO2 concentrations, CO2    
                        concentrations, flow rate, or NOX emission rate 
                        for the hour before and the hour following a    
                        missing data period.                            
7....................  Hourly average SO2 concentration, CO2            
                        concentration, flow rate, or NOX emission rate  
                        using initial missing data procedures.          
8....................  90th percentile hourly SO2 concentration, flow   
                        rate, or emission rate.                         
9....................  95th percentile hourly SO2 concentration, flow   
                        rate, or NOX emission rate.                     
10...................  Maximum hourly SO2 concentration, flow rate, or  
                        NOX emission rate.                              
11...................  Hourly average flow rate or NOX emission rate in 
                        corresponding load range.                       
12...................  Maximum potential concentration of SO2, maximum  
                        potential concentration of CO2, maximum         
                        potential flow rate, or maximum potential NOX   
                        emission rate, as determined using section 2.1  
                        of appendix A to this part.                     
13...................  Fuel analysis data from appendix G to this part  
                        for CO2 mass emissions. (This code is optional  
                        through 12/31/99, and shall not be used after 1/
                        1/00.)                                          
14...................  Diluent cap value (if the cap is replacing a CO2 
                        measurement, it shall be 5.0 percent for boilers
                        and 1.0 percent for turbines; if it is replacing
                        an O2 measurement, it shall be 14.0 percent for 
                        boilers and 19.0 percent for turbines.          
15...................  Fuel analysis data from appendix G to this part  
                        for CO2 mass emissions. (This code is optional  
                        through 12/31/99, and shall not be used after 1/
                        1/00.)                                          
16...................  SO2 concentration value of 2 ppm during hours    
                        when only natural gas (or fuel with equivalent  
                        sulfur content) is combusted.                   
19...................  200.0 percent of the MPC; default high range     
                        value.                                          
20...................  200.0 percent of the full-scale range setting    
                        (full-scale exceedance of high range).          
40...................  Stack volumetric flow calculated using the       
                        procedures of appendix I.                       
54...................  Other quality assured methodologies approved     
                        through petition. These hours are included in   
                        missing data lookback and are included as       
                        unavailable hours for percent monitor           
                        availability calculations.                      
55...................  Other substitute data approved through petition. 
                        These hours are not included in missing data    
                        lookback and are included as unavailable hours  
                        for percent monitor availability calculations.  
------------------------------------------------------------------------

    (d) NOX emission record provisions. The owner or 
operator shall record the information required by this paragraph for 
each affected unit for each hour, or partial hour during which the unit 
operates, except for a gas-fired peaking unit or oil-fired peaking unit 
for which the owner or operator is using the optional protocol in 
appendix E to this part or a low mass emissions unit for which the 
owner or operator is using the optional low mass emissions excepted 
methodology in Sec. 75.19(c) for estimating NOX emission 
rate. For each NOX emission rate as measured and reported 
from the certified primary monitor, certified back-up monitor, or other 
approved method of emissions determination:
    (1) Component system identification code, as provided in Sec. 75.53 
(including identification code for the moisture monitoring system, if 
applicable);
    (2) Date and hour;
    (3) Hourly average concentration (ppm, rounded to the nearest 
tenth);
    (4) Hourly average diluent gas concentration (percent O2 
or percent CO2, rounded to the nearest tenth) and, if 
applicable, the hourly average moisture content of the stack gas 
(percent H2O, rounded to the nearest tenth). If the 
continuous moisture monitoring system consists of wet- and dry-basis 
oxygen analyzers, also record both the hourly wet- and dry-basis oxygen 
readings (in percent O2, rounded to the nearest tenth);
    (5) Hourly average NOX emission rate (lb/mmBtu, rounded 
either to the nearest hundredth or thousandth prior to January 1, 2000 
and rounded to the nearest thousandth on and after January 1, 2000);
    (6) Hourly average NOX emission rate (lb/mmBtu, rounded 
either to the nearest hundredth or thousandth prior to January 1, 2000 
and rounded to the nearest thousandth on and after January 1, 2000), 
adjusted for bias if bias adjustment factor is required, as provided in 
Sec. 75.24(d). The requirement to report hourly NOX emission 
rates to the nearest thousandth shall not affect NOX 
compliance determinations under part 76 of this chapter; compliance 
with each applicable emission limit under part 76 shall be determined 
to the nearest hundredth pound per million Btu;
    (7) Percent monitoring system data availability (recorded to the 
nearest tenth of a percent), for the NOX

[[Page 28139]]

monitoring system, and, if applicable, separately for the moisture 
monitoring system, calculated pursuant to Sec. 75.32;
    (8) Method of determination for hourly average NOX 
emission rate using Codes 1-55 in Table 4a of this section;
    (9) Identification code for emissions formulas used to derive 
hourly average NOX emission rate and total NOX 
mass, as provided in Sec. 75.53, and F-factor used to convert 
NOX concentrations into emission rates;
    (e) CO2 emission record provisions. Except for a low 
mass emissions unit for which the owner or operator is using the 
optional low mass emissions excepted methodology in Sec. 75.19(c) for 
estimating CO2 mass emissions, the owner or operator shall 
record or calculate CO2 emissions for each affected unit 
using one of the following methods specified in this section:
    (1) If the owner or operator chooses to use a CO2 
continuous emission monitoring system (including an O2 
monitor and flow monitor, as specified in appendix F to this part), 
then the owner or operator shall record for each hour or partial hour 
during which the unit operates the following information for 
CO2 mass emissions, as measured and reported from the 
certified primary monitor, certified back-up monitor, or other approved 
method of emissions determination:
    (i) Component/system identification code, as provided in 
Sec. 75.53;
    (ii) Date and hour;
    (iii) Hourly average CO2 concentration (in percent, 
rounded to the nearest tenth);
    (iv) Hourly average volumetric flow rate (scfh, rounded to the 
nearest thousand scfh);
    (v) Hourly average moisture content of flue gas (percent, rounded 
to the nearest tenth), where CO2 concentration is measured 
on a dry basis. If the continuous moisture monitoring system consists 
of wet- and dry-basis oxygen analyzers, also record both the hourly 
wet- and dry-basis oxygen readings (in percent O2, rounded 
to the nearest tenth);
    (vi) Hourly average CO2 mass emission rate (tons/hr, 
rounded to the nearest tenth);
    (vii) Percent monitor data availability for both the CO2 
monitoring system and, if applicable, the moisture monitoring system 
(recorded to the nearest tenth of a percent), calculated pursuant to 
Sec. 75.32;
    (viii) Method of determination for hourly average CO2 
mass emission rate using Codes 1-55 in Table 4a of this section;
    (ix) Identification code for emissions formula used to derive 
hourly average CO2 mass emission rate, as provided in 
Sec. 75.53; and
    (x) Indication of whether the diluent cap was used for 
CO2 calculation for the hour.
    (2) As an alternative to paragraph (e)(1) of this section, the 
owner or operator may use the procedures in Sec. 75.13 and in appendix 
G to this part, and shall record daily the following information for 
CO2 mass emissions:
    (i) Date;
    (ii) Daily combustion-formed CO2 mass emissions (tons/
day, rounded to the nearest tenth);
    (iii) For coal-fired units, flag indicating whether optional 
procedure to adjust combustion-formed CO2 mass emissions for 
carbon retained in flyash has been used and, if so, the adjustment;
    (iv) For a unit with a wet flue gas desulfurization system or other 
controls generating CO2, daily sorbent-related 
CO2 mass emissions (tons/day, rounded to the nearest tenth); 
and
    (v) For a unit with a wet flue gas desulfurization system or other 
controls generating CO2, total daily CO2 mass 
emissions (tons/day, rounded to the nearest tenth) as sum of 
combustion-formed emissions and sorbent-related emissions.
    (f) Opacity records. The owner or operator shall record opacity 
data as specified by the State or local air pollution control agency. 
If the State or local air pollution control agency does not specify 
recordkeeping requirements for opacity, then record the information 
required by paragraphs (f) (1) through (5) of this section for each 
affected unit, except as provided in Sec. 75.14 (b), (c), and (d). The 
owner or operator shall also keep records of all incidents of opacity 
monitor downtime during unit operation, including reason(s) for the 
monitor outage(s) and any corrective action(s) taken for opacity, as 
measured and reported by the continuous opacity monitoring system:
    (1) Component/system identification code;
    (2) Date, hour, and minute;
    (3) Average opacity of emissions for each six minute averaging 
period (in percent opacity);
    (4) If the average opacity of emissions exceeds the applicable 
standard, then a code indicating such an exceedance has occurred; and
    (5) Percent monitor data availability (recorded to the nearest 
tenth of a percent), calculated according to the requirements of the 
procedure recommended for State Implementation Plans in appendix M to 
part 51 of this chapter.
    (g) O2-diluent record provisions. The owner or operator 
of a unit using a flow monitor and an O2-diluent monitor to 
determine heat input, in accordance with Equation F-17 or F-18 of 
appendix F to this part, shall keep the following records for the 
O2-diluent monitor:
    (1) Component-system identification code, as provided in 
Sec. 75.53;
    (2) Date and hour;
    (3) Hourly average O2 concentration (in percent, rounded to the 
nearest tenth);
    (4) Percent monitor data availability (recorded to the nearest 
tenth of a percent), calculated pursuant to Sec. 75.32;
    (5) Method of determination code for O2 concentration 
data using Codes 1-55, substituting the words ``O2 
concentrations'' and ``O2 concentration'' for the words 
``CO2 concentrations'' and CO2 concentration'' in 
the descriptions of Codes 6 and 7 in Table 4a of this section, 
respectively.
    (h) Missing data records. The owner or operator shall record the 
causes of any missing data periods and the actions taken by the owner 
or operator to cure such causes.
    (i) Compliance dates. Beginning on January 1, 2000, the owner or 
operator shall comply with the provisions in paragraphs (a), (b), (e) 
and (f) of this section only. Before January 1, 2000, the owner or 
operator shall comply with either paragraphs (a) through (d) or 
paragraphs (a), (b), (c), and (f) of this section, except that the 
owner or operator shall comply with provisions in paragraphs (e) and 
(f) of this section only before January 1, 2000, when those provisions 
support a regulatory option provided in another section of this part 75 
and the regulatory option is exercised before January 1, 2000.
    39. Section 75.58 is added to read as follows:


Sec. 75.58  General recordkeeping provisions for specific situations.

    (a) Specific SO2 emission record provisions for units 
with qualifying Phase I technology. In addition to the SO2 
emissions information required in Sec. 75.54(c), from January 1, 1997 
through December 31, 1999, the owner or operator shall record the 
applicable information in this paragraph for each affected unit on 
which SO2 emission controls have been installed and operated 
for the purpose of meeting qualifying Phase I technology requirements 
pursuant to Sec. 72.42 of this chapter and Sec. 75.15.
    (1) For units with post-combustion emission controls:
    (i) Component/system identification codes for each inlet and outlet 
SO2-diluent continuous emission monitoring system;
    (ii) Date and hour;

[[Page 28140]]

    (iii) Hourly average inlet SO2 emission rate during unit 
operation (lb/mmBtu, rounded to nearest hundredth);
    (iv) Hourly average outlet SO2 emission rate during unit 
operation (lb/mmBtu, rounded to nearest hundredth);
    (v) Percent data availability for both inlet and outlet 
SO2-diluent continuous emission monitoring systems (recorded 
to the nearest tenth of a percent), calculated pursuant to Equation 8 
of Sec. 75.32 (for the first 8,760 unit operating hours following 
initial certification) and Equation 9 of Sec. 75.32, thereafter; and
    (vi) Identification code for emissions formula used to derive 
hourly average inlet and outlet SO2 mass emissions rates for 
each affected unit or group of units using a common stack.
    (2) For units with combustion and/or pre-combustion emission 
controls:
    (i) Component/system identification codes for each outlet 
SO2-diluent continuous emission monitoring system;
    (ii) Date and hour;
    (iii) Hourly average outlet SO2 emission rate during 
unit operation (lb/mmBtu, rounded to nearest hundredth);
    (iv) For units with combustion controls, average daily inlet 
SO2 emission rate (lb/mmBtu, rounded to nearest hundredth), 
determined by coal sampling and analysis procedures in Sec. 75.15; and
    (v) For units with pre-combustion controls (i.e., fuel 
pretreatment), fuel analysis demonstrating the weight, sulfur content, 
and gross calorific value of the product and raw fuel lots.
    (b) Specific parametric data record provisions for calculating 
substitute emissions data for units with add-on emission controls. In 
accordance with Sec. 75.34, the owner or operator of an affected unit 
with add-on emission controls shall either record the applicable 
information in paragraph (b)(3) of this section for each hour of 
missing SO2 concentration data or NOX emission 
rate (in addition to other information), or shall record the 
information in paragraph (b)(1) of this section for SO2 or 
paragraph (b)(2) of this section for NOX through an 
automated data acquisition and handling system, as appropriate to the 
type of add-on emission controls:
    (1) For units with add-on SO2 emission controls 
petitioning to use or using the optional parametric monitoring 
procedures in appendix C to this part, for each hour of missing 
SO2 concentration or volumetric flow data:
    (i) The information required in Sec. 75.54(b) or Sec. 75.57(b) for 
SO2 concentration and volumetric flow, if either one of 
these monitors is still operating;
    (ii) Date and hour;
    (iii) Number of operating scrubber modules;
    (iv) Total feedrate of slurry to each operating scrubber module 
(gal/min);
    (v) Pressure differential across each operating scrubber module 
(inches of water column);
    (vi) For a unit with a wet flue gas desulfurization system, an in-
line measure of absorber pH for each operating scrubber module;
    (vii) For a unit with a dry flue gas desulfurization system, the 
inlet and outlet temperatures across each operating scrubber module;
    (viii) For a unit with a wet flue gas desulfurization system, the 
percent solids in slurry for each scrubber module.
    (ix) For a unit with a dry flue gas desulfurization system, the 
slurry feed rate (gal/min) to the atomizer nozzle;
    (x) For a unit with SO2 add-on emission controls other 
than wet or dry limestone, corresponding parameters approved by the 
Administrator;
    (xi) Method of determination of SO2 concentration and 
volumetric flow using Codes 1-55 in Table 4 of Sec. 75.54 or Table 4a 
of Sec. 75.57; and
    (xii) Inlet and outlet SO2 concentration values, 
recorded by an SO2 continuous emission monitoring system, 
and the removal efficiency of the add-on emission controls.
    (2) For units with add-on emission controls petitioning to use or 
using the optional parametric monitoring procedures in appendix C to 
this part, for each hour of missing NOX emission rate data:
    (i) Date and hour;
    (ii) Inlet air flow rate (scfh, rounded to the nearest thousand);
    (iii) Excess O2 concentration of flue gas at stack 
outlet (percent, rounded to nearest tenth of a percent);
    (iv) Carbon monoxide concentration of flue gas at stack outlet 
(ppm, rounded to the nearest tenth);
    (v) Temperature of flue gas at furnace exit or economizer outlet 
duct ( deg.F);
    (vi) Other parameters specific to NOX emission controls 
(e.g., average hourly reagent feedrate);
    (vii) Method of determination of NOX emission rate using 
Codes 1-55 in Table 4 of Sec. 75.54 or Table 4a of Sec. 75.57; and
    (viii) Inlet and outlet NOX emission rate values 
recorded by a NOX continuous emission monitoring system and 
the removal efficiency of the add-on emission controls.
    (3) For units with add-on SO2 or NOX emission 
controls following the provisions of Sec. 75.34(a)(1) or (a)(2), the 
owner or operator shall, for each hour of missing SO2 or 
NOX emission data, record:
    (i) Parametric data which demonstrate the proper operation of the 
add-on emission controls, as described in the quality assurance/quality 
control program for the unit. The parametric data shall be maintained 
on site and shall be submitted, upon request, to the Administrator, EPA 
Regional office, State, or local agency;
    (ii) A flag indicating either that the add-on emission controls are 
operating properly, as evidenced by all parameters being within the 
ranges specified in the quality assurance/quality control program, or 
that the add-on emission controls are not operating properly;
    (iii) For units petitioning under Sec. 75.66 for substituting a 
representative SO2 concentration during missing data 
periods, any available inlet and outlet SO2 concentration 
values recorded by an SO2 continuous emission monitoring 
system; and
    (iv) For units petitioning under Sec. 75.66 for substituting a 
representative NOX emission rate during missing data 
periods, any available inlet and outlet NOX emission rate 
values recorded by a continuous emission monitoring system.
    (c) Specific SO2 emission record provisions for gas-
fired or oil-fired units using optional protocol in appendix D to this 
part. In lieu of recording the information in Sec. 75.54(c) or 
Sec. 75.57(c), the owner or operator shall record the applicable 
information in this paragraph for each affected gas-fired or oil-fired 
unit for which the owner or operator is using the optional protocol in 
appendix D to this part for estimating SO2 mass emissions.
    (1) For each hour when the unit is combusting oil:
    (i) Date and hour;
    (ii) Hourly average flow rate of oil, while the unit combusts oil, 
with the units in which oil flow is recorded (gal/hr, lb/hr, 
m3/hr, or bbl/hr, rounded to the nearest tenth) (flag value 
if derived from missing data procedures);
    (iii) Sulfur content of oil sample used to determine SO2 
mass emission rate (rounded to nearest hundredth for diesel fuel or to 
the nearest tenth of a percent for other fuel oil) (flag value if 
derived from missing data procedures);
    (iv) Method of oil sampling (flow proportional, continuous drip, as 
delivered, manual from storage tank, or daily manual);
    (v) Mass rate of oil combusted each hour (lb/hr, rounded to the 
nearest tenth) (flag value if derived from missing data procedures);
    (vi) SO2 mass emission rate from oil (lb/hr, rounded to 
the nearest tenth);
    (vii) For units using volumetric oil flowmeters, density of oil 
with the units in which oil density is recorded (flag

[[Page 28141]]

value if derived from missing data procedures);
    (viii) Gross calorific value (heat content) of oil used to 
determine heat input (Btu/mass unit) (flag value if derived from 
missing data procedures);
    (ix) Hourly heat input rate from oil, according to procedures in 
appendix F to this part (mmBtu/hr, to the nearest tenth);
    (x) Fuel usage time for combustion of oil during the hour (rounded 
up to the nearest fraction of an hour (in equal increments that can 
range from one hundredth to one quarter of an hour, at the option of 
the owner or operator)) (flag to indicate multiple/single fuel types 
combusted); and
    (xi) Monitoring system identification code.
    (2) For gas-fired units or oil-fired units using the optional 
protocol in appendix D to this part for daily manual oil sampling, when 
the unit is combusting oil, the highest sulfur content recorded from 
the most recent 30 daily oil samples (rounded to nearest tenth of a 
percent).
    (3) For gas-fired units or oil-fired units, using the optional 
protocol in appendix D to this part for using an assumed sulfur content 
or density, or for as-delivered fuel sampled from each delivery:
    (i) Record the measured sulfur content, GCV and, if applicable, 
density from each fuel sample; and
    (ii) Record and report the assumed sulfur content, GCV and, if 
applicable, density used to calculate SO2 mass emission rate 
or heat input rate.
    (4) For each hour when the unit is combusting gaseous fuel:
    (i) Date and hour;
    (ii) Hourly heat input rate from gaseous fuel, according to 
procedures in appendix F to this part (mmBtu/hr, rounded to the nearest 
tenth);
    (iii) Sulfur content or SO2 emission rate, in one of the 
following formats, in accordance with the appropriate procedure from 
appendix D to this part:
    (A) Sulfur content of gas sample (rounded to the nearest 0.1 
grains/100 scf) (flag value if derived from missing data procedures); 
or
    (B) SO2 emission rate from NADB or default 
SO2 emission rate of 0.0006 lb/mmBtu for pipeline natural 
gas;
    (iv) Hourly flow rate of gaseous fuel, while the unit combusts gas 
(100 scfh) (flag value if derived from missing data procedures);
    (v) Gross calorific value (heat content) of gaseous fuel used to 
determine heat input rate (Btu/100 scf) (flag value if derived from 
missing data procedures);
    (vi) Heat input rate from gaseous fuel, while the unit combusts gas 
(mmBtu/hr, rounded to the nearest tenth);
    (vii) SO2 mass emission rate due to the combustion of 
gaseous fuels (lb/hr);
    (viii) Fuel usage time for combustion of gaseous fuel during the 
hour (rounded up to the nearest fraction of an hour (in equal 
increments that can range from one hundredth to one quarter of an hour, 
at the option of the owner or operator)) (flag to indicate multiple/
single fuel types combusted); and
    (ix) Monitoring system identification code.
    (5) For each oil sample or sample of diesel fuel:
    (i) Date of sampling;
    (ii) Sulfur content (percent, rounded to the nearest hundredth for 
diesel fuel and to the nearest tenth for other fuel oil) (flag value if 
derived from missing data procedures);
    (iii) Gross calorific value or heat content (Btu/lb) (flag value if 
derived from missing data procedures); and
    (iv) Density or specific gravity, if required to convert volume to 
mass (flag value if derived from missing data procedures).
    (6) For each sample of gaseous fuel for sulfur content:
    (i) Date of sampling;
    (ii) Sulfur content (grains/100 scf, rounded to the nearest tenth) 
(flag value if derived from missing data procedures);
    (7) For each sample of gaseous fuel for gross calorific value:
    (i) Date of sampling; and
    (ii) Gross calorific value or heat content (Btu/100 scf) (flag 
value if derived from missing data procedures).
    (8) For each oil sample or sample of gaseous fuel:
    (i) Type of oil or gas; and
    (ii) Type of sulfur sampling and value used in calculations.
    (d) Specific NOX emission record provisions for gas-
fired peaking units or oil-fired peaking units using optional protocol 
in appendix E to this part. In lieu of recording the information in 
paragraph Sec. 75.54(d) or Sec. 75.57(d), the owner or operator shall 
record the applicable information in this paragraph for each affected 
gas-fired peaking unit or oil-fired peaking unit for which the owner or 
operator is using the optional protocol in appendix E to this part for 
estimating NOX emission rate. The owner or operator shall 
meet the requirements of this section, except that the requirements 
under paragraphs (d)(1)(vii), (d)(2)(vii), and (d)(3)(vi) of this 
section shall become applicable on the date on which the owner or 
operator is required to monitor, record, and report NOX mass 
emissions under an applicable State or federal NOX mass 
emission reduction program, if the provisions of subpart H of this part 
are adopted as requirements under such a program.
    (1) For each hour when the unit is combusting oil:
    (i) Date and hour;
    (ii) Hourly average fuel flow rate of oil while the unit combusts 
oil with the units in which oil flow is recorded (gal/hour, lb/hr, or 
bbl/hour) (flag value if derived from missing data procedures);
    (iii) Gross calorific value (heat content) of oil used to determine 
heat input (Btu/lb) (flag value if derived from missing data 
procedures);
    (iv) Hourly average NOX emission rate from combustion of 
oil (lb/mmBtu);
    (v) Heat input rate of oil (mmBtu/hr, rounded to the nearest tenth;
    (vi) Fuel usage time for combustion of oil during the hour (rounded 
up to the nearest fraction of an hour (in equal increments that can 
range from one hundredth to one quarter of an hour, at the option of 
the owner or operator)); and
    (vii) NOX mass emissions, calculated in accordance with 
section 8.1 of appendix F to this part.
    (2) For each hour when the unit is combusting gaseous fuel:
    (i) Date and hour;
    (ii) Hourly average fuel flow rate of gaseous fuel, while the unit 
combusts gas (100 scfh) (flag value if derived from missing data 
procedures);
    (iii) Gross calorific value (heat content) of gaseous fuel used to 
determine heat input (Btu/100 scf) (flag value if derived from missing 
data procedures);
    (iv) Hourly average NOX emission rate from combustion of 
gaseous fuel (lb/mmBtu, rounded to nearest hundredth);
    (v) Heat input rate from gaseous fuel, while the unit combusts gas 
(mmBtu/hr, rounded to the nearest tenth);
    (vi) Fuel usage time for combustion of gaseous fuel during the hour 
(rounded up to the nearest fraction of an hour (in equal increments 
that can range from one hundredth to one quarter of an hour, at the 
option of the owner or operator)); and
    (vii) NOX mass emissions, calculated in accordance with 
section 8.1 of appendix F to this part.
    (3) For each hour when the unit combusts any fuel:
    (i) Date and hour;
    (ii) Hourly average heat input rate from all fuels (mmBtu/hr, 
rounded to the nearest tenth);
    (iii) Hourly average NOX emission rate for the unit for 
all fuels;
    (iv) For stationary gas turbines and diesel or dual-fuel 
reciprocating engines, hourly averages of operating parameters under 
section 2.3 of appendix E to this part (flag if value is

[[Page 28142]]

outside of manufacturer's recommended range);
    (v) For boilers, hourly average boiler O2 reading 
(percent, rounded to the nearest tenth) (flag if value exceeds by more 
than 2 percentage points the O2 level recorded at the same 
heat input during the previous NOX emission rate test);
    (vi) NOX mass emissions, calculated in accordance with 
section 8.1 of appendix F to this part;
    (vii) Segment ID of the correlation curve; and
    (viii) Monitoring system identification code.
    (4) For each fuel sample:
    (i) Date of sampling;
    (ii) Gross calorific value (heat content) (Btu/lb for oil, Btu/100 
scf for gaseous fuel); and
    (iii) Density or specific gravity, if required to convert volume to 
mass.
    (e) Specific SO2 emission record provisions during the 
combustion of gaseous fuel. (1) If SO2 emissions are 
determined in accordance with the provisions in Sec. 75.11(e)(2) during 
hours in which only natural gas (or gaseous fuel with a total sulfur 
content no greater than the total sulfur content of natural gas) is 
combusted in a unit with an SO2 continuous emission 
monitoring system, the owner or operator shall record the information 
in paragraph (c)(3) of this section in lieu of the information in 
Secs. 75.54(c)(1) and (c)(3) or Secs. 75.57(c)(1) and (c)(3), for those 
hours.
    (2) The provisions of this paragraph apply to a unit which, in 
accordance with the provisions of Sec. 75.11(e)(3), uses an 
SO2 continuous emission monitoring system to determine 
SO2 emissions during hours in which only natural gas or 
gaseous fuel with a total sulfur content no greater than the total 
sulfur content of natural gas is combusted in the unit. If the unit 
sometimes burns only natural gas (or gaseous fuel with total sulfur 
content no greater than the total sulfur content of natural gas) as a 
primary and/or backup fuel and at other times combusts higher-sulfur 
fuels, such as coal or oil, as primary and/or backup fuel(s), then the 
owner or operator shall keep records on-site, suitable for inspection, 
of the type(s) of fuel(s) burned during each period of missing 
SO2 data and the number of hours that each types of fuel was 
combusted in the unit during each missing data period. This 
recordkeeping requirement does not apply to an affected unit that burns 
natural gas (or gaseous fuel with a total sulfur content no greater 
than the total sulfur content of natural gas) exclusively, nor does it 
apply to a unit that burns such gaseous fuel(s) only during unit 
startup.
    (f) Specific SO2, NOX, and CO2 
record provisions for gas-fired or oil-fired units using the optional 
low mass emissions excepted methodology in Sec. 75.19. In lieu of 
recording the information in Secs. 75.54(b) through (e) or 
Sec. 75.57(b) through (e), the owner or operator shall record, for each 
hour when the unit is operating for any portion of the hour, the 
following information for each affected low mass emissions unit for 
which the owner or operator is using the optional low mass emissions 
excepted methodology in Sec. 75.19(c):
    (1) Date and hour;
    (2) Fuel type (pipeline natural gas, natural gas, residual oil, or 
diesel fuel) (note: if more than one type of fuel is combusted in the 
hour, indicate the fuel type which results in the highest emission 
factors for SO2, CO2, and NOX);
    (3) Average hourly NOX emission rate (lb/mmBtu, rounded 
to the nearest thousandth);
    (4) Hourly NOX mass emissions (lbs, rounded to the 
nearest tenth);
    (5) Hourly SO2 mass emissions (lbs, rounded to the 
nearest tenth); and
    (6) Hourly CO2 mass emissions (tons, rounded to the 
nearest tenth).
    (g) Specific provisions for gas-fired units or oil-fired units 
using optional protocol in appendix I to this part. In addition to 
recording the information in Sec. 75.54(c) or Sec. 75.57(c), as 
applicable, the owner or operator shall record the applicable 
information in this paragraph for each affected unit for which the 
owner or operator is using the optional protocol in appendix I to this 
part. This includes:
    (1) For each hour when the unit is combusting oil:
    (i) Date and hour;
    (ii) Hourly average flow rate of oil with the units in which oil 
flow is recorded (gal/hr, lb/hr, m3/hr, or bbl/hr, rounded 
to the nearest tenth) (flag value if derived from missing data 
procedures);
    (iii) Method of oil sampling (flow proportional, continuous drip, 
as delivered, or manual);
    (iv) Mass of oil combusted each hour (lb/hr, rounded to the nearest 
tenth);
    (v) For units using volumetric oil flowmeters, density of oil (flag 
value if derived from missing data procedures);
    (vi) Gross calorific value (heat content) of oil used to determine 
heat input (Btu/mass unit) (flag value if derived from missing data 
procedures);
    (vii) Hourly heat input rate from oil, according to procedures in 
appendix F to this part (mmBtu/hr, to the nearest tenth); and
    (viii) Fuel usage time for combustion of oil during the hour 
(rounded up to the nearest 15 minutes).
    (2) For each hour when the unit is combusting gaseous fuel:
    (i) Date and hour;
    (ii) Hourly heat input rate from gaseous fuel according to 
procedures in appendix F to this part (mmBtu/hr, rounded to the nearest 
tenth);
    (iii) Hourly flow rate of gaseous fuel (100 scfh) (flag value if 
derived from missing data procedures);
    (iv) Gross calorific value (heat content) of gaseous fuel used to 
determine heat input (Btu/100 scf) (flag value if derived from missing 
data procedures);
    (v) Heat input rate from gaseous fuel (mmBtu/hr, rounded to the 
nearest tenth);
    (vi) Fuel usage time for combustion of gaseous fuel during the hour 
(rounded up to the nearest 15 minutes); and
    (vii) F-factor (Fc=Carbon-based F-factor of 1040 scf 
CO2/mmBtu for natural gas, or Fd=Dry basis, 
O2-based F-factor of 8,710 dscf/mmBtu for natural gas).
    (3) For each oil sample or sample of diesel fuel:
    (i) Date of sampling;
    (ii) Gross calorific value or heat content (Btu/lb) (flag value if 
derived from missing data procedures);
    (iii) Density or specific gravity, if required to convert volume to 
mass (flag value if derived from missing data procedures); and
    (iv) Percent carbon by weight.
    (4) For each monthly sample of gaseous fuel:
    (i) Date of sampling; and
    (ii) Gross calorific value or heat content (Btu/100 scf) (flag 
value if derived from missing data procedures).
    (5) Hourly average diluent gas concentration (percent O2 
or percent CO2, rounded to the nearest tenth).
    (h) Compliance dates. Beginning on January 1, 2000, the owner or 
operator shall comply with this section only. Before January 1, 2000, 
the owner or operator shall comply with either this section or 
Sec. 75.55; except that if a regulatory option provided in another 
section of this part 75 is exercised prior to January 1, 2000, then the 
owner or operator shall comply with any provisions of this section that 
support the regulatory option beginning with the date on which the 
option is exercised.
    40. Section 75.59 is added to read as follows:


Sec. 75.59  Certification, quality assurance, and quality control 
record provisions.

    (a) Continuous emission or opacity monitoring systems. The owner or

[[Page 28143]]

operator shall record the applicable information in this section for 
each certified monitor or certified monitoring system (including 
certified backup monitors) measuring and recording emissions or flow 
from an affected unit.
    (1) For each SO2 or NOX pollutant 
concentration monitor, flow monitor, CO2 monitor (including 
O2 monitors used to determine CO2 emissions), 
moisture sensor, or diluent gas monitor (including wet-and dry-basis 
O2 monitors used to determine percent moisture), the owner 
or operator shall record the following for all daily and 7-day 
calibration error tests, including any follow-up tests after corrective
    (i) Component/system identification code;
    (ii) Instrument span and span scale;
    (iii) Date and hour;
    (iv) Reference value (i.e., calibration gas concentration or 
reference signal value, in ppm or other appropriate units);
    (v) Observed value (monitor response during calibration, in ppm or 
other appropriate units);
    (vi) Percent calibration error (rounded to the nearest tenth of a 
percent) (flag if using alternative performance specification for low 
emitters or differential pressure flow monitors);
    (vii) Calibration gas level;
    (viii) Test number and reason for test;
    (ix) For 7-day calibration tests for certification or 
recertification, a certification from the cylinder gas vendor or CEMS 
vendor that calibration gas, as defined in Sec. 72.2 of this chapter 
and appendix A to this part, was used to conduct calibration error 
testing;
    (x) Description of any adjustments, corrective actions, or 
maintenance following test; and
    (xi) For the qualifying test for off-line calibration, the owner or 
operator shall indicate whether the unit is off-line or on-line.
    (2) For each flow monitor, the owner or operator shall record the 
following for all daily interference checks, including any follow-up 
tests after corrective action:
    (i) Code indicating whether monitor passes or fails the 
interference check; and
    (ii) Description of any adjustments, corrective actions, or 
maintenance following test.
    (3) For each SO2 or NOX pollutant 
concentration monitor, CO2 monitor (including O2 
monitors used to determine CO2 emissions), or diluent gas 
monitor (including wet-and dry-basis O2 monitors used to 
determine percent moisture), the owner or operator shall record the 
following for the initial and all subsequent linearity check(s), 
including any follow-up tests after corrective action:
    (i) Component/system identification code;
    (ii) Instrument span and span scale;
    (iii) Date and hour;
    (iv) Reference value (i.e., reference gas concentration, in ppm or 
other appropriate units);
    (v) Observed value (average monitor response at each reference gas 
concentration, in ppm or other appropriate units);
    (vi) Percent error at each of three reference gas concentrations 
(rounded to nearest tenth of a percent) (flag if using alternative 
performance specification);
    (vii) Calibration gas level;
    (viii) Mean of reference values and mean of measured values;
    (ix) Test number and reason for test (flag if aborted test); and
    (x) Description of any adjustments, corrective action, or 
maintenance following test.
    (4) For each flow monitor (where applicable) the owner or operator 
shall record items in paragraphs (a)(4)(i) through (v) of this section, 
for all quarterly leak checks, including any follow-up tests after 
corrective action, and items in paragraphs (a)(4)(vi) and (vii) of this 
section, for all flow-to-load ratio and gross heat rate tests:
    (i) Component/system identification code;
    (ii) Date and hour;
    (iii) Reason for test;
    (iv) Code indicating whether monitor passes or fails the quarterly 
leak check;
    (v) Description of any adjustments, corrective actions, or 
maintenance following test;
    (vi) Test data from the flow-to-load ratio or gross heat rate 
evaluation, including:
    (A) Component/system identification code;
    (B) Calendar year and quarter;
    (C) Indication of whether the test is a flow-to-load ratio or gross 
heat rate evaluation;
    (D) Indication of whether bias adjusted flow rates were used;
    (E) Average absolute percent difference between reference ratio (or 
BHR) and hourly ratios (or GHE values);
    (F) Test result;
    (G) Number of hours used in final quarterly average;
    (H) Number of hours exempted for use of a different fuel type;
    (I) Number of hours exempted for load ramping up or down;
    (J) Number of hours exempted for scrubber bypass;
    (K) Number of hours exempted for hours preceding a normal-load flow 
RATA; and
    (L) Number of hours exempted for hours preceding a successful 
diagnostic test, following a documented monitor repair or major 
component replacement; and
    (vii) Reference data for the flow-to-load ratio or gross heat rate 
evaluation, including:
    (A) Reference flow RATA end date and time;
    (B) Test number;
    (C) Reference RATA load and load level;
    (D) Average reference method flow rate during reference flow RATA;
    (E) Reference flow/load ratio;
    (F) Average reference method diluent gas concentration during flow 
RATA and diluent gas units of measure;
    (G) Fuel specific Fd- or Fc-factor during 
flow RATA and F-factor units of measure; and
    (H) Reference gross heat rate value.
    (5) For each SO2 pollutant concentration monitor, flow 
monitor, CO2 pollutant concentration monitor (including any 
O2 concentration monitor used to determine CO2 
mass emissions or heat input), NOX continuous emission 
monitoring system, SO2-diluent continuous emission 
monitoring system, moisture monitoring system, and approved alternative 
monitoring system, the owner or operator shall record the following 
information for the initial and all subsequent relative accuracy test 
audits:
    (i) Reference method(s) used;
    (ii) Individual test run data from the relative accuracy test audit 
for the SO2 concentration monitor, flow monitor, 
CO2 pollutant concentration monitor, NOX 
continuous emission monitoring system, SO2-diluent 
continuous emission monitoring system, moisture monitoring system, or 
approved alternative monitoring systems, including:
    (A) Date, hour, and minute of beginning of test run;
    (B) Date, hour, and minute of end of test run;
    (C) System identification code;
    (D) Test number and reason for test;
    (E) Operating load level (low, mid, high, or normal, as 
appropriate) and number of load levels comprising test;
    (F) Run number;
    (G) Run data for monitor, in the appropriate units of measure;
    (H) Run data for reference method, in the appropriate units of 
measure;
    (I) Flag value (0, 1, or 9, as appropriate) indicating whether run 
has been used in calculating relative accuracy and bias values or 
whether the test was aborted prior to completion;
    (J) Average gross unit load; and

[[Page 28144]]

    (K) Flag to indicate whether an alternative performance 
specification has been used.
    (iii) Calculations and tabulated results, as follows:
    (A) Arithmetic mean of the monitoring system measurement values, of 
the reference method values, and of their differences, as specified in 
Equation A-7 in appendix A to this part.
    (B) Standard deviation, as specified in Equation A-8 in appendix A 
to this part.
    (C) Confidence coefficient, as specified in Equation A-9 in 
appendix A to this part.
    (D) Relative accuracy test results, as specified in Equation A-10 
in appendix A to this part. (For multi-level flow monitor tests the 
relative accuracy test results shall be recorded at each load level 
tested. Each load level shall be expressed as a total gross unit load, 
rounded to the nearest MWe, or as steam load, rounded to the nearest 
thousand lb/hr.)
    (E) Bias test results as specified in section 7.6.4 in appendix A 
to this part.
    (F) Bias adjustment factor from Equations A-11 and A-12 in appendix 
A to this part for any monitoring system that failed the bias test 
(except as provided in section 7.6.5 of appendix A to this part) and 
1.000 for any monitoring system that passed the bias test. (For multi-
load RATAs of flow monitors only, when the bias test is passed at the 
load level(s) designated as normal in section 6.5.2.1 of appendix A to 
this part, the system BAF shall be recorded as 1.000. When the bias 
test is failed at any load level designated as normal in section 
6.5.2.1 of appendix A to this part, bias adjustment factors shall be 
recorded at the two most frequently used load levels, as defined in 
section 6.5.2.1 of appendix A to this part.)
    (iv) Description of any adjustment, corrective action, or 
maintenance following test.
    (v) F-factor value(s) used to convert NOX pollutant 
concentration and diluent gas (O2 or CO2) 
concentration measurements into NOX emission rates (in lb/
mmBtu), heat input or CO2 emissions.
    (vi) For flow monitors, the flow polynomial equation used to 
linearize the flow monitor and the numerical values of the polynomial 
coefficients of that equation.
    (6) For each SO2, NOX, CO2, or 
O2 pollutant concentration monitor, NOX-diluent 
continuous emission monitoring system, or SO2-diluent 
continuous emission monitoring system, the owner or operator shall 
record the following information for the cycle time test:
    (i) Component/system identification code;
    (ii) Date;
    (iii) Start and end times;
    (iv) Upscale and downscale cycle times for each component;
    (v) Stable start monitor value;
    (vi) Stable end monitor value;
    (vii) Reference value of calibration gas(es);
    (viii) Calibration gas level; and
    (ix) Cycle time result for the entire system.
    (x) Reason for test.
    (7) The owner or operator shall also record, for each relative 
accuracy test audit, supporting information sufficient to substantiate 
compliance with all applicable sections and appendices in this part. 
This RATA supporting information shall include, but shall not be 
limited to, the following data elements:
    (i) For each RATA using Reference Method 2 (or its allowable 
alternatives) in appendix A to part 60 of this chapter to determine 
volumetric flow rate:
    (A) Information indicating whether or not the location meets 
requirements of Method 1 in appendix A to part 60 of this chapter; and
    (B) Information indicating whether or not the equipment passed the 
required leak checks.
    (ii) For each run of each RATA using Reference Method 2 (or its 
allowable alternatives) in appendix A to part 60 of this chapter to 
determine volumetric flow rate, record the following data elements (as 
applicable to the measurement method used):
    (A) Operating load level (low, mid, high, or normal, as 
appropriate);
    (B) Number of reference method traverse points;
    (C) Average absolute stack gas temperature ( deg. F);
    (D) Barometric pressure at test port (inches of mercury);
    (E) Stack static pressure (inches of H2O);
    (F) Absolute stack gas pressure (inches of mercury);
    (G) Percent CO2 and O2 in the stack gas, dry 
basis;
    (H) CO2 and O2 reference method used;
    (I) Moisture content of stack gas (percent H2O);
    (J) Molecular weight of stack gas, dry basis (lb/lb-mole);
    (K) Molecular weight of stack gas, wet basis (lb/lb-mole);
    (L) Stack diameter (or equivalent diameter) at the test port (ft);
    (M) Average square root of velocity head of stack gas (inches of 
H2O) for the run;
    (N) Stack or duct cross-sectional area at test port (ft 
2);
    (O) Average axial velocity (ft/sec); and
    (P) Total volumetric flow rate (scfh, wet basis).
    (iii) For each traverse point of each run of each RATA using 
Reference Method 2 (or its allowable alternatives) in appendix A to 
part 60 of this chapter to determine volumetric flow rate, record the 
following data elements (as applicable to the measurement method used):
    (A) Reference method probe type;
    (B) Pressure measurement device type;
    (C) Traverse point ID;
    (D) Probe or pitot tube calibration coefficient;
    (E) Date of latest probe or pitot tube calibration;
    (F) P at traverse point (inches of H2O);
    (G) Ts, stack temperature at the traverse point ( deg. 
F);
    (H) Calculated impact (total) velocity at the traverse point (ft/
sec);
    (I) Composite (wall effects) traverse point identifier;
    (J) Number of points included in composite traverse point;
    (K) Yaw angle of flow at traverse point (degrees);
    (L) Pitch angle of flow at traverse point (degrees); and
    (M) Calculated axial velocity at traverse point (ft/sec).
    (iv) For each RATA using Method 6C, 7E, or 3A in appendix A to part 
60 of this chapter to determine SO2, NOX, 
CO2, or O2 concentration:
    (A) Pollutant or diluent gas being measured;
    (B) Span of reference method analyzer;
    (C) Type of reference method system (e.g., extractive or dilution 
type);
    (D) Reference method dilution factor (dilution type systems, only);
    (E) Reference gas concentrations (zero, mid, and high gas levels) 
used for the 3-point pre-test analyzer calibration error test (or for 
dilution type reference method systems, for the 3-point pre-test system 
calibration error test) and for any subsequent recalibrations;
    (F) Analyzer responses to the zero-, mid-, and high-level 
calibration gases during the 3-point pre-test analyzer (or system) 
calibration error test and during any subsequent recalibration(s);
    (G) Analyzer calibration error at each gas level (zero, mid, and 
high) for the 3-point pre-test analyzer (or system) calibration error 
test and for any subsequent recalibration(s) (percent of span value);
    (H) Reference gas concentration (zero, mid, or high gas levels) 
used for each pre-run or post-run system bias check or (for dilution 
type reference method

[[Page 28145]]

systems) for each pre-run or post-run system calibration error check;
    (I) Analyzer response to the calibration gas for each pre-run or 
post-run system bias (or system calibration error) check;
    (J) The arithmetic average of the analyzer responses to the zero-
level gas, for each pair of pre- and post-run system bias (or system 
calibration error) checks;
    (K) The arithmetic average of the analyzer responses to the upscale 
calibration gas, for each pair of pre-and post-run system bias (or 
system calibration error) checks;
    (L) The results of each pre-run and each post-run system bias (or 
system calibration error) check using the zero-level gas (percentage of 
span value);
    (M) The results of each pre-run and each post-run system bias (or 
system calibration error) check using the upscale calibration gas 
(percentage of span value);
    (N) Calibration drift and zero drift of analyzer during each RATA 
run (percentage of span value);
    (O) Moisture basis of the reference method analysis;
    (P) Moisture content of stack gas, in percent, during each test run 
(if needed to convert to moisture basis of CEMS being tested);
    (Q) Unadjusted (raw) average pollutant or diluent gas concentration 
for each run;
    (R) Average pollutant or diluent gas concentration for each run, 
corrected for calibration bias (or calibration error) and, if 
applicable, corrected for moisture;
    (S) The F-factor used to convert reference method data to units of 
lb/mmBtu (if applicable);
    (T) The code for the formula used to convert reference method data 
to units of lb/mmBtu (if applicable);
    (U) Date(s) of the latest analyzer interference test(s);
    (V) Results of the latest analyzer interference test(s);
    (W) Date of the latest NO2 to NO conversion test (Method 
7E only);
    (X) Results of the latest NO2 to NO conversion test 
(Method 7E only); and
    (Y) For each calibration gas cylinder during each RATA, record the 
cylinder gas vendor, cylinder number, expiration date, pollutant(s) in 
the cylinder, and certified gas concentration(s).
    (v) For each test run of each moisture determination using Method 4 
in appendix A to part 60 of this chapter (or its allowable 
alternatives), whether the determination is made to support a gas RATA, 
to support a flow RATA, or to quality assure the data from a continuous 
moisture monitoring system, record the following data elements (as 
applicable to the moisture measurement method used):
    (A) Parameter (SO2, NOX, flow, 
CO2, or H2O), to indicate whether the moisture 
determination is used to support a gas or flow rate RATA or whether the 
determination is used to quality assure a moisture monitoring system;
    (B) Test number;
    (C) Run number;
    (D) The beginning date, hour, and minute of the run;
    (E) The ending date, hour, and minute or the run;
    (F) Unit operating level (low, mid, high, or normal, as 
appropriate);
    (G) Moisture measurement method;
    (H) Volume of H2O collected in the impingers (ml);
    (I) Mass of H2O collected in the silica gel (g);
    (J) Dry gas meter calibration factor;
    (K) Average dry gas meter temperature ( deg.F);
    (L) Barometric pressure (inches of mercury);
    (M) Differential pressure across the orifice meter (inches of 
H2O);
    (N) Initial and final dry gas meter readings (ft\3\);
    (O) Total sample gas volume, corrected to standard conditions 
(dscf); and
    (P) Percentage of moisture in the stack gas (percent 
H2O).
    (vi) The upper and lower boundaries of the range of operation (as 
defined in section 6.5.2.1 of appendix A to this part) for the unit or 
common stack on which the continuous emission monitor(s) are installed, 
expressed in megawatts or thousands of lb/hr of steam;
    (vii) The load level(s) designated as normal in section 6.5.2.1 of 
appendix A to this part for the unit or common stack on which the 
continuous emission monitor(s) are installed, expressed in megawatts or 
thousands of lb/hr of steam;
    (viii) Except for peaking units, the two load levels (i.e., low, 
mid, or high) identified in section 6.5.2.1 of appendix A to this part 
as the most frequently used;
    (ix) Except for peaking units, the relative frequency (percentage) 
of historical usage of each load level (low, mid, and high) in the 
previous four QA operating quarters, as determined in section 6.5.2.1 
of appendix A to this part, to the nearest 0.1 percent. The beginning 
and ending calendar quarters in the historical look-back period shall 
also be recorded. A summary of the data used to determine the most 
frequently and second most frequently used load levels and the 
percentage of time that each load level has been used historically 
shall be kept on-site in a format suitable for inspection;
    (x) Indication of whether the unit/stack qualifies for single load 
flow RATA testing (operation for  85.0 percent of operating 
hours is at a single load level); and
    (xi) Date of the load analysis described in paragraphs (a)(7)(vi) 
through (a)(7)(x) of this section.
    (8) For each certified continuous emission monitoring system, 
continuous opacity monitoring system, or alternative monitoring system, 
the date and description of each event which requires recertification 
of the system and the date and type of each test performed to recertify 
the system in accordance with Sec. 75.20(b).
    (9) Hardcopy quality assurance relative accuracy test reports, 
certification reports, or recertification reports for pollutant 
concentration or stack flow CEMS shall include, as a minimum, the 
following elements (as applicable to the type(s) of test(s) performed):
    (i) Summarized test results near the front of the report;
    (ii) DAHS printouts of the CEMS data generated during the 
calibration error, linearity, cycle time, and relative accuracy tests;
    (iii) For pollutant concentration monitor relative accuracy tests 
at normal operating load:
    (A) The raw reference method data from each run (usually in the 
form of a computerized printout, showing a series of one-minute 
readings and the run average);
    (B) The raw data and results for all required pre-test and post-
test quality assurance checks (i.e., calibration gas injections) of the 
reference method analyzers;
    (C) The raw data and results for any moisture measurements made 
during the relative accuracy testing;
    (D) Tabulated, final, corrected reference method run data (i.e., 
the actual values used in the relative accuracy calculations), along 
with the equations used to convert the raw data to the final values and 
example calculations to demonstrate how the test data were reduced;
    (iv) For flow monitor relative accuracy tests:
    (A) The raw Reference Method 2 data, including auxiliary moisture 
data (often in the form of handwritten data sheets);
    (B) The tabulated, final volumetric flow rate values used in the 
relative accuracy calculations (determined from the Method 2 data and 
other necessary measurements, e.g., moisture, stack temperature and 
pressure, etc.), along

[[Page 28146]]

with the equations used to convert the raw data to the final values and 
example calculations to demonstrate how the test data were reduced;
    (v) Calibration gas certificates for the gases used in the 
linearity, calibration error, and cycle time tests and for the 
calibration gases used to quality assure the gas monitor reference 
method data during the relative accuracy test audit;
    (vi) Laboratory calibrations of the source sampling equipment;
    (vii) A copy of the test protocol used for the CEMS certifications 
or recertifications, including narrative that explains any testing 
abnormalities, problematic sampling, and analytical conditions that 
required a change to the test protocol, and/or solutions to technical 
problems encountered during the testing program;
    (viii) Diagrams illustrating test locations and sample point 
locations (to verify that locations are consistent with presented 
information in the monitoring plan). Include a discussion of any 
special traversing or measurement scheme. The discussion shall also 
confirm that sample points satisfied applicable acceptance criteria; 
and
    (ix) Names of key personnel involved in the test program, including 
test team members, plant contacts, agency representatives or test 
observers on site, etc.
    (10) Whenever reference methods are used as backup monitoring 
systems pursuant to Sec. 75.20(d)(3), the owner or operator shall 
record the following information:
    (i) For each test run using Reference Method 2 (or its allowable 
alternatives) in appendix A to part 60 of this chapter to determine 
volumetric flow rate, record the following data elements (as applicable 
to the measurement method used):
    (A) Unit or stack identification number;
    (B) Reference method system and component identification numbers;
    (C) Run date and hour;
    (D) The data elements in paragraph (a)(7)(ii) of this section, 
except for paragraphs (a)(7)(ii) (A), (F), (H), and (L);
    (E) Data element in paragraph (a)(7)(iii)(A) of this section.
    (ii) For each reference method test run using Method 6C, 7E, or 3A 
in appendix A to part 60 of this chapter to determine SO2, 
NOX, CO2, or O2 concentration:
    (A) Unit or stack identification number;
    (B) The reference method system and component identification 
numbers;
    (C) Run number;
    (D) Run start date and hour;
    (E) Run end date and hour;
    (F) Data elements in paragraph (a)(7)(iv) (B) through (I) and (L) 
through (O) of this section; and
    (G) Stack gas density adjustment factor (if applicable).
    (iii) For each hour of each reference method test run using Method 
6C, 7E, or 3A in appendix A to part 60 of this chapter to determine 
SO2, NOX, CO2, or O2 
concentration:
    (A) Unit or stack identification number;
    (B) The reference method system and component identification 
numbers;
    (C) Run number;
    (D) Run date and hour;
    (E) Pollutant or diluent gas being measured;
    (F) Unadjusted (raw) average pollutant or diluent gas concentration 
for the hour; and
    (G) Average pollutant or diluent gas concentration for the hour, 
adjusted as appropriate for moisture, calibration bias (or calibration 
error) and stack gas density.
    (11) For each other quality-assurance test or other quality 
assurance activity, the owner or operator shall record the following:
    (i) Component/system identification code;
    (ii) Parameter;
    (iii) Test or activity completion date and hour;
    (iv) Test or activity description;
    (v) Test result;
    (vi) Reason for test;
    (vii) Test code.
    (12) For each quality assurance test extension or exemption 
request, the owner or operator shall record the following:
    (i) For a RATA deadline extension or exemption request:
    (A) Monitoring system identification code;
    (B) Date of last RATA;
    (C) RATA expiration date without extension;
    (D) RATA expiration date with extension;
    (E) Type of RATA extension of exemption claimed or lost;
    (F) Year to date hours of fuel usage with a sulfur content >0.05 
percent by weight; and
    (G) Year to date hours of non-redundant back-up CEMS use at the 
unit/stack.
    (ii) For a linearity test quarterly exemption:
    (A) Component/system identification code; and
    (B) Basis for exemption.
    (iii) For a quality assurance test extension claim based on a grace 
period:
    (A) Component/system identification code;
    (B) Type of test;
    (C) Beginning of grace period;
    (D) Date and hour of completion of required quality assurance test 
or maximum allowable grace period if no quality assurance test was 
completed during the grace period; and
    (E) Number of unit/stack operating hours from the beginning of the 
grace period to the completion of the quality assurance test or the 
maximum allowable grace period.
    (13) An indication of which data have been excluded from the 
quarterly span and range evaluations of the SO2 and 
NOX monitors and the reasons for excluding the data, as 
required in sections 2.1.1.5 and 2.1.2.5 of appendix A to this part. 
For purposes of reporting under Sec. 75.64(a)(1), this information 
shall be reported with the quarterly report as descriptive text 
consistent with Sec. 75.64(g).
    (b) Excepted monitoring systems for gas-fired and oil-fired units. 
The owner or operator shall record the applicable information in this 
section for each excepted monitoring system following the requirements 
of appendix D to this part or appendix E to this part for determining 
and recording emissions from an affected unit.
    (1) For each oil-fired unit or gas-fired unit using the optional 
procedures of appendix D to this part for determining SO2 
mass emissions and/or heat input or the optional procedures of appendix 
E to this part for determining NOX emission rate, for 
certification and quality assurance testing of fuel flowmeters tested 
against a reference fuel flow rate (i.e., flow rate another fuel 
flowmeter under section 2.1.5.2 of appendix D to this part or flow rate 
from a procedure according to a standard incorporated by reference 
under section 2.1.5.1 of appendix D to this part):
    (i) Date and hour of test completion;
    (ii) Upper range value of the fuel flowmeter;
    (iii) Flowmeter measurements during accuracy test (and mean of 
values), including units of measure;
    (iv) Reference flow rates during accuracy test (and mean of 
values), including units of measure;
    (v) Average flowmeter accuracy as a percent of upper range value 
for low, mid, and high fuel flowrates;
    (vi) Indicator of whether test method was a lab comparison to 
reference meter or an in-line comparison against a master meter;
    (vii) Test result (aborted, pass, or fail);
    (viii) Component and system identification numbers of the fuel 
flowmeter being tested;

[[Page 28147]]

    (ix) Date and hour fuel flowmeter was reinstalled ( only for tests 
not performed inline); and
    (x) Description of fuel flowmeter calibration specification or 
procedure (in the certification application, or periodically if a 
different method is used for annual quality assurance testing).
    (2) For each transmitter or transducer accuracy test for an 
orifice-, nozzle-, or venturi-type flowmeter used under section 2.1.6 
of appendix D to this part:
    (i) Date of test;
    (ii) Full-scale value of the transmitter or transducer;
    (iii) Transmitter input (pre-calibration) prior to accuracy test, 
including units of measure;
    (iv) Expected transmitter output during accuracy test (reference 
value from NIST-traceable equipment), including units of measure;
    (v) Actual transmitter output during accuracy test, including units 
of measure;
    (vi) Transmitter or transducer accuracy as a percent of the full-
scale value;
    (vii) Transmitter output level as a percent of the full-scale 
value);
    (viii) Transmitter or transducer accuracy, as a percent of full-
scale value, and overall accuracy (if applicable), as a percent of 
upper range value;
    (ix) Test and run number;
    (x) Time of run (only for tests against another flowmeter inline);
    (xi) Component and system identification numbers of the fuel 
flowmeter being tested;
    (xii) Transmitter or transducer type (differential pressure, static 
pressure, or temperature); and
    (xiii) Test result.
    (3) For each visual inspection of the primary element or 
transmitter or transducer accuracy test for an orifice-, nozzle-, or 
venturi-type flowmeter under sections 2.1.6.1 through 2.1.6.6 of 
appendix D to this part:
    (i) Date of inspection/test;
    (ii) Hour of completion of inspection/test;
    (iii) Component and system identification numbers of the fuel 
flowmeter being inspected/tested; and
    (iv) Results of inspection/test (pass or fail).
    (4) For fuel flowmeters that are tested using the flow-to-load 
ratio procedures of section 2.1.7 of appendix D to this part:
    (i) Test data for the fuel flowmeter flow-to-load ratio or gross 
heat rate check, including:
    (A) Component/system identification code;
    (B) Calendar year and quarter;
    (C) Indication of whether the test is for flow-to-load ratio or 
gross heat rate;
    (D) Test result;
    (E) Number of hours excluded due to co-firing;
    (F) Number of hours excluded due to ramping;
    (G) Number of hours excluded for lower 10.0 percent range of 
operation; and
    (H) Quarterly average absolute percent difference between baseline 
ratio (or baseline GHR) and hourly quarterly ratios (or GHR value).
    (ii) Reference data for the fuel flowmeter flow-to-load ratio or 
gross heat rate evaluation, including:
    (A) Completion date and hour of most recent primary element 
inspection;
    (B) Completion date and hour of most recent flowmeter or 
transmitter accuracy test;
    (C) Beginning and hour of baseline period;
    (D) Completion date and hour of baseline period;
    (E) Average fuel flow rate;
    (F) Average load;
    (G) Baseline fuel flow-to-load ratio and fuel flow-to-load units of 
measure;
    (H) Baseline GHR and GHR units;
    (I) Number of hours excluded due to ramping; and
    (J) Number of hours excluded in lower 10.0 percent of range of 
operation.
    (5) For gas-fired peaking units or oil-fired peaking units using 
the optional procedures of appendix E to this part, for each initial 
performance, periodic, or quality assurance/quality control-related 
test:
    (i) For each run of emission data;
    (A) Run start date and time;
    (B) Run end date and time;
    (C) Fuel flow rate (lb/hr, gal/hr, scf/hr, bbl/hr, or m\3\/hr);
    (D) Gross calorific value (heat content) of fuel (Btu/lb or Btu/
scf);
    (E) Density of fuel, and units of measure for fuel density (if 
needed to convert mass to volume);
    (F) Total heat input during the run (mmBtu);
    (G) Hourly heat input rate for run (mmBtu/hr);
    (H) Response time of the O2 and NOX reference method 
analyzers;
    (I) NOX concentration (ppm);
    (J) O2 concentration (percent O2);
    (K) NOX emission rate (lb/mmBtu);
    (L) Fuel or fuel combination (by heat input fraction) combusted;
    (M) Run number;
    (N) Operating level;
    (O) Elapsed time;
    (P) Test number;
    (Q) Monitoring system identification code for appendix E system, 
and oil or fuel flow system;
    (R) Heat input from oil and/or gas during the run;
    (S) Volumetric flow of oil and/or gas during the run, and units of 
measure for volumetric flow; and
    (T) Mass fuel flow during the run.
    (ii) For each unit load and heat input:
    (A) Average NOX emission rate (lb/mmBtu);
    (B) F-factor used in calculations;
    (C) Average heat input rate (mmBtu/hr);
    (D) Unit operating parametric data related to NOX 
formation for that unit type (e.g., excess O2 level, water/
fuel ratio);
    (E) Fuel or fuel combination (by heat input fraction) combusted;
    (F) Completion date and time of last run in level; and
    (G) Arithmetic mean of reference method values at this level.
    (c) For units with add-on SO2 and NOX 
emission controls following the provisions of Sec. 75.34(a)(1) or 
(a)(2), the owner or operator shall keep the following records on-site 
in the quality assurance/quality control plan required by section 1 in 
appendix B to this part:
    (1) A list of operating parameters for the add-on emission 
controls, including parameters in Sec. 75.55(b), appropriate to the 
particular installation of add-on emission controls; and
    (2) The range of each operating parameter in the list that 
indicates the add-on emission controls are properly operating.
    (d) Excepted flow monitoring systems under appendix I. The owner or 
operator shall record the applicable information in this section for 
each certified excepted flow monitoring system under appendix I to this 
part measuring and recording flow from an affected unit.
    (1) Certification test records. Record the results of the following 
tests:
    (i) For each CO2 or O2 component monitor:
    (A) 7-day calibration error tests, as specified in paragraph (a)(1) 
of this section;
    (B) Cycle time test, as specified in paragraph (a)(6) of this 
section; and
    (C) Linearity checks, as specified in paragraph (a)(3) of this 
section.
    (ii) For each appendix I flow monitoring system tested in a 
component by component assessment:
    (A) Flowmeter accuracy test data (or a statement of calibration, if 
the flowmeter meets the accuracy standard by design), as specified in 
paragraph (b)(1) of this section;
    (B) Relative accuracy test and bias data for the CO2 (or 
O2) monitor, as specified in paragraphs (a)(5) and (a)(7) of 
this section; and

[[Page 28148]]

    (C) Fuel sampling and analysis data, as specified in section 2.3 of 
appendix I to this part.
    (iii) For each appendix I flow monitoring system tested in a system 
relative accuracy assessment:
    (A) Relative accuracy test and bias data for the appendix I flow 
monitoring system, as specified for a flow monitoring system in 
paragraphs (a)(5) and (a)(7) of this section; and
    (B) Fuel sampling and analysis data, as specified in section 2.3 of 
appendix I to this part.
    (2) Quality assurance/quality control test records. Record the 
results of the following tests:
    (i) For CO2 or O2 monitors:
    (A) Daily calibration error tests, as specified in paragraph (a)(1) 
of this section; and
    (B) Quarterly linearity checks, as specified in paragraph (a)(3) of 
this section.
    (ii) For each appendix I flow monitoring system tested in a 
component-by-component assessment:
    (A) Flowmeter accuracy test data, as specified in paragraph (b)(1) 
or (b)(2) of this section and paragraph (b)(3) or (b)(4) of this 
section;
    (B) Relative accuracy test and bias data for the CO2 (or 
O2) monitor, as specified in paragraphs (a)(5) and (a)(7) of 
this section; and
    (C) Fuel sampling and analysis data, as specified in section 2.3 of 
appendix I to this part.
    (iii) For each appendix I flow monitoring system tested in a system 
relative accuracy assessment:
    (A) Relative accuracy test and bias data for the appendix I flow 
monitoring system, as specified for a flow monitoring system in 
paragraphs (a)(5) and (a)(7) of this section; and
    (B) Fuel sampling and analysis data, as specified in section 2.3 of 
appendix I to this part.
    (e) Compliance dates. Beginning on January 1, 2000, the owner or 
operator shall comply with this section only. Before January 1, 2000, 
the owner or operator shall comply with either this section or 
Sec. 75.56; except that if a regulatory option provided in another 
section of this part 75 is exercised prior to January 1, 2000, then the 
owner or operator shall comply with any provisions of this section that 
support the regulatory option beginning with the date on which the 
option is exercised.
    41. Section 75.60 is amended by revising paragraphs (a), (b)(1), 
and (b)(2) and by adding new paragraphs (b)(3), (b)(4), (b)(5) and 
(b)(6) to read as follows:


Sec. 75.60  General provisions.

    (a) The designated representative for any affected unit subject to 
the requirements of this part shall comply with all reporting 
requirements in this section and with the requirements of Sec. 72.21 of 
this chapter for all submissions.
    (b) * * *
    (1) Initial certifications. The designated representative shall 
submit initial certification applications according to Sec. 75.63.
    (2) Recertifications. The designated representative shall submit 
recertification applications according to Sec. 75.63.
    (3) Monitoring plans. The designated representative shall submit 
monitoring plans according to Sec. 75.62.
    (4) Electronic quarterly reports. The designated representative 
shall submit electronic quarterly reports according to Sec. 75.64.
    (5) Other petitions and communications. The designated 
representative shall submit petitions, correspondence, application 
forms, designated representative signature, and petition-related test 
results in hardcopy to the Administrator. Additional petition 
requirements are specified in Secs. 75.66 and 75.67.
    (6) Quality assurance RATA reports. If requested by the applicable 
EPA Regional Office, appropriate State, and/or appropriate local air 
pollution control agency, the designated representative shall submit 
the quality assurance RATA report within 45 days after completing a 
quality assurance RATA according to section 2.3.1 of appendix B to this 
part, or within 15 days of receiving the request, whichever is later. 
The designated representative shall report the hardcopy information 
required by Sec. 75.59(a)(10) to the applicable EPA Regional Office, 
appropriate State, and/or appropriate local air pollution control 
agency that requested the RATA report.
* * * * *
    42. Section 75.61 is amended by revising paragraphs (a) 
introductory text, (a)(1) introductory text, and (b) and by adding a 
new paragraph (a)(1)(iv) to read as follows:


Sec. 75.61  Notifications.

    (a) Submission. The designated representative for an affected unit 
(or owner or operator, as specified) shall submit notice to the 
Administrator, to the appropriate EPA Regional Office, and to the 
applicable State and local air pollution control agencies for the 
following purposes, as required by this part.
    (1) Initial certification and recertification test notifications. 
The owner or operator or designated representative for an affected unit 
shall submit written notification of initial certification tests, 
recertification tests, and revised test dates as specified in 
Sec. 75.20 for continuous emission monitoring systems, for alternative 
monitoring systems under subpart E of this part, or for excepted 
monitoring systems under appendix E or I to this part, except as 
provided in paragraphs (a)(1)(iv) and (a)(4) of this section and except 
for testing only of the data acquisition and handling system.
* * * * *
    (iv) Waiver from notification requirements. The Administrator, the 
appropriate EPA Regional Office, or the applicable State or local air 
pollution control agency may issue a waiver from the requirement of 
paragraph (a)(1) of this section to provide it for a unit or a group of 
units for one or more recertification tests. The Administrator, the 
appropriate EPA Regional Office, or the applicable State or local air 
pollution control agency may also discontinue the waiver and enforce 
the requirement of paragraph (a)(1) of this section to provide it 
notice of recertification testing for future tests for a unit or a 
group of units.
* * * * *
    (b) The owner or operator or designated representative shall submit 
notification of certification tests and recertification tests for 
continuous opacity monitoring systems as specified in Sec. 75.20(c)(8) 
to the State or local air pollution control agency.
* * * * *
    43. Section 75.62 is amended by revising paragraphs (a) and (c) to 
read as follows:


Sec. 75.62  Monitoring plan.

    (a) Submission.--(1) Electronic. Using the format specified in 
paragraph (c) of this section, the designated representative for an 
affected unit shall submit a complete, electronic, up-to-date 
monitoring plan file (except for hardcopy portions identified in 
paragraph (a)(2) of this section) to the Administrator: No later than 
45 days prior to the initial certification test; at the time of 
recertification application submission; and in each electronic 
quarterly report.
    (2) Hardcopy. The designated representative shall submit all of the 
hardcopy information required under Sec. 75.53 to the appropriate EPA 
Regional Office and the appropriate State and/or local air pollution 
control agency prior to initial certification. Thereafter, the

[[Page 28149]]

designated representative shall submit hardcopy information only if 
that portion of the monitoring plan is revised. The designated 
representative shall submit the required hardcopy information: no later 
than 45 days prior to the initial certification test; with any 
recertification application, if a hardcopy monitoring plan change is 
associated with the recertification event; and within 30 days of any 
other event with which a hardcopy monitoring plan change is associated, 
pursuant to Sec. 75.53(b).
* * * * *
    (c) Format. Each monitoring plan shall be submitted in a format 
specified by the Administrator.
    44. Section 75.63 is revised to read as follows:


Sec. 75.63  Initial certification or recertification application.

    (a) Submission. The designated representative for an affected unit 
or a combustion source shall submit applications and reports as 
follows:
    (1) Initial certifications. (i) Within 45 days after completing all 
initial certification tests, submit to the Administrator the electronic 
information required by paragraph (b)(1) of this section and a hardcopy 
certification application form (EPA form 7610-14). Except for subpart E 
applications or unless specifically requested by the Administrator, do 
not submit a hardcopy of the test data and results to the 
Administrator.
    (ii) Within 45 days after completing all initial certification 
tests, submit the hardcopy information required by paragraph (b)(2) of 
this section to the applicable EPA Regional Office and the appropriate 
State and/or local air pollution control agency.
    (iii) For units for which the owner or operator is applying for 
certification approval of the optional excepted methodology under 
Sec. 75.19 for low mass emissions units, submit:
    (A) To the Administrator, the electronic information required by 
paragraph (b)(1)(i) of this section, the hardcopy information required 
by paragraph (b)(3) of this section, and a hardcopy certification 
application form (EPA form 7610-14) signed by the designated 
representative.
    (B) To the applicable EPA Regional Office and appropriate State 
and/or local air pollution control agency, the hardcopy information 
required by paragraphs (b)(2)(i), (iii), and (iv) of this section and 
by paragraph (b)(3) of this section.
    (2) Recertifications. (i) Within 45 days after completing all 
recertification tests, submit to the Administrator the electronic 
information required by (b)(1) of this section and a hardcopy 
certification application form (EPA form 7610-14). Except for subpart E 
applications or unless specifically requested by the Administrator, do 
not submit a hardcopy of the test data and results to the 
Administrator.
    (ii) Within 45 days after completing all recertification tests, 
submit the hardcopy information required by paragraph (b)(2) of this 
section to the applicable EPA Regional Office and the appropriate State 
and/or local air pollution control agency. The applicable EPA Regional 
Office or appropriate State or local air pollution control agency may 
waive the requirement for submission to it of a hardcopy 
recertification. The applicable EPA Regional Office or the appropriate 
State or local air pollution control agency may also discontinue the 
waiver and enforce the requirement of this paragraph (a)(2)(ii) to 
provide a hardcopy report of the recertification test data and results.
    (iii) Notwithstanding the requirements of paragraphs (a)(2)(i) and 
(a)(2)(ii) of this section, for an event for which the Administrator 
determines that only diagnostic tests (see Sec. 75.20(b)) are required 
rather than a RATA, an accuracy test of the fuel flowmeter, or a retest 
of the appendix E NOX correlation curve, no hardcopy 
submittal of any kind is required; however, the results of all 
diagnostic test(s) shall be submitted in the electronic quarterly 
report required under Sec. 75.64. For DAHS (missing data and formula) 
verifications, neither a hardcopy nor an electronic submittal of any 
kind is required; these test results shall be kept on-site, suitable 
for inspection.
    (b) Contents. Each application for initial certification or 
recertification shall contain the following information, as applicable:
    (1) Electronic. (i) A complete, up-to-date version of the 
electronic portion of the monitoring plan, according to Sec. 75.53(c) 
and (d), or Sec. 75.53(e) and (f), as applicable, in the format 
specified in Sec. 75.62(c).
    (ii) The results of the test(s) required by Sec. 75.20, including 
the type of test conducted, testing date, information required by 
Sec. 75.56 or Sec. 75.59, as applicable, and the results of any failed 
tests that affect data validation.
    (2) Hardcopy. (i) Any changed portions of the hardcopy monitoring 
plan information required under Sec. 75.53(c) and (d), or Sec. 75.53(e) 
and (f), as applicable.
    (ii) The results of the test(s) required by Sec. 75.20, including 
the type of test conducted, testing date, information required by 
Sec. 75.59(a)(10), and the results of any failed tests that affect data 
validation.
    (iii) Certification or recertification application form (EPA form 
7610-14).
    (iv) Designated representative signature.
    (3) If the owner or operator is applying to use the optional low 
mass emissions excepted methodology in Sec. 75.19(c) in lieu of a 
certified monitoring system,
    (i) A statement that the unit burns only natural gas or fuel oil 
and a list of the fuels that are burned or a statement that the unit is 
projected to burn only natural gas or fuel oil and a list of the fuels 
that are projected to be burned;
    (ii) A statement that the unit meets the applicability requirements 
in Sec. 75.19(a) and (b); and
    (iii) Any unit historical actual and projected emissions data and 
calculated emissions data demonstrating that the affected unit 
qualifies as a low mass emissions unit under Sec. 75.19(a) and (b).
    (c) Format. The electronic portion of each certification or 
recertification application shall be submitted in a format to be 
specified by the Administrator. The hardcopy test results shall be 
submitted in a format suitable for review and shall include the 
information in Sec. 75.59(a)(10).
    45. Section 75.64 is amended by revising paragraphs (a) 
introductory text, (d), and (e); by redesignating existing paragraphs 
(a)(1), (a)(2), (a)(3), (a)(4), (a)(5), and (a)(6) as paragraphs 
(a)(2), (a)(3), (a)(4), (a)(5),(a)(6) and (a)(8), respectively; by 
revising newly designated paragraphs (a)(2), and (a)(4); by adding new 
paragraphs (a)(1), (a)(7), (a)(9), (f), and (g); and by removing the 
third sentence in paragraph (c), to read as follows:


Sec. 75.64  Quarterly reports.

    (a) Electronic submission. The designated representative for an 
affected unit shall electronically report the data and information in 
paragraphs (a), (b), and (c) of this section to the Administrator 
quarterly, beginning with the data from the later of: the last 
(partial) calendar quarter of 1993 (where the calendar quarter data 
begins at November 15, 1993), the calendar quarter corresponding to the 
date of provisional certification, or the calendar quarter 
corresponding to the relevant deadline for initial certification in 
Sec. 75.4(a), (b), or (c), whichever quarter is earlier (where the 
report contains hourly data beginning with the hour of provisional 
certification or the hour corresponding to the relevant certification 
deadline, whichever is earlier). For an affected unit subject to

[[Page 28150]]

Sec. 75.4(d) that is shutdown on the relevant compliance date in 
Sec. 75.4(a), the owner or operator shall submit quarterly reports for 
the unit beginning with the data from the quarter in which the owner or 
operator recommences commercial operation of the unit (where the report 
contains hourly data beginning with the first hour of recommenced 
commercial operation of the unit). For any provisionally-certified 
monitoring system, Sec. 75.20(a)(3) shall apply for initial 
certifications, and Sec. 75.20(b)(5) shall apply for recertifications. 
Each electronic report must be submitted to the Administrator within 30 
days following the end of each calendar quarter. Each electronic report 
shall include the date of report generation, for the information 
provided in paragraphs (a)(2) through (a)(9) of this section, and shall 
also include for each affected unit (or group of units using a common 
stack):
    (1) Facility information:
    (i) Identification, including:
    (A) Facility/ORISPL number;
    (B) Calendar quarter and year data contained in the report; and
    (C) EDR version used for the report.
    (ii) Location, including:
    (A) Plant name and facility ID;
    (B) EPA AIRS facility system ID;
    (C) State facility ID;
    (D) Source category/type;
    (E) Primary SIC code;
    (F) State postal abbreviation;
    (G) County code; and
    (H) Latitude and longitude.
    (2) The information and hourly data required in Secs. 75.53 through 
75.59, excluding:
    (i) Descriptions of adjustments, corrective action, and 
maintenance;
    (ii) Information which is incompatible with electronic reporting 
(e.g., field data sheets, lab analyses, quality control plan);
    (iii) Opacity data listed in Sec. 75.54(f) or Sec. 75.57(f), and in 
Sec. 75.59(a)(9);
    (iv) For units with SO2 or NOX add-on 
emission controls that do not elect to use the approved site-specific 
parametric monitoring procedures for calculation of substitute data, 
the information in Sec. 75.55(b)(3) or Sec. 75.58(b)(3);
    (v) The information recorded under Sec. 75.56(a)(7) for the period 
prior to January 1, 2000;
    (vi) Information required by Sec. 75.54(g) or Sec. 75.57(h) 
concerning the causes of any missing data periods and the actions taken 
to cure such causes; and
    (vii) Hardcopy monitoring plan information required by Sec. 75.53 
and hardcopy test data and results required by Sec. 75.56 or 
Sec. 75.59;
    (viii) Records of flow polynomial equations and numerical values 
required by Sec. 75.56(a)(5)(vii) or Sec. 75.59(a)(5)(vi);
    (ix) Daily fuel sampling information required by 
Sec. 75.58(c)(3)(i) for units using assumed values under appendix D;
    (x) Information required by Secs. 75.59(b)(1)(ii), (iii), (iv), and 
(x), and (b)(2) concerning fuel flowmeter accuracy tests and 
transmitter/transducer accuracy tests;
    (xi) Stratification test results required as part of the RATA 
supplementary records under Secs. 75.56(a)(7) or 75.59(a)(7);
    (xii) Data and results of RATAs that are aborted or invalidated due 
to problems with the reference method or operational problems with the 
unit and data and results of linearity checks that are aborted or 
invalidated due to operational problems with the unit; and
    (xiii) The summary of data used to determine the percentage of 
historical usage of each load level as required under 
Sec. 75.59(a)(8)(iv).
    (xiv) Supplementary RATA information required under 
Secs. 75.59(a)(7)(iv)(A), (U), (V), (W), (X), and (Y).
* * * * *
    (4) Average NOX emission rate (lb/mmBtu, rounded to the 
nearest hundredth prior to January 1, 2000 and to the nearest 
thousandth on and after January 1, 2000) during the quarter and 
cumulative NOX emission rate for the calendar year.
* * * * *
    (7) Unit/stack/pipe operating hours for quarter and cumulative 
unit/stack/pipe operating hours for calendar year.
* * * * *
    (9) For low mass emissions units for which the owner or operator is 
using the optional low mass emissions methodology in Sec. 75.19(c) to 
calculate NOX mass emissions, the designated representative 
must also report tons (rounded to the nearest tenth) of NOX 
emitted during the quarter and cumulative NOX mass emissions 
for the calendar year.
* * * * *
    (d) Electronic format. Each quarterly report shall be submitted in 
a format to be specified by the Administrator, including both 
electronic submission of data and electronic or hardcopy submission of 
compliance certifications.
    (e) Phase I qualifying technology reports. In addition to reporting 
the information in paragraphs (a), (b), and (c) of this section, the 
designated representative for an affected unit on which SO2 
emission controls have been installed and operated for the purpose of 
meeting qualifying Phase I technology requirements pursuant to 
Sec. 72.42 of this chapter shall also submit reports documenting the 
measured percent SO2 emissions removal to the Administrator 
on a quarterly basis, beginning the first quarter of 1997 and 
continuing through the fourth quarter of 1999. Each report shall 
include all measurements and calculations necessary to substantiate 
that the qualifying technology achieves the required percent reduction 
in SO2 emissions.
    (f) Method of submission. Beginning with the quarterly report for 
the first quarter of the year 2000, all quarterly reports shall be 
submitted to EPA by direct computer-to-computer electronic transfer via 
modem and EPA-provided software, unless otherwise approved by the 
Administrator.
    (g) Any cover letter text accompanying a quarterly report shall 
either be submitted in hardcopy to the Agency or be provided in 
electronic format compatible with the other data required to be 
reported under this section.
    46. Section 75.65 is revised to read as follows:


Sec. 75.65  Opacity reports.

    The owner or operator or designated representative shall report 
excess emissions of opacity recorded under Sec. 75.54(f) or 
Sec. 75.57(f), as applicable, to the applicable State or local air 
pollution control agency.
    47. Section 75.66 is amended by revising paragraphs (a) and the 
first sentence of (e) introductory text; by redesignating paragraph (i) 
as paragraph (m) and revising it; and by adding paragraphs (i) through 
(l), to read as follows:


Sec. 75.66  Petitions to the Administrator.

    (a) General. The designated representative for an affected unit 
subject to the requirements of this part may submit a petition to the 
Administrator requesting that the Administrator exercise his or her 
discretion to approve an alternative to any requirement prescribed in 
this part or incorporated by reference in this part. Any such petition 
shall be submitted in accordance with the requirements of this section. 
The designated representative shall comply with the signatory 
requirements of Sec. 72.21 of this chapter for each submission.
* * * * *
    (e) Parametric monitoring procedure petitions. The designated 
representative for an affected unit may submit a petition to the 
Administrator, where each petition shall contain the information 
specified in Sec. 75.55(b) or

[[Page 28151]]

Sec. 75.58(b), as applicable, for the use of a parametric monitoring 
method. * * *
* * * * *
    (i) Emergency fuel petition. The designated representative for an 
affected unit may submit a petition to the Administrator to use the 
emergency fuel provisions in Section 2.1.4 of Appendix E of this part. 
The designated representative shall include the following information 
in the petition:
    (1) Identification of the affected unit(s);
    (2) A procedure for determining the NOX emission rate 
for the unit when the emergency fuel is combusted; and
    (3) A demonstration that the permit restricts use of the fuel to 
emergencies only.
    (j) Petition for alternative method of accounting for emissions 
prior to completion of certification tests. The designated 
representative for an affected unit may submit a petition to the 
Administrator to use an alternative to the procedures in Sec. 75.4 
(d)(3), (e)(3), (f)(3) and/or (g)(3) to account for emissions during 
the period between the compliance date for a unit and the completion of 
certification testing for that unit. The designated representative 
shall include:
    (1) Identification of the affected unit(s);
    (2) A detailed explanation of the alternative method to account for 
emissions of the following parameters, as applicable: SO2 
mass emissions (in lbs), NOX emission rate (in lbs/mmbtu), 
CO2 mass emissions (in lbs) and, if the unit is subject to 
the requirements of subpart H of this part, NOX mass 
emissions (in lbs); and
    (3) A demonstration that the proposed alternative does not 
underestimate emissions.
    (k) Petition for an alternative to the stabilization criteria for 
the cycle time test in section 6.4 of Appendix A of this part. The 
designated representative for an affected unit may submit a petition to 
the Administrator to use an alternative stabilization criteria for the 
cycle time test in section 6.4 of Appendix A of this part, if the 
installed monitoring system does not record data in 1-minute or 3-
minute intervals. The designated representative shall provide a 
description of the alternative criteria.
    (l) Petition for an alternative to the maximum rated hourly heat 
input used to determine emissions under the low mass emissions excepted 
methodology in Sec. 75.19. The designated representative for an 
affected unit may submit a petition to the Administrator to use an 
alternative to the maximum rated hourly heat input to determine 
emissions under the low mass emissions excepted methodology set forth 
in Sec. 75.19. The designated representative shall provide the 
following information:
    (1) Identification of the affected unit(s);
    (2) Information demonstrating that the maximum rated hourly heat 
input, as defined in Sec. 72.2 of this chapter, is not representative 
of the unit's current capabilities because modifications have been made 
to the unit, limiting its capacity permanently; and
    (3) Information documenting that the proposed alternative maximum 
heat input is representative of the unit's highest potential heat 
input.
    (m) Any other petitions to the Administrator under this part. 
Except for petitions addressed in paragraphs (b) through (l) of this 
section, any petition submitted under this paragraph shall include 
sufficient information for the evaluation of the petition, including, 
at a minimum, the following information:
    (1) Identification of the affected unit(s);
    (2) A detailed explanation of why the proposed alternative is being 
suggested in lieu of the requirement;
    (3) A description and diagram of any equipment and procedures used 
in the proposed alternative, if applicable;
    (4) A demonstration that the proposed alternative is consistent 
with the purposes of the requirement for which the alternative is 
proposed and is consistent with the purposes of this part and of 
section 412 of the Act and that any adverse effect of approving such 
alternative will be de minimis; and
    (5) Any other relevant information that the Administrator may 
require.
    48. Subpart H is added to read as follows:

Subpart H--NOX Mass Emissions Provisions

Sec.
75.70  NOX mass emissions provisions.
75.71  Specific provisions for monitoring NOX emission 
rate and heat input for the purpose of calculating NOX 
mass emissions.
75.72  Determination of NOX mass emissions.
75.73  Recordkeeping and reporting.

Subpart H--NOX Mass Emissions Provisions


Sec. 75.70  NOX mass emissions provisions.

    (a) The owner or operator of a unit shall comply with the 
requirements of this subpart only if such compliance is required by an 
applicable state or federal NOX mass emission reduction 
program that incorporates by reference, or otherwise adopts the 
requirements of, this subpart. For purposes of this subpart, the term 
``affected unit'' shall mean any unit that is subject to a state or 
federal NOX mass emission reduction program requiring 
compliance with this subpart, the term ``nonaffected unit'' shall mean 
any unit that is not subject to such a program, the term ``permitting 
authority'' shall mean the permitting authority under an applicable 
state or federal NOX mass emission reduction program that 
adopts the requirements of this subpart, and the term ``designated 
representative'' shall mean the responsible party under the applicable 
state or federal NOX mass emission reduction program that 
adopts the requirements of this subpart. In addition, as set forth in 
this subpart, the provisions of subparts A, C, D, E, F, and G and 
appendices A through G applicable to NOX emission rate and 
heat input shall apply to the owner or operator of a unit required to 
meet the requirements of this subpart by a state or federal 
NOX mass emission reduction program, except that the term 
``affected unit'' shall mean any unit that is subject to a state or 
federal NOX mass emission reduction program requiring 
compliance with this subpart, the term ``permitting authority'' shall 
mean the permitting authority under an applicable state or federal 
NOX mass emission reduction program that adopts the 
requirements of this subpart, and the term ``designated 
representative'' shall mean the responsible party under the applicable 
state or federal NOX mass emission reduction program that 
adopts the requirements of this subpart.
    (b) Compliance dates. The owner or operator of an affected unit 
shall meet the compliance deadlines established by an applicable state 
or federal NOX mass emission reduction program that adopts 
the requirements of this subpart.
    (c) Prohibitions. (1) No owner or operator of an affected unit or a 
non-affected unit under Sec. 75.72(b)(2)(ii) shall use any alternative 
monitoring system, alternative reference method, or any other 
alternative for the required continuous emission monitoring system 
without having obtained prior written approval in accordance with 
paragraph (g) of this section.
    (2) No owner or operator of an affected unit or a non-affected unit 
under Sec. 75.72(b)(2)(ii) shall operate the unit so as to discharge, 
or allow to be discharged emissions of NOX to the atmosphere 
without accounting for all such emissions in accordance with the 
applicable provisions of this part.
    (3) No owner or operator of an affected unit or a non-affected unit 
under Sec. 75.72(b)(2)(ii) shall disrupt the continuous emission 
monitoring system, any portion thereof, or any other

[[Page 28152]]

approved emission monitoring method, and thereby avoid monitoring and 
recording NOX mass emissions discharged into the atmosphere, 
except for periods of recertification or periods when calibration, 
quality assurance testing, or maintenance is performed in accordance 
with the applicable provisions of this part.
    (4) No owner or operator of an affected unit or a non-affected unit 
under Sec. 75.72(b)(2)(ii) shall retire or permanently discontinue use 
of the continuous emission monitoring system, any component thereof, or 
any other approved emission monitoring system under this part, except 
under any one of the following circumstances:
    (i) During the period that the unit is covered by a retired unit 
exemption under Sec. 96.5 that is in effect;
    (ii) The owner or operator is monitoring NOX mass 
emissions from the affected unit with another certified monitoring 
system approved, in accordance with the provisions of paragraph (d) of 
this section; or
    (iii) The designated representative submits notification of the 
date of certification testing of a replacement monitoring system in 
accordance with Sec. 75.73(d)(5).
    (d) Initial certification and recertification procedures. (1) The 
owner or operator of an affected unit that is subject to an Acid Rain 
emissions limitation shall comply with the initial certification and 
recertification procedures of this part except that:
    (i) The owner or operator shall meet any additional requirements 
set forth in an applicable state or federal NOX mass 
emission reduction program that adopts the requirements of this 
subpart.
    (ii) For any additional NOX emission rate CEMS required 
under the common stack provisions in Sec. 75.72, the owner or operator 
shall meet the requirements of paragraph (d)(2) of this section.
    (2) The owner or operator of an affected unit that is not subject 
to an Acid Rain emissions limitation shall comply with the initial 
certification and recertification procedures established by an 
applicable state or federal NOX mass emission reduction 
program that adopts the requirements of this subpart. The owner or 
operator of an affected unit that is subject to an Acid Rain emissions 
limitation shall, for any additional NOX emission rate CEMS 
required under the common stack provisions in Sec. 75.72, comply with 
the initial certification and recertification procedures established by 
an applicable state or federal NOX mass emission reduction 
program that adopts the requirements of this subpart.
    (e) Quality assurance and quality control requirements. The owner 
or operator shall meet the quality assurance and quality control 
requirements in Sec. 75.21.
    (f) Missing data procedures. Except as provided in Sec. 75.34, the 
owner or operator shall provide substitute data for each affected unit 
and each non-affected unit under Sec. 75.72(b)(2)(ii) using a 
continuous emissions monitoring system in accordance with the missing 
data procedures in subpart D of this part whenever the unit combusts 
fuel and:
    (1) A valid quality assured hour of NOX emission rate 
data (in lb/mmBtu) has not been measured and recorded for an affected 
unit or non-affected unit under Sec. 75.72(b)(2)(ii) by a certified 
NOX continuous emission monitoring system or by an approved 
monitoring system under subpart E of this part;
    (2) A valid quality assured hour of flow data (in scfh) has not 
been measured and recorded for an affected unit or non-affected unit 
under Sec. 75.72(b)(2)(ii) from a certified flow monitor or by an 
approved alternative monitoring system under subpart E of this part; or
    (3) A valid quality assured hour of heat input data (in mmBtu) has 
not been measured and recorded for an affected unit from a certified 
flow monitor and a certified diluent (CO2 or O2) 
monitor or by an approved alternative monitoring system under subpart E 
of this part or by an accepted monitoring system under appendix D to 
this part.
    (g) Petitions. (1) The owner or operator of an affected unit that 
is subject to an Acid Rain emissions limitation may submit a petition 
to the Administrator requesting an alternative to any requirement of 
this subpart. Such a petition shall meet the requirements of Sec. 75.66 
and any additional requirements established by an applicable state or 
federal NOX mass emission reduction program that adopts the 
requirements of this subpart. Use of an alternative to any requirement 
of this subpart is in accordance with this subpart and with such state 
or federal NOX mass emission reduction program only to the 
extent that the petition is approved by the Administrator, in 
consultation with the permitting authority.
    (2) Notwithstanding paragraph (g)(1) of this section, petitions 
requesting an alternative to a requirement concerning any additional 
CEMS required solely to meet the common stack provisions of Sec. 75.72, 
shall be submitted to the permitting authority and the Administrator 
and shall be governed by paragraph (g)(3)(ii) of this section. Such a 
petition shall meet the requirements of Sec. 75.66 and any additional 
requirements established by an applicable state or federal 
NOX mass emission reduction program that adopts the 
requirements of this subpart.
    (3)(i) The owner or operator of an affected unit that is not 
subject to an Acid Rain emissions limitation may submit a petition to 
the permitting authority and the Administrator requesting an 
alternative to any requirement of this subpart. Such a petition shall 
meet the requirements of Sec. 75.66 and any additional requirements 
established by an applicable state or federal NOX mass 
emission reduction program that adopts the requirements of this 
subpart.
    (ii) Use of an alternative to any requirement of this subpart is in 
accordance with this subpart only to the extent that it is approved by 
both the permitting authority and the Administrator.


Sec. 75.71  Specific provisions for monitoring NOX emission 
rate and heat input for the purpose of calculating NOX mass 
emissions.

    (a) Coal-fired units. The owner or operator of an affected unit 
shall meet the general operating requirements in Sec. 75.10 for a 
NOX continuous emission monitoring system (including a 
NOX pollutant concentration monitor and an O2- or 
CO2-diluent gas monitor) to measure NOX emission 
rate and for a continuous flow monitoring system and an O2- 
or CO2-diluent gas monitor to measure heat input, except as 
provided by the Administrator in accordance with subpart E of this 
part.
    (b) Moisture correction. If a correction for the stack gas moisture 
content is needed to properly calculate the NOX emission 
rate in lb/mmBtu (i.e., if the NOX pollutant concentration 
monitor measures on a different moisture basis from the diluent 
monitor), the owner or operator of an affected unit shall install, 
operate, maintain, and quality assure a continuous moisture monitoring 
system, as defined in Sec. 75.11(b).
    (c) Gas-fired nonpeaking units or oil-fired non-peaking units. The 
owner or operator of an affected unit that qualifies as a gas-fired or 
oil-fired unit but not as a peaking unit, as defined in Sec. 72.2 of 
this chapter, based on information submitted by the designated 
representative in the monitoring plan shall either:
    (1) Meet the requirements of paragraph (a) of this section and, if 
applicable, paragraph (b) of this section; or
    (2) Meet the general operating requirements in Sec. 75.10 for a 
NOX continuous emission monitoring system, except as 
provided, where applicable, in paragraph (e)(2) of this section or by 
the

[[Page 28153]]

Administrator in accordance with subpart E of this part, and use the 
procedures specified in appendix D to this part for determining hourly 
heat input. However, the heat input apportionment provisions in section 
2.1.2 of appendix D to this part shall not be used to meet the 
NOX mass reporting provisions of this subpart.
    (d) Peaking units that combust natural gas or fuel oil. The owner 
or operator of an affected unit that combusts only natural gas or fuel 
oil and that qualifies as a peaking unit, as defined in Sec. 72.2 of 
this chapter, based on information submitted by the designated 
representative in the monitoring plan shall either:
    (1) Meet the requirements of paragraph (c) of this section; or
    (2) Use the procedures in appendix D to this part for determining 
hourly heat input and the procedure specified in appendix E to this 
part for estimating hourly NOX emission rate. However, the 
heat input apportionment provisions in section 2.1.2 of appendix D to 
this part shall not be used to meet the NOX mass reporting 
provisions of this subpart. In addition, if after certification of an 
excepted monitoring system under appendix E to this part, a unit's 
operations exceed a capacity factor of 20.0 percent in any calender 
year or exceed a capacity factor of 10.0 percent averaged over three 
years, the owner or operator shall meet the requirements of paragraph 
(c) of this section or, if applicable, paragraph (e) of this section by 
no later than December 31 of the following calender year.
    (e) Low mass emissions units. Notwithstanding the requirements of 
paragraphs (c) and (d) of this section, the owner or operator of an 
affected unit that qualifies as a low mass emissions unit under 
Sec. 75.19(a) shall comply with one of the following:
    (1) Meet the applicable requirements specified in paragraph (c) or 
(d) of this section for monitoring NOX emission rate and 
heat input; or
    (2) Use the low mass emissions excepted methodology in 
Sec. 75.19(c) for estimating hourly emission rate, hourly heat input, 
and hourly NOX mass emissions.
    (f) Other units. The owner or operator of an affected unit that 
combusts wood, refuse, or other materials shall comply with the 
monitoring provisions specified in paragraph (a) of this section and, 
where applicable, paragraph (b) of this section.


Sec. 75.72  Determination of NOX mass emissions.

    The owner or operator of an affected unit shall calculate hourly 
NOX mass emissions (in lbs) by multiplying the hourly 
NOX emission rate (in lbs/mmBtu) by the hourly heat input 
(in mmBtu/hr) and the hourly operating time (in hr). The owner or 
operator shall also calculate quarterly and cumulative year-to-date 
NOX mass emissions and cumulative NOX mass 
emissions for the ozone season (in tons) by summing the hourly 
NOX mass emissions according to the procedures in section 8 
of appendix F to this part.
    (a) Unit utilizing common stack with other affected unit(s). When 
an affected unit utilizes a common stack with one or more affected 
units, but no nonaffected units, the owner or operator shall either:
    (1) Record the combined NOX mass emissions for the units 
exhausting to the common stack, install, certify, operate, and maintain 
a NOX continuous emissions monitoring system in the common 
stack and:
    (i) Install, certify, operate, and maintain a continuous flow 
monitoring system at the common stack; or
    (ii) If all of the units using the common stack are eligible to use 
the procedures in appendix D to this part, use the procedures in 
appendix D to this part to determine heat input for each affected unit 
and use the combined heat input of all of the units exhausting to the 
common stack for calculating NOX mass emissions; however, 
the heat input apportionment provisions in section 2.1.2 of appendix D 
to this part shall not be used to meet the NOX mass 
reporting provisions of this subpart; or
    (2) Install, certify, operate, and maintain a NOX 
continuous emissions monitoring system in the duct to the common stack 
from each affected unit and:
    (i) Install, certify, operate, and maintain a flow monitor in the 
duct to the common stack from each affected unit; or
    (ii)(A) For any unit using the common stack and eligible to use the 
procedures in appendix D to this part, use the procedures in appendix D 
to determine heat input for that affected unit. However, the heat input 
apportionment provisions in section 2.1.2 of appendix D to this part 
shall not be used to meet the mass reporting provisions of this 
subpart; and
    (B) Install, certify, operate, and maintain a flow monitor in the 
duct to the common stack for each remaining affected unit.
    (b) Unit utilizing common stack with nonaffected unit(s). When one 
or more affected units utilizes a common stack with one or more 
nonaffected units, the owner or operator shall either:
    (1) Install, certify, operate, and maintain a NOX 
continuous emission monitoring system in the duct to the common stack 
from each affected unit; and
    (i) Install, certify, operate, and maintain a continuous flow 
monitoring system in the duct to the common stack from each affected 
unit; or
    (ii)(A) For any unit using the common stack and eligible to use the 
procedures in appendix D to this part, use the procedures in appendix D 
to determine heat input for that affected unit; however, the heat input 
apportionment provisions in section 2.1.2 of appendix D to this part 
shall not be used to meet the mass reporting provisions of this 
subpart; and
    (B) Install, certify, operate, and maintain a flow monitor in the 
duct to the common stack for each remaining affected unit that exhausts 
to the common stack; or
    (2) Install, certify, operate, and maintain a NOX 
continuous emission monitoring system in the common stack; and
    (i) Designate the nonaffected units as affected units in accordance 
with the applicable state or federal NOX mass emissions 
reduction program and meet the requirements of paragraph (a)(1) of this 
section; or
    (ii)(A) Install, certify, operate, and maintain a continuous flow 
monitoring system in the common stack and a NOX continuous 
emission monitoring system in the duct to the common stack from each 
nonaffected unit and either install, certify, operate, and maintain a 
continuous flow monitoring system in the duct from each nonaffected 
unit or, for any nonaffected unit exhausting to the common stack and 
otherwise eligible to use the procedures in appendix D to this part, 
determine heat input using the procedures in appendix D for that 
nonaffected unit (however, the heat input apportionment provisions in 
section 2.1.2 of appendix D to this part shall not be used to meet the 
NOX mass reporting provisions of this subpart), and for any 
remaining nonaffected unit that exhausts to the common stack, install, 
certify, operate, and maintain a flow monitor in the duct to the common 
stack; and
    (B) Submit a petition to the permitting authority and the 
Administrator to allow a method of calculating and reporting the 
NOX mass emissions from the affected units as the difference 
between NOX mass emissions measured in the common stack and 
NOX mass emissions measured in the ducts of the nonaffected 
units, not to be reported as an hourly value less than zero. The 
permitting authority and the

[[Page 28154]]

Administrator may approve such a method whenever the designated 
representative demonstrates, to the satisfaction of the permitting 
authority and the Administrator, that the method ensures that the 
NOX mass emissions from the affected units are not 
underestimated; or
    (iii) Install a continuous flow monitoring system in the common 
stack and record the combined emissions from all units as the combined 
NOX mass emissions for the affected units for recordkeeping 
and compliance purposes; or
    (iv) Submit a petition to the permitting authority and the 
Administrator to allow use of a method for apportioning NOX 
mass emissions measured in the common stack to each of the units using 
the common stack and for reporting the NOX mass emissions. 
The permitting authority and the Administrator may approve such a 
method whenever the designated representative demonstrates, to the 
satisfaction of the permitting authority and the Administrator, that 
the method ensures that the NOX mass emissions from the 
affected units are not underestimated.
    (c) Unit with bypass stack. Whenever any portion of the flue gases 
from an affected unit can be routed to avoid the installed 
NOX continuous emissions monitoring system, the owner and 
operator shall either:
    (1) Install, certify, operate, and maintain a NOX 
continuous emissions monitoring system and a continuous flow monitoring 
system on the bypass flue, duct, or stack gas stream and calculate 
NOX mass emissions for the unit as the sum of the emissions 
recorded by all required monitoring systems; or
    (2) Monitor NOX mass emissions on the bypass flue, duct, 
or stack gas stream using the reference methods in Sec. 75.22(b) for 
NOX concentration, flow, and diluent and calculate 
NOX mass emissions for the unit as the sum of the emissions 
recorded by the installed monitoring systems on the main stack and the 
emissions measured by the reference method monitoring systems.
    (d) Unit with multiple stacks. Notwithstanding Sec. 75.17(c), when 
the flue gases from an affected unit utilize two or more ducts feeding 
into two or more stacks (which may include flue gases from other 
affected or nonaffected unit(s)), or when the flue gases from an 
affected unit utilize two or more ducts feeding into a single stack and 
the owner or operator chooses to monitor in the ducts rather than in 
the stack, the owner or operator shall either:
    (1) Install, certify, operate, and maintain a NOX 
continuous emission monitoring system and a continuous flow monitoring 
system in each duct feeding into the stack or stacks and determine 
NOX mass emissions from each affected unit using the stack 
or stacks as the sum of the NOX mass emissions recorded for 
each duct; or
    (2) Install, certify, operate, and maintain a NOX 
continuous emissions monitoring system and a continuous flow monitoring 
system in each stack, and determine NOX mass emissions from 
the affected unit using the sum of the NOX mass emissions 
recorded for each stack, except that where another unit also exhausts 
flue gases to one or more of the stacks, the owner or operator shall 
also comply with the applicable requirements of paragraphs (a) and (b) 
of this section to determine and record NOX mass emissions 
from the units using that stack; or
    (3) If the unit is eligible to use the procedures in appendix D to 
this part, install, certify, operate, and maintain a NOX 
continuous emissions monitoring system in one of the ducts feeding into 
the stack or stacks and use the procedures in appendix D to this part 
to determine heat input for the unit, provided that:
    (i) There are no add-on NOX controls at the unit;
    (ii) The unit is not capable of emitting solely through an 
unmonitored stack (i.e., has no dampers); and
    (iii) The owner or operator of the unit demonstrates to the 
satisfaction of the permitting authority and the Administrator that the 
NOX emission rate in the monitored duct or stack is 
representative of the NOX emission rate in each duct or 
stack.


Sec. 75.73  Recordkeeping and reporting.

    (a) General recordkeeping provisions. The owner or operator of any 
affected unit shall maintain for each affected unit and each non-
affected unit under Sec. 75.72(b)(2)(ii) a file of all measurements, 
data, reports, and other information required by this part at the 
source in a form suitable for inspection for at least three (3) years 
from the date of each record. Except for the certification data 
required in Sec. 75.57(a)(4) and the initial submission of the 
monitoring plan required in Sec. 75.57(a)(5), the data shall be 
collected beginning with the earlier of the date of provisional 
certification or the deadline in Sec. 75.70. The certification data 
required in Sec. 75.57(a)(4) shall be collected beginning with the date 
of the first certification test performed.
    The file shall contain the following information:
    (1) The information required in Secs. 75.57(a)(2), (a)(4), (a)(5), 
(a)(6), (b), (c)(2), (d), (g), and (h);
    (2) The information required in Secs. 75.58 (b), (d), and (g);
    (3) For each hour when the unit is operating, NOX mass 
emissions, calculated in accordance with section 8.1 of appendix F to 
this part;
    (4) During the second and third calendar quarters, cumulative ozone 
season heat input and cumulative ozone season operating hours;
    (5) Heat input and NOX methodologies for the hour;
    (6) Specific heat input record provisions for gas-fired or oil-
fired units using the procedures in appendix D to this part. In lieu of 
the information required in Sec. 75.57(c)(2), the owner or operator 
shall record the following information in this paragraph for each 
affected gas-fired or oil-fired unit and each non-affected gas-or oil-
fired unit under Sec. 75.72(b)(2)(ii) for which the owner or operator 
is using the procedures in appendix D to this part for estimating heat 
input:
    (i) For each hour when the unit is combusting oil:
    (A) Date and hour;
    (B) Hourly average flow rate of oil, while the unit combusts oil 
(in gal/hr, lb/hr, m3/hr, or bbl/hr, rounded to the nearest 
tenth) (flag value if derived from missing data procedures);
    (C) Method of oil sampling (flow proportional, continuous drip, as 
delivered, manual from storage tank, or daily manual);
    (D) Mass rate of oil combusted each hour (in lb/hr, rounded to the 
nearest tenth) (flag value if derived from missing data procedures);
    (E) For units using volumetric oil flowmeters, density of oil (flag 
value if derived from missing data procedures);
    (F) Gross calorific value (heat content) of oil used to determine 
heat input (in Btu/mass unit) (flag value if derived from missing data 
procedures);
    (G) Hourly heat input rate from oil, according to procedures in 
appendix F to this part (in mmBtu/hr, to the nearest tenth);
    (H) Fuel usage time for combustion of oil during the hour (rounded 
up to the nearest fraction of an hour (in equal increments that can 
range from one hundredth to one quarter of an hour, at the option of 
the owner or operator)) (flag to indicate multiple/single fuel types 
combusted); and
    (I) Monitoring system identification code;
    (ii) For gas-fired units or oil-fired units, using the procedures 
in appendix D to this part with an assumed density or for as-delivered 
fuel sampled from each delivery:

[[Page 28155]]

    (A) Measured GCV and, if applicable, density from each fuel sample; 
and
    (B) Assumed GCV and, if applicable, density used to calculate heat 
input rate;
    (iii) For each hour when the unit is combusting gaseous fuel:
    (A) Date and hour;
    (B) Hourly heat input rate from gaseous fuel, according to 
procedures in appendix F to this part (in mmBtu/hr, rounded to the 
nearest tenth);
    (C) Hourly flow rate of gaseous fuel, while the unit combusts gas 
(in 100 scfh) (flag value if derived from missing data procedures);
    (D) Gross calorific value (heat content) of gaseous fuel used to 
determine heat input rate (in Btu/100 scf) (flag value if derived from 
missing data procedures);
    (E) Heat input rate from gaseous fuel, while the unit combusts gas 
(in mmBtu/hr, rounded to the nearest tenth);
    (F) Fuel usage time for combustion of gaseous fuel during the hour 
(rounded up to the nearest fraction of an hour (in equal increments 
that can range from one hundredth to one quarter of an hour, at the 
option of the owner or operator)) (flag to indicate multiple/single 
fuel types combusted); and
    (G) Monitoring system identification code;
    (iv) For each oil sample or sample of diesel fuel:
    (A) Date of sampling;
    (B) Gross calorific value or heat content (in Btu/lb) (flag value 
if derived from missing data procedures); and
    (C) Density or specific gravity, if required to convert volume to 
mass (flag value if derived from missing data procedures);
    (v) For each sample of gaseous fuel:
    (A) Date of sampling; and
    (B) Gross calorific value or heat content (in Btu/100 scf) (flag 
value if derived from missing data procedures);
    (vi) For each oil sample or sample of gaseous fuel:
    (A) Type of oil or gas; and
    (B) Percent carbon or F-factor of fuel;
    (7) Specific NOX, record provisions for gas-fired or 
oil-fired units using the optional low mass emissions excepted 
methodology in Sec. 75.19. In lieu of recording the information in 
Sec. 75.57(b), (c)(2), (d), and (g), the owner or operator shall 
record, for each hour when the unit is operating for any portion of the 
hour, the following information for each affected low mass emissions 
unit for which the owner or operator is using the low mass emissions 
excepted methodology in Sec. 75.19(c):
    (i) Date and hour;
    (ii) If one type of fuel is combusted in the hour, fuel type 
(pipeline natural gas, natural gas, residual oil, or diesel fuel) or, 
if more than one type of fuel is combusted in the hour, the fuel type 
which results in the highest emission factors for NOX;
    (iii) Average hourly NOX emission rate (in lb/mmBtu, 
rounded to the nearest thousandth); and
    (iv) Hourly NOX mass emissions (in lbs, rounded to the 
nearest tenth).
    (b) Certification, quality assurance and quality control record 
provisions. The owner or operator of any affected unit shall record the 
applicable information in Sec. 75.59 for each affected unit or group of 
units monitored at a common stack and each non-affected unit under 
Sec. 75.72(b)(2)(ii).
    (c) Monitoring plan record provisions. (1) General provisions. The 
owner or operator of an affected unit shall prepare and maintain a 
monitoring plan for each affected unit or group of units monitored at a 
common stack and each non-affected unit under Sec. 75.72(b)(2)(ii). 
Except as provided in paragraph (d) or (f) of this section, a 
monitoring plan shall contain sufficient information on the continuous 
emission monitoring systems, excepted methodology under Sec. 75.19, or 
excepted monitoring systems under appendix D or E to this part and the 
use of data derived from these systems to demonstrate that all the 
unit's NOX emissions are monitored and reported.
    (2) Whenever the owner or operator makes a replacement, 
modification, or change in the certified continuous emission monitoring 
system, excepted methodology under Sec. 75.19, excepted monitoring 
system under appendix D or E to this part, or alternative monitoring 
system under subpart E of this part, including a change in the 
automated data acquisition and handling system or in the flue gas 
handling system, that affects information reported in the monitoring 
plan (e.g., a change to a serial number for a component of a monitoring 
system), then the owner or operator shall update the monitoring plan.
    (3) Contents of the monitoring plan for units not subject to an 
Acid Rain emissions limitation. Each monitoring plan shall contain the 
information in Sec. 75.53(e)(1) in electronic format and the 
information in Sec. 75.53(e)(2) in hardcopy format. In addition, to the 
extent applicable, each monitoring plan shall contain the information 
in Sec. 75.53(f)(1)(i), (f)(2)(i), and (f)(4) in electronic format and 
the information in Sec. 75.53(f)(1)(ii) and (f)(2)(ii) in hardcopy 
format.
    (d) General reporting provisions. (1) The designated representative 
for an affected unit shall comply with all reporting requirements in 
this section and with any additional requirements set forth in an 
applicable state or Federal NOX mass emission reduction 
program that adopts the requirements of this subpart.
    (2) The designated representative for an affected unit shall submit 
the following for each affected unit or group of units monitored at a 
common stack and each non-affected unit under Sec. 75.72(b)(2)(ii);
    (i) Initial certification applications in accordance with 
Sec. 75.70(d);
    (ii) Monitoring plans in accordance with paragraph (e) of this 
section; and
    (iii) Quarterly reports in accordance with paragraph (f) of this 
section.
    (3) Other petitions and communications. The designated 
representative for an affected unit shall submit petitions, 
correspondence, application forms, and petition-related test results in 
accordance with the provisions in Sec. 75.70(g).
    (4) Quality assurance RATA reports. If requested by the permitting 
authority, the designated representative of an affected unit shall 
submit the quality assurance RATA report for each affected unit or 
group of units monitored at a common stack and each non-affected unit 
under Sec. 75.72(b)(2)(ii) by the later of 45 days after completing a 
quality assurance RATA according to section 2.3 of appendix B to this 
part or 15 days of receiving the request. The designated representative 
shall report the hardcopy information required by Sec. 75.59(a)(10) to 
the permitting authority.
    (5) Notifications. The designated representative for an affected 
unit shall submit written notice to the permitting authority according 
to the provisions in Sec. 75.61 for each affected unit or group of 
units monitored at a common stack and each non-affected unit under 
Sec. 75.72(b)(2)(ii).
    (e) Monitoring plans. (1) Submission.
    (i) Electronic. The designated representative for an affected unit 
shall submit a complete, electronic, up-to-date monitoring plan file 
(except for hardcopy portions identified in paragraph (e)(1)(ii) of 
this section) for each affected unit or group of units monitored at a 
common stack and each non-affected unit under Sec. 75.72(b)(2)(ii) as 
follows:
    (A) To the permitting authority, no later than 45 days prior to the 
initial certification test and at the time of recertification 
application submission; and
    (B) To the Administrator, no later than 45 days prior to the 
initial certification test, at the time of recertification application 
submission, and in each electronic quarterly report.
    (ii) Hardcopy. The designated representative of an affected unit 
shall

[[Page 28156]]

submit all of the hardcopy information required under Sec. 75.53, for 
each affected unit or group of units monitored at a common stack and 
each non-affected unit under Sec. 75.72(b)(2)(ii), to the permitting 
authority prior to initial certification. Thereafter, the designated 
representative shall submit hardcopy information only if that portion 
of the monitoring plan is revised. The designated representative shall 
submit the required hardcopy information: no later than 45 days prior 
to the initial certification test; with any recertification 
application, if a hardcopy monitoring plan change is associated with 
the recertification event; and within 30 days of any other event with 
which a hardcopy monitoring plan change is associated, pursuant to 
Sec. 75.53(b).
    (2) [Reserved]
    (f) Quarterly reports. (1) Electronic submission. The designated 
representative for an affected unit shall electronically report the 
data and information in this paragraph (f)(1) and in paragraphs (f)(2) 
and (3) of this section to the Administrator quarterly. Each electronic 
report shall include the date of report generation, for the information 
provided in paragraphs (f)(1)(ii) through (f)(1)(vi) of this section, 
and shall also include for each affected unit or group of units 
monitored at a common stack:
    (i) Facility information:
    (A) Identification, including:
    (1) Facility/ORISPL number;
    (2) Calendar quarter and year data contained in the report; and
    (3) EDR version used for the report;
    (B) Location, including:
    (1) Plant name and facility ID;
    (2) EPA AIRS facility system ID;
    (3) State facility ID;
    (4) Source category/type;
    (5) Primary SIC code;
    (6) State postal abbreviation;
    (7) County code; and
    (8) Latitude and longitude;
    (ii) The information and hourly data required in paragraph (a) of 
this section, except for:
    (A) Descriptions of adjustments, corrective action, and 
maintenance;
    (B) Information which is incompatible with electronic reporting 
(e.g., field data sheets, lab analyses, quality control plan);
    (C) For units with NOX add-on emission controls that do 
not elect to use the approved site-specific parametric monitoring 
procedures for calculation of substitute data, the information in 
Sec. 75.58(b)(3);
    (D) Information required by Sec. 75.57(h) concerning the causes of 
any missing data periods and the actions taken to cure such causes;
    (E) Hardcopy monitoring plan information required by Sec. 75.53 and 
hardcopy test data and results required by Sec. 75.59;
    (F) Records of flow polynomial equations and numerical values 
required by Sec. 75.59(a)(5)(vi);
    (G) Daily fuel sampling information required by Sec. 75.58(c)(3)(i) 
for units using assumed values under appendix D;
    (H) Information required by Sec. 75.59(b)(2) concerning 
transmitter/transducer accuracy tests;
    (I) Stratification test results required as part of the RATA 
supplementary records under Sec. 75.56(a)(7) or Sec. 75.59(a)(7);
    (J) Data and results of RATAs that are aborted or invalidated due 
to problems with the reference method or operational problems with the 
unit and data and results of linearity checks that are aborted or 
invalidated due to operational problems with the unit; and
    (K) The summary of data used to determine the percentage of 
historical usage of each load level as required under 
Sec. 75.59(a)(8)(iv);
    (iii) Average NOX emission rate (lb/mmBtu, rounded to 
the nearest thousandth) during the quarter and cumulative 
NOX emission rate for the calendar year;
    (iv) Tons of NOX emitted during quarter, cumulative tons 
of NOX emitted during the year, and, during the second and 
third calender quarters, cumulative tons of NOX emitted 
during the ozone season;
    (v) During the second and third calender quarters, cummulative heat 
input for the ozone season; and
    (vi) Unit/stack/pipe operating hours for quarter, cumulative unit/
stack/pipe operating hours for calendar year, and, during the second 
and third calender quarters, cumulative operating hours during the 
ozone season.
    (2) The designated representative shall affirm that the component/
system identification codes and formulas in the quarterly electronic 
reports submitted to the Administrator pursuant to paragraph (e) of 
this section represent current operating conditions.
    (3) Compliance certification. The designated representative shall 
submit and sign a compliance certification in support of each quarterly 
emissions monitoring report based on reasonable inquiry of those 
persons with primary responsibility for ensuring that all of the unit's 
emissions are correctly and fully monitored. The certification shall 
state that:
    (i) The monitoring data submitted were recorded in accordance with 
the applicable requirements of this part, including the quality 
assurance procedures and specifications; and
    (ii) With regard to a unit with add-on emission controls and for 
all hours where data are substituted in accordance with 
Sec. 75.34(a)(1), the add-on emission controls were operating within 
the range of parameters listed in the monitoring plan and the 
substitute values do not systematically underestimate NOX 
emissions.
    (4) The designated representative shall comply with all of the 
quarterly reporting requirements in Secs. 75.64(d), (f), and (g).

Appendix A to Part 75--Specifications and Test Procedures

Appendix A--[Amended]

    49.-53. Appendix A to part 75 is amended by revising section 2.1 to 
read as follows:
* * * * *

2. Equipment Specifications

2.1  Instrument Span and Range

    In implementing sections 2.1.1 through 2.1.5 of this appendix, 
set the measurement range for each parameter (SO2, 
NOX, CO2, O2, or flow rate) high 
enough to prevent full-scale exceedances from occurring, yet low 
enough to ensure good measurement accuracy and to maintain a high 
signal-to-noise ratio. To meet these objectives, it is recommended 
that the range be selected such that the readings obtained during 
typical unit operation are kept, to the extent practicable, between 
20.0 and 80.0 percent of full-scale range of the instrument. Note 
that this guideline does not apply to: (1) SO2 readings 
obtained during the combustion of natural gas or fuel with a total 
sulfur content no greater than the total sulfur content of natural 
gas; (2) SO2 or NOX readings recorded on the 
high measurement range, for units with SO2 or 
NOX emission controls and two span values; or (3) 
SO2 or NOX readings less than 20.0 percent of 
full-scale on the low measurement range for a dual span unit with 
SO2 or NOX emission controls, provided that 
the readings occur during periods of high control device efficiency.

2.1.1  SO2 Pollutant Concentration Monitors

    Determine, as indicated below, the span value(s) and range(s) 
for an SO2 pollutant concentration monitor so that all 
potential and expected concentrations can be accurately measured and 
recorded. Note that if a unit exclusively combusts fuel(s) with a 
total sulfur content no greater than the total sulfur content of 
natural gas (i.e.,  0.05 percent sulfur by weight), the 
SO2 monitor span requirements in Sec. 75.11(e)(3)(iv) 
apply in lieu of the requirements of this section.

2.1.1.1  Maximum Potential Concentration

    Make an initial determination of the maximum potential 
concentration (MPC) of SO2 by using Equation A-1a or A-
1b. Base the MPC calculation on the maximum percent sulfur and the 
minimum gross calorific value (GCV) for the highest-sulfur

[[Page 28157]]

fuel to be burned. The maximum sulfur content and minimum GCV shall 
be determined from all available fuel sampling and analysis data for 
that fuel from the previous 12 months (minimum), excluding clearly 
anomalous fuel sampling results. If the designated representative 
certifies that the highest-sulfur fuel is never burned alone in the 
unit during normal operation but is always blended or co-fired with 
other fuel(s), the MPC may be calculated using a best estimate of 
the highest sulfur content and lowest gross calorific value expected 
for the blend or fuel mixture and inserting these values into 
Equation A-1a or A-1b. Derive the best estimate of the highest 
percent sulfur and lowest GCV for a blend or fuel mixture from 
weighted-average values based upon the historical composition of the 
blend or mixture in the previous 12 (or more) months. If 
insufficient representative fuel sampling data are available to 
determine the maximum sulfur content and minimum GCV, use values 
from contract(s) for the fuel(s) that will be combusted by the unit 
in the MPC calculation.
    Alternatively, if a certified SO2 CEMS is already 
installed, the owner or operator may make the initial MPC 
determination based upon quality assured historical data recorded by 
the CEMS. If this option is chosen, the MPC shall be the maximum 
SO2 concentration observed during the previous 720 (or 
more) quality assured monitor operating hours when combusting the 
highest-sulfur fuel (or highest-sulfur blend if fuels are always 
blended or co-fired) that is to be combusted in the unit or units 
monitored by the SO2 monitor. For units with 
SO2 emission controls, the certified SO2 
monitor used to determine the MPC must be located at or before the 
control device inlet. Report the MPC and the method of determination 
in the monitoring plan required under Sec. 75.53.
    When performing fuel sampling to determine the MPC, use ASTM 
Methods: ASTM D3177-89, ``Standard Test Methods for Total Sulfur in 
the Analysis Sample of Coal and Coke''; ASTM D4239-85, ``Standard 
Test Methods for Sulfur in the Analysis Sample of Coal and Coke 
Using High Temperature Tube Furnace Combustion Methods''; ASTM 
D4294-90, ``Standard Test Method for Sulfur in Petroleum Products by 
Energy-Dispersive X-Ray Fluorescence Spectroscopy''; ASTM D1552-90, 
``Standard Test Method for Sulfur in Petroleum Products (High 
Temperature Method)''; ASTM D129-91, ``Standard Test Method for 
Sulfur in Petroleum Products (General Bomb Method)''; ASTM D2622-92, 
``Standard Test Method for Sulfur in Petroleum Products by X-Ray 
Spectrometry'' for sulfur content of solid or liquid fuels; ASTM 
D3176-89, ``Standard Practice for Ultimate Analysis of Coal and 
Coke''; ASTM D240-87 (Reapproved 1991), ``Standard Test Method for 
Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb 
Calorimeter''; or ASTM D2015-91, ``Standard Test Method for Gross 
Calorific Value of Coal and Coke by the Adiabatic Bomb Calorimeter'' 
for GCV (incorporated by reference under Sec. 75.6).

[GRAPHIC] [TIFF OMITTED] TP21MY98.002

(Eq. A-1a)
or
[GRAPHIC] [TIFF OMITTED] TP21MY98.003

(Eq. A-1b)

Where:

MPC=Maximum potential concentration (ppm, wet basis). To convert to 
dry basis, divide the MPC by 0.9).
MEC=Maximum expected concentration (ppm, wet basis). To convert to 
dry basis, divide the MEC by 0.9).
%S=Maximum sulfur content of the fuel to be fired, wet basis, weight 
percent, as determined by ASTM D3177-89, ASTM D4239-85, ASTM D4294-
90, ASTM D1552-90, ASTM D129-91, or ASTM D2622-92 for solid or 
liquid fuels (incorporated by reference under Sec. 75.6).
%O2w=Minimum oxygen concentration, percent wet basis, 
under typical operating conditions.
%CO2w=Maximum carbon dioxide concentration, percent wet 
basis, under typical operating conditions.
11.32 x 106=Oxygen-based conversion factor in (Btu/
lb)(ppm)/%.
66.93 x 106=Carbon dioxide-based conversion factor in 
(Btu/lb)(ppm)/%.

    Note: All percentage values to be inserted in the equations of 
this section are to be expressed as a percentage, not a fractional 
value (e.g., 3, not .03).

2.1.1.2  Maximum Expected Concentration

    Make an initial determination of the maximum expected 
concentration (MEC) of SO2 whenever: (a) SO2 
emission controls are used; or (b) both high-sulfur and low-sulfur 
fuels (e.g., high-sulfur coal and low-sulfur coal or different 
grades of fuel oil) or high-sulfur and low-sulfur fuel blends are 
combusted as primary or backup fuels in a unit without 
SO2 emission controls. For units with SO2 
emission controls, use Equation A-2 to make the initial MEC 
determination. When high-sulfur and low-sulfur fuels or blends are 
burned as primary or backup fuels in a unit without SO2 
controls, use Equation A-1a or A-1b to calculate the initial MEC 
value for each fuel or blend, except for: (1) the highest-sulfur 
fuel or blend (for which the MPC was previously calculated in 
section 2.1.1.1 of this appendix); (2) fuels or blends with a total 
sulfur content no greater than the total sulfur content of natural 
gas, i.e.,  0.05 percent sulfur by weight; or (3) fuels 
or blends that are used only for unit startup.
    For each MEC determination, substitute into Equation A-1a or A-
1b the highest sulfur content and minimum GCV value for that fuel or 
blend, based upon all available fuel sampling and analysis results 
from the previous 12 months (or more), or, if fuel sampling data are 
unavailable, based upon fuel contract(s).
    Alternatively, if a certified SO2 CEMS is already 
installed, the owner or operator may make the initial MEC 
determination(s) based upon historical monitoring data. If this 
option is chosen for a unit with SO2 emission controls, 
the MEC shall be the maximum SO2 concentration measured 
downstream of the control device outlet by the CEMS over the 
previous 720 (or more) quality assured monitor operating hours with 
the unit and the control device both operating normally. For units 
that burn high- and low-sulfur fuels or blends as primary and backup 
fuels and have no SO2 emission controls, the MEC for each 
fuel shall be the maximum SO2 concentration measured by 
the CEMS over the previous 720 (or more) quality assured monitor 
operating hours in which that fuel or blend was the only fuel being 
burned in the unit.
[GRAPHIC] [TIFF OMITTED] TP21MY98.004

(Eq. A-2)

where:

MEC=Maximum expected concentration (ppm).
MPC=Maximum potential concentration (ppm), as determined by Eq. A-1a 
or A-1b.
RE=Expected average design removal efficiency of control equipment 
(percent).

2.1.1.3  Span Value(s) and Range(s)

    Determine the high span value and the high full-scale range of 
the SO2 monitor as follows. (Note: For purposes of this 
part, the high span and range refer, respectively, either to the 
span and range of a single span unit or to the high span and range 
of a dual span unit.) The high span value shall be obtained by 
multiplying the MPC by a factor no less than 1.00 and no greater 
than 1.25. Round the

[[Page 28158]]

span value upward to the next highest multiple of 100 ppm. If the 
SO2 span concentration is  500 ppm, the span 
value may be rounded upward to the next highest multiple of 10 ppm, 
instead of the nearest 100 ppm. The high span value shall be used to 
determine concentrations of the calibration gases required for daily 
calibration error checks and linearity tests. Select the full-scale 
range of the instrument to be consistent with section 2.1 of this 
appendix and to be greater than or equal to the span value. Report 
the full-scale range setting and calculations of the MPC and span in 
the monitoring plan for the unit. Note that for certain 
applications, a second (low) SO2 span value may be 
required (see section 2.1.1.4 of this appendix). If an existing 
state, local, or federal requirement for span of an SO2 
pollutant concentration monitor requires a span lower than that 
required by this section or by section 2.1.1.4 of this appendix, the 
state, local, or federal span value may be used if a satisfactory 
explanation is included in the monitoring plan, unless span and/or 
range adjustments become necessary in accordance with section 
2.1.1.5 of this appendix. Span values higher than those required by 
either this section or section 2.1.1.4 of this appendix must be 
approved by the Administrator.

2.1.1.4  Dual Span and Range Requirements

    For most units, the high span value based on the MPC, as 
determined under section 2.1.1.3 of this appendix will suffice to 
measure and record SO2 concentrations (unless span and/or 
range adjustments become necessary in accordance with section 
2.1.1.5 of this appendix). In some instances, however, a second 
(low) span value based on the MEC may be required to ensure accurate 
measurement of all possible or expected SO2 
concentrations. To determine whether two SO2 span values 
are required, proceed as follows:
    (a) For units with SO2 emission controls, compare the 
MEC from section 2.1.1.2 of this appendix to the MPC value from 
section 2.1.1.1 of this appendix. If the MEC is 20.0 
percent of the MPC, then the high span value and range determined 
under section 2.1.1.3 of this appendix are sufficient. If the MEC is 
< 20.0 percent of the MPC, however, a second (low) span value is 
required.
    (b) For units that combust high- and low-sulfur primary and 
backup fuels (or blends) and have no SO2 controls, 
compare the MPC value from section 2.1.1.1 of this appendix (for the 
highest-sulfur fuel or blend) to the MEC value for each of the other 
fuels or blends, as determined under section 2.1.1.2 of this 
appendix. If all of the MEC values are 20.0 percent of 
the MPC, the high span and range determined under section 2.1.1.3 of 
this appendix are sufficient, regardless of which fuel or blend is 
burned in the unit. If any MEC value is <20.0 percent of the MPC, 
however, a second (low) span value must be used when that fuel or 
blend is combusted.
    (c) When two SO2 spans are required, the owner or 
operator may either use a single SO2 analyzer with a dual 
range (i.e., low- and high-scales) or two separate SO2 
analyzers connected to a common sample probe and sample interface. 
For units with SO2 emission controls, the owner or 
operator may use a low range analyzer and a default high range 
value, as described in paragraph (f) of this section, in lieu of 
maintaining and quality assuring a high-scale range. Other monitor 
configurations are subject to the approval of the Administrator.
    (d) The owner or operator shall designate the monitoring systems 
and components as follows: (1) designate the low and high monitor 
ranges as separate components of a single, primary monitoring 
system; or (2) designate the low and high monitor ranges as 
separate, primary monitoring systems; or (3) designate the normal 
monitor range as a primary monitoring system and the other monitor 
range as a non-redundant backup monitoring system; or (4) for units 
with SO2 controls, if the default high range value is 
used, designate the low range analyzer as the primary monitoring 
system.
    (e) Each monitoring system designated as primary shall meet the 
initial certification and quality assurance requirements for primary 
monitoring systems in Sec. 75.20(c) and appendices A and B to this 
part, with one exception: relative accuracy test audits (RATAs) are 
required only on the normal range (for units with SO2 
emission controls, the low range is considered normal). Each 
monitoring system designated as a non-redundant backup shall meet 
the applicable quality assurance requirements in Sec. 75.20(d).
    (f) For dual span units with SO2 emission controls, 
the owner or operator may, as an alternative to maintaining and 
quality assuring a high monitor range, use a default high range 
value. If this option is chosen, the owner or operator shall report 
a default SO2 concentration of 200.0 percent of the MPC 
for each unit operating hour in which the full-scale of the low 
range SO2 analyzer is exceeded.
    (g) The high span value and range shall be determined in 
accordance with section 2.1.1.3 of this appendix. The low span value 
shall be obtained by multiplying the MEC by a factor no less than 
1.00 and no greater than 1.25, and rounding the result upward to the 
next highest multiple of 10 ppm (or 100 ppm, as appropriate). For 
units that burn high- and low-sulfur primary and backup fuels or 
blends and have no SO2 emission controls, select, as the 
basis for calculating the appropriate low span value and range, the 
fuel-specific MEC value closest to 20.0 percent of the MPC (from 
paragraph (b) of this section). The low range must be greater than 
or equal to the low span value, and the required calibration gases 
must be selected based on the low span value. For units with two 
SO2 spans, use the low range whenever the SO2 
concentrations are expected to be consistently below 20.0 percent of 
the MPC, i.e., when the MEC of the fuel or blend being combusted is 
less than 20.0 percent of the MPC. When the full-scale of the low 
range is exceeded, the high range shall be used to measure and 
record the SO2 concentrations; or, if applicable, the 
default high range value in paragraph (f) of this section shall be 
reported for each hour of the full-scale exceedance.

2.1.1.5  Adjustment of Span and Range

    For each affected unit or common stack, the owner or operator 
shall make a quarterly evaluation of the MPC, MEC, span, and range 
values for each SO2 monitor and shall make any necessary 
span and range adjustments, with corresponding monitoring plan 
updates, as described in paragraphs (a) through (e), below. Span and 
range adjustments may be required as a result of changes in the fuel 
supply, changes in the manner of operation of the unit, installation 
or removal of emission controls, etc. In implementing the provisions 
in paragraphs (a) through (e), below, note that SO2 data 
recorded during short-term, non-representative process operating 
conditions (e.g., a trial burn of a different type of fuel) shall be 
excluded from the analysis; however, if the high range is exceeded, 
200.0 percent of the high range must still be reported as the hourly 
SO2 concentration for each hour of the full-scale 
exceedance, as required by paragraph (c)(1) of this section. The 
owner or operator shall document all such unrepresentative operating 
conditions in the quarterly report required under Sec. 75.64 and 
shall indicate which data (dates and hours) have been excluded from 
the quarterly span and range evaluation.
    Make each required span or range adjustment no later than 45 
days after the end of the quarter in which the need to adjust the 
span or range is identified, except that up to 90 days after the end 
of that quarter may be taken to implement a span adjustment if the 
calibration gases currently being used for daily calibration error 
tests and linearity checks are unsuitable for use with the new span 
value.
    (a) No span or range adjustment is required if, during a 
calendar quarter, the hourly SO2 concentration exceeds 
the MPC but does not exceed the high span value. However, for 
missing data purposes, if any of the hourly SO2 
concentrations exceed the current MPC by 5.0 percent, a 
new MPC equal to the highest quality assured hourly SO2 
concentration recorded during the quarter must be defined in the 
monitoring plan. Update the monitoring plan to reflect the new MPC 
value.
    (b) A span adjustment is required if any of the on-scale, 
quality assured hourly SO2 concentrations exceed the high 
span value by  10.0 percent during a quarter, but do not 
exceed the high range. Define a new MPC value (as applicable) equal 
to the highest quality assured on-scale SO2 concentration 
recorded during the quarter, and set the new span value according to 
section 2.1.1.3 of this appendix, using the new MPC value. If the 
new span value exceeds the current full-scale range, adjust the 
range setting also. Update the monitoring plan to reflect the new 
MPC, the new span value, and (if applicable) the new full-scale 
range. Where separate ranges are used to measure emissions from the 
combustion of different types of fuel, the low span and MEC shall be 
increased in the manner described in this paragraph if any on-scale 
hourly value exceeds the low span value by 10.0 percent or more.
    (c) Whenever a full-scale range is exceeded during a quarter and 
the exceedance is not caused by a monitor out-of-control period, 
proceed as follows:
    (1) For exceedances of the high range, report 200.0 percent of 
the current full-scale range as the hourly SO2 
concentration for

[[Page 28159]]

each hour of the full-scale exceedance and make adjustments to the 
MPC, span, and range to prevent future full-scale exceedances.
    (2) For units with two SO2 spans and ranges, if the 
low range is exceeded, no further action is required, provided that 
the high range is available and is not out-of-control or out-of-
service for any reason. However, if the high range is not able to 
provide quality assured data at the time of the low range exceedance 
or at any time during the continuation of the exceedance, report the 
MPC as the SO2 concentration until the readings return to 
the low range or until the high range is able to provide quality 
assured data (unless the reason that the high-scale range is not 
able to provide quality assured data is because the high-scale range 
has been exceeded; if the high-scale range is exceeded follow the 
procedures in paragraph (c)(1) of this section).
    (d) If the fuel supply, the composition of the fuel blend(s), 
the emission controls, or the manner of operation change such that 
the maximum expected or potential concentration changes 
significantly, adjust the span and range setting to assure the 
continued accuracy of the monitoring system. The owner or operator 
should evaluate whether any planned changes in operation of the unit 
may affect the concentration of emissions being emitted from the 
unit or stack and should plan any necessary span and range changes 
needed to account for these changes, so that they are made in as 
timely a manner as practicable to coordinate with the operational 
changes. Determine the adjusted span(s) using the procedures in 
sections 2.1.1.3 and 2.1.1.4 of this appendix (as applicable). 
Select the full-scale range(s) of the instrument to be greater than 
or equal to the new span value(s) and to be consistent with the 
guidelines of section 2.1 of this appendix.
    (e) Whenever changes are made to the MPC, MEC, full-scale range, 
or span value of the SO2 monitor, as described in 
paragraphs (a) through (d) of this section, record and report (as 
applicable) the new full-scale range setting, the new MPC or MEC and 
calculations of the adjusted span value in an updated monitoring 
plan. The monitoring plan update shall be made in the quarter in 
which the changes become effective. In addition, record and report 
the adjusted span as part of the records for the daily calibration 
error test and linearity check specified by appendix B to this part. 
Whenever the span value is adjusted, use calibration gas 
concentrations that meet the requirements of section 5.1 of this 
appendix, based on the adjusted span value. When a span adjustment 
is so significant that the calibration gases currently being used 
for daily calibration error tests and linearity checks are 
unsuitable for use with the new span value, then a diagnostic 
linearity test using the new calibration gases must be performed and 
passed. Data from the monitor are considered invalid from the hour 
in which the span is adjusted until the required linearity check is 
passed in accordance with section 6.2 of this appendix.

2.1.2  NOX Pollutant Concentration Monitors

    Determine, as indicated below, the span and range value(s) for 
the NOX pollutant concentration monitor so that all 
expected NOX concentrations can be determined and 
recorded accurately.

2.1.2.1  Maximum Potential Concentration

    The maximum potential concentration (MPC) of NOX for 
each affected unit shall be based upon whichever fuel or blend 
combusted in the unit produces the highest level of NOX 
emissions. Make an initial determination of the MPC using the 
appropriate option below. Note that an initial MPC value determined 
for a unit that is not equipped with low-NOX burners must 
be re-evaluated if a low-NOX burner system is 
subsequently installed.
    Option 1: Use 800 ppm for coal-fired and 400 ppm for oil-or gas-
fired units as the maximum potential concentration of NOX 
(if an MPC of 1600 ppm for coal-fired units or 480 ppm for oil-or 
gas-fired units was previously selected under this part, that value 
may still be used, provided that the guidelines of section 2.1 of 
this appendix are met);
    Option 2: Use the specific values based on boiler type and fuel 
combusted, listed in Table 2-1 or Table 2-2;
    Option 3: Use NOX emission test results; or
    Option 4: Use historical CEM data over the previous 720 (or 
more) unit operating hours when combusting the fuel or blend with 
the highest NOX emission rate.
    For the purpose of providing substitute data during 
NOX missing data periods in accordance with Secs. 75.31 
and 75.33 and as required elsewhere under this part, the owner or 
operator shall also calculate the maximum potential NOX 
emission rate (MER), in lb/mmBtu, by substituting the MPC for 
NOX in conjunction with the minimum CO2 or 
maximum O2 concentration (under all unit operating 
conditions except for unit startup, shutdown, and upsets) and the 
appropriate F-factor into the applicable equation in appendix F to 
this part. The diluent cap value of 5.0 percent CO2 (or 
14.0 percent O2) for boilers or 1.0 percent 
CO2 (or 19.0 percent O2) for combustion 
turbines may be used in the NOX MER calculation.
    Report the method of determining the initial MPC and the 
calculation of the maximum potential NOX emission rate in 
the monitoring plan for the unit.
    For units with add-on NOX controls, NOX 
emission testing may only be used to determine the MPC if testing 
can be performed on uncontrolled emissions (e.g., measured at or 
before the control device inlet). If NOX emission testing 
is performed, use the following guidelines. Use Method 7E from 
appendix A to part 60 of this chapter to measure total 
NOX concentration. (Note: Method 20 from appendix A to 
Part 60 may be used for gas turbines, instead of Method 7E.) Operate 
the unit, or group of units sharing a common stack, at the minimum 
safe and stable load, the normal load, and the maximum load. If the 
normal load and maximum load are identical, an intermediate level 
need not be tested. Operate at the highest excess O2 
level expected under normal operating conditions. Make at least 
three runs of 20 minutes (minimum) duration with three traverse 
points per run at each operating condition. Select the highest point 
NOX concentration (e.g., the highest one-minute average) 
from all test runs as the MPC for NOX.
    If historical CEM data are used to determine the MPC, the data 
must represent a minimum of 720 quality assured monitor operating 
hours, obtained under various operating conditions, including the 
minimum safe and stable load, normal load (including periods of high 
excess air at normal load), and maximum load. For units with add-on 
NOX controls, historical CEM data may only be used to 
determine the MPC if there are 720 quality assured monitor operating 
hours of CEM data measuring uncontrolled emissions (e.g., the CEM 
data are collected at or before the control device inlet). The 
highest hourly NOX concentration in ppm shall be the MPC.

2.1.2.2 Maximum Expected Concentration

    Make an initial determination of the maximum expected 
concentration (MEC) of NOX during normal operation for 
affected units with add-on NOX controls of any kind 
(i.e., steam injection, water injection, SCR, or SNCR). Determine a 
separate MEC value for each type of fuel (or blend) combusted in the 
unit, except for fuels that are only used for unit startup and/or 
flame stabilization. Calculate the MEC of NOX using 
Equation A-2, if applicable, inserting the maximum potential 
concentration, as determined using the procedures in section 2.1.2.1 
of this appendix. Where Equation A-2 is not applicable, set the MEC 
either by: (1) measuring the NOX concentration using the 
testing procedures in this section; or (2) using historical CEM data 
over the previous 720 (or more) quality assured monitor operating 
hours. Include in the monitoring plan for the unit each MEC value 
and the method by which the MEC was determined.
    If NOX emission testing is used to determine the MEC 
value(s), the MEC for each type of fuel (or blend) shall be based 
upon testing at minimum load, normal load, and maximum load. At 
least three tests of 20 minutes (minimum) duration, using at least 3 
traverse points, shall be performed at each load, using Method 7E 
from appendix A to part 60 of this chapter (Note: Method 20 from 
appendix A to part 60 may be used for gas turbines instead of Method 
7E). The test must be performed at a time when all NOX 
control devices and methods used to reduce NOX emissions 
are operating properly. The testing shall be conducted downstream of 
all NOX controls. The highest point NOX 
concentration (e.g., the highest one-minute average) recorded during 
any of the test runs shall be the MEC.
    If historical CEM data are used to determine the MEC value(s), 
the MEC for each type of fuel shall be based upon 720 (or more) 
hours of quality assured data representing the entire load range 
under stable operating conditions. The data base for the MEC shall 
not include any CEM data recorded during unit startup, shutdown, or 
malfunction or during any NOX control device malfunctions 
or outages. All NOX control devices and methods used to 
reduce

[[Page 28160]]

NOX emissions must be operating properly during each 
hour. The CEM data shall be collected downstream of all 
NOX controls. For each type of fuel, the highest of the 
720 (or more) quality assured hourly average NOX 
concentrations recorded by the CEMS shall be the MEC.

2.1.2.3  Span Value(s) and Range(s)

    Determine the high span value of the NOX monitor as 
follows. The high span value shall be obtained by multiplying the 
MPC by a factor no less than 1.00 and no greater than 1.25. Round 
the span value upward to the next highest multiple of 100 ppm. If 
the NOX span concentration is  500 ppm, the 
span value may be rounded upward to the next highest multiple of 10 
ppm, rather than 100 ppm. The high span value shall be used to 
determine the concentrations of the calibration gases required for 
daily calibration error checks and linearity tests. Note that for 
certain applications, a second (low) NOX span value may 
be required (see section 2.1.2.4 of this appendix).
    If an existing state, local, or federal requirement for span of 
an NOX pollutant concentration monitor requires a span 
lower than that required by this section or by section 2.1.2.4 of 
this appendix, the state, local, or federal span value may be used, 
where a satisfactory explanation is included in the monitoring plan, 
unless span and/or range adjustments become necessary in accordance 
with section 2.1.2.5 of this appendix. Span values higher than 
required by this section or by section 2.1.2.4 of this appendix must 
be approved by the Administrator.
    Select the full-scale range of the instrument to be consistent 
with section 2.1 of this appendix and to be greater than or equal to 
the high span value. Include the full-scale range setting and 
calculations of the MPC and span in the monitoring plan for the 
unit.

2.1.2.4  Dual Span and Range Requirements

    For most units, the high span value based on the MPC, as 
determined under section 2.1.2.3 of this appendix will suffice to 
measure and record NOX concentrations (unless span and/or 
range adjustments must be made in accordance with section 2.1.2.5 of 
this appendix). In some instances, however, a second (low) span 
value based on the MEC may be required to ensure accurate 
measurement of all expected and potential NOX 
concentrations. To determine whether two NOX spans are 
required, proceed as follows:
    (a) Compare the MEC value(s) determined in section 2.1.2.2 of 
this appendix to the MPC value determined in section 2.1.2.1 of this 
appendix. If the MEC values for all fuels (or blends) are 
 20.0 percent of the MPC, the high span and range values 
determined under section 2.1.2.3 of this appendix are sufficient, 
irrespective of which fuel or blend is combusted in the unit. If any 
of the MEC values is < 20.0 percent of the MPC, two spans (low and 
high) are required, one based upon the MPC and the other based on 
the MEC.
    (b) When two NOX spans are required, the owner or 
operator may either use a single NOX analyzer with a dual 
range (low-and high-scales) or two separate NOX analyzers 
connected to a common sample probe and sample interface. For units 
with add-on NOX emission controls (i.e., steam injection, 
water injection, SCR, or SNCR), the owner or operator may use a low 
range analyzer and a ``default high range value,'' as described in 
paragraph 2.1.2.4(e) of this section, in lieu of maintaining and 
quality assuring a high-scale range. Other monitor configurations 
are subject to the approval of the Administrator.
    (c) The owner or operator shall designate the monitoring systems 
and components as follows: (1) designate the low and high ranges as 
separate components of a single, primary monitoring system; or (2) 
designate the low and high ranges as separate, primary monitoring 
systems; or (3) designate the normal range as a primary monitoring 
system and the other range as a non-redundant backup monitoring 
system; or (4) for units with add-on NOX controls, if the 
default high range value is used, designate the low range analyzer 
as the primary monitoring system.
    (d) Each monitoring system designated as primary shall meet the 
initial certification and quality assurance requirements for primary 
monitoring systems in Sec. 75.20(c) and appendices A and B to this 
part, with one exception: relative accuracy test audits (RATAs) are 
required only on the normal range (for dual span units with add-on 
NOX emission controls, the low range is considered 
normal). Each monitoring system designated as non-redundant backup 
shall meet the applicable quality assurance requirements in 
Sec. 75.20(d).
    (e) For dual span units with add-on NOX emission 
controls (i.e., steam injection, water injection, SCR, or SNCR), the 
owner or operator may, as an alternative to maintaining and quality 
assuring a high monitor range, use a default high range value. If 
this option is chosen, the owner or operator shall report a default 
value of 200.0 percent of the MPC for each unit operating hour in 
which the full-scale of the low range NOX analyzer is 
exceeded.
    (f) The high span and range shall be determined in accordance 
with section 2.1.2.3 of this appendix. The low span value shall be 
100.0 to 125.0 percent of the MEC, rounded up to the next highest 
multiple of 10 ppm (or 100 ppm, if appropriate). If more than one 
MEC value (as determined in section 2.1.2.2 of this appendix) is 
<20.0 percent of the MPC, the low span value shall be based upon 
whichever MEC value is closest to 20.0 percent of the MPC. The low 
range must be greater than or equal to the low span value, and the 
required calibration gases for the low range must be selected based 
on the low span value. For units with two NOX spans, use 
the low range whenever NOX concentrations are expected to 
be consistently <20.0 percent of the MPC, i.e., when the MEC of the 
fuel being combusted is <20.0 percent of the MPC. When the full-
scale of the low range is exceeded, the high range shall be used to 
measure and record the NOX concentrations; or, if 
applicable, the default high range value in paragraph (e) of this 
section shall be reported for each hour of the full-scale 
exceedance.

2.1.2.5  Adjustment of Span and Range

    For each affected unit or common stack, the owner or operator 
shall make a quarterly evaluation of the MPC, MEC, span, and range 
values for each NOX monitor and shall make any necessary 
span and range adjustments, with corresponding monitoring plan 
updates, as described in paragraphs (a) through (e), below. Span and 
range adjustments may be required as a result of changes in the fuel 
supply, changes in the manner of operation of the unit, installation 
or removal of emission controls, etc. In implementing the provisions 
in paragraphs (a) through (e), below, note that NOX data 
recorded during short-term, non-representative operating conditions 
(e.g., a trial burn of a different type of fuel) shall be excluded 
from the analysis; however, if the high range is exceeded, 200.0 
percent of the high range must still be reported as the hourly 
NOX concentration for each hour of the full-scale 
exceedance, in accordance with paragraph (c)(1) of this section. The 
owner or operator shall document all such unrepresentative operating 
conditions in the quarterly report required under Sec. 75.64 and 
shall indicate which data have been excluded from the quarterly span 
and range evaluation.
    Make each required span or range adjustment no later than 45 
days after the end of the quarter in which the need to adjust the 
span or range is identified, except that up to 90 days after the end 
of that quarter may be taken to implement a span adjustment if the 
calibration gases currently being used for daily calibration error 
tests and linearity checks are unsuitable for use with the new span 
value.
    (a) No span or range adjustment is required if, during a 
calendar quarter, the hourly NOX concentration exceeds 
the MPC but does not exceed the high span value. However, for 
missing data purposes, if any of the hourly NOX 
concentrations exceed the current MPC by  5.0 percent, a 
new MPC equal to the highest quality assured hourly NOX 
concentration recorded during the quarter must be defined in the 
monitoring plan. Update the monitoring plan to reflect the new MPC 
value.
    (b) A span adjustment is required whenever any of the on-scale, 
quality assured, hourly NOX concentrations exceed the 
high span value by  10.0 percent during a quarter but do 
not exceed the high range. Define a new MPC value (as applicable) 
equal to the highest quality assured on-scale NOX 
concentration recorded during the quarter, and set the new span 
value according to section 2.1.2.3 or 2.1.2.4 of this appendix (as 
applicable), using the new MPC value. If the new span value exceeds 
the current full-scale range, adjust the range setting also. Update 
the monitoring plan to reflect the new MPC, the new span value, and 
(if applicable) the new full-scale range. Where separate ranges are 
used to measure emissions from different fuels or in different 
seasons (i.e. where seasonal controls are used), the low span and 
MEC shall be increased in the manner described in this paragraph if 
any on-scale hourly value exceeds the low span value by 10.0 percent 
or more.
    (c) Whenever a full-scale range is exceeded during a quarter and 
the exceedance is not caused by a monitor out-of-control period, 
proceed as follows:
    (1) For exceedances of the high range, report 200.0 percent of 
the current full-scale

[[Page 28161]]

range as the hourly NOX concentration for each hour of 
the full-scale exceedance and make adjustments to the MPC, span, and 
range to prevent future full-scale exceedances.
    (2) For units with two NOX spans and ranges, if the 
low range is exceeded, no further action is required, provided that 
the high range is available and is not out-of-control or out-of-
service for any reason. However, if the high range is not able to 
provide quality assured data at the time of the low range exceedance 
or at any time during the continuation of the exceedance, report the 
MPC as the NOX concentration until the readings return to 
the low range or until the high range is able to provide quality 
assured data (unless the reason that the high-scale range is not 
able to provide quality assured data is because the high-scale range 
has been exceeded; if the high-scale range is exceeded follow the 
procedures in paragraph (c)(1) of this section).
    (d) If the fuel supply, emission controls, or other process 
parameters change such that the maximum expected concentration or 
the maximum potential concentration changes significantly, adjust 
the NOX pollutant concentration span(s) and (if 
necessary) monitor range(s) to assure the continued accuracy of the 
monitoring system. The owner or operator should evaluate whether any 
planned changes in operation of the unit or stack may affect the 
concentration of emissions being emitted from the unit and should 
plan any necessary span and ranges changes needed to account for 
these changes, so that they are made in as timely a manner as 
practicable to coordinate with the operational changes. Determine 
the adjusted span(s) using the procedures in section 2.1.2.3 or 
2.1.2.4 of this appendix (as applicable). Select the full-scale 
range(s) of the instrument to be greater than or equal to the 
adjusted span value(s) and to be consistent with the guidelines of 
section 2.1 of this appendix.
    (e) Whenever changes are made to the MPC, MEC, full-scale range, 
or span value of the NOX monitor as described in 
paragraphs (a) through (d) of this section, record and report (as 
applicable) the new full-scale range setting, the new MPC or MEC, 
maximum potential NOX emission rate, and the adjusted 
span value in an updated monitoring plan for the unit. The 
monitoring plan update shall be made in the quarter in which the 
changes become effective. In addition, record and report the 
adjusted span as part of the records for the daily calibration error 
test and linearity check required by appendix B to this part. 
Whenever the span value is adjusted, use calibration gas 
concentrations that meet the requirements of section 5.1 of this 
appendix, based on the adjusted span value. When a span adjustment 
is significant enough that the calibration gases currently being 
used for daily calibration error tests and linearity checks are 
unsuitable for use with the new span value, a linearity test using 
the new calibration gases must be performed and passed. Data from 
the monitor are considered invalid from the hour in which the span 
is adjusted until the required linearity check is passed in 
accordance with section 6.2 of this appendix.

2.1.3  CO2 and O2 Monitors

    For an O2 monitor (including O2 monitors 
used to measure CO2 emissions or percentage moisture), 
select a span value between 15.0 and 25.0 percent O2. For 
a CO2 monitor installed on a boiler, select a span value 
between 14.0 and 20.0 percent CO2. For a CO2 
monitor installed on a combustion turbine, an alternative span value 
between 6.0 and 14.0 percent CO2 may be used. An 
alternative O2 span value below 15.0 percent 
O2 may be used if an appropriate technical justification 
is included in the monitoring plan. Select the full-scale range of 
the instrument to be consistent with section 2.1 of this appendix 
and to be greater than or equal to the span value. Select the 
calibration gas concentrations for the daily calibration error tests 
and linearity checks in accordance with section 5.1 of this 
appendix, as percentages of the span value. For O2 
monitors with span values 21.0 percent O2, 
purified instrument air containing 20.9 percent O2 may be 
used as the high-level calibration material.

2.1.3.1  Maximum Potential Concentration of CO2

    For CO2 pollutant concentration monitors, the maximum 
potential concentration shall be 14.0 percent CO2 for 
boilers and 6.0 percent CO2 for combustion turbines. 
Alternatively, the owner or operator may determine the MPC based on 
a minimum of 720 hours of quality assured historical CEM data 
representing the full operating load range of the unit(s).

2.1.3.2  Adjustment of Span and Range

    Adjust the span value and range of a CO2 or 
O2 monitor according to the general guidelines in section 
2.1.1.5 of this appendix (insofar as those provisions are 
applicable), replacing the term ``SO2'' with 
``CO2 or O2.'' Set the new span and range in 
accordance with section 2.1.3 of this appendix and provide a 
rationale for the new span value in the monitoring plan.

2.1.4  Flow Monitors

    Select the full-scale range of the flow monitor so that it is 
consistent with section 2.1 of this appendix and can accurately 
measure all potential volumetric flow rates at the flow monitor 
installation site.

2.1.4.1  Maximum Potential Velocity and Flow Rate

    Make an initial determination of the maximum potential velocity 
(MPV) using Equation A-3a or A-3b, or determine the MPV (wet basis) 
from velocity traverse testing using Reference Method 2 (or its 
allowable alternatives) in appendix A to part 60 of this chapter. If 
using test values, use the highest average velocity (determined from 
the Method 2 traverses) measured at or near the maximum unit 
operating load. Express the MPV in units of wet standard feet per 
minute (fpm). For the purpose of providing substitute data during 
periods of missing flow rate data in accordance with Secs. 75.31 and 
75.33 and as required elsewhere in this part, calculate the maximum 
potential stack gas flow rate (MPF) in units of standard cubic feet 
per hour (scfh), as the product of the MPV (in units of wet, 
standard fpm) times 60, times the cross-sectional area of the stack 
or duct (in ft2) at the flow monitor location.

2.1.4.2  Span Values and Range

    Determine the span and range of the flow monitor as follows. 
Convert the MPV, as determined in section 2.1.4.1 of this appendix, 
to the same units of flow rate that are used for daily calibration 
error tests (e.g., scfh, kscfh, kacfm, or differential pressure 
(inches of water)). Next, determine the ``calibration span value'' 
by multiplying the MPV (converted to equivalent daily calibration 
error units) by a factor no less than 1.00 and no greater than 1.25, 
and rounding up the result to at least 2 significant figures. For 
calibration span values in inches of water, retain at least 2 
decimal places. Select appropriate reference signals for the daily 
calibration error tests as percentages of the calibration span 
value. Finally, calculate the ``flow rate span value'' (in scfh) as 
the product of the MPF, as determined in section 2.1.4.1 of this 
appendix, times the same factor (between 1.00 and 1.25) that was 
used to calculate the calibration span value. Round off the flow 
rate span value to the nearest 1000 scfh. Select the full-scale 
range of the flow monitor so that it is greater than or equal to the 
span value and is consistent with section 2.1 of this appendix. 
Include in the monitoring plan for the unit: calculations of the 
MPV, MPF, calibration span value, flow rate span value, and full-
scale range (expressed both in units of scfh and, if different, in 
the units of calibration).
[GRAPHIC] [TIFF OMITTED] TP21MY98.005

(Eq. A-3a)

or
[GRAPHIC] [TIFF OMITTED] TP21MY98.006


[[Page 28162]]


(Eq. A-3b)

Where:

MPV=maximum potential velocity (fpm, standard wet basis),
Fd=dry-basis F factor (dscf/mmBtu) from Table 1, Appendix 
F of this part,
Fc=carbon-based F factor (scfCO2/mmBtu) from 
Table 1, Appendix F this part,
HF=maximum heat input (mmBtu/minute) for all units, combined, 
exhausting to the stack or duct where the flow monitor is located,
A=inside cross sectional area (ft2) of the flue at the flow monitor 
location,
%O2d=maximum oxygen concentration, percent dry basis, 
under normal operating conditions,
%CO2d=minimum carbon dioxide concentration, percent dry 
basis, under normal operating conditions,
%H2O=maximum percent flue gas moisture content under 
normal operating conditions.

2.1.4.3  Adjustment of Span and Range

    For each affected unit or common stack, the owner or operator 
shall make a quarterly evaluation of the MPV, MPF, span, and range 
values for each flow rate monitor and shall make any necessary span 
and range adjustments with corresponding monitoring plan updates, as 
described in paragraphs (a) through (e), below. Span and range 
adjustments may be required as a result of changes in the fuel 
supply, changes in the stack or ductwork configuration, changes in 
the manner of operation of the unit, installation or removal of 
emission controls, etc. In implementing the provisions in paragraphs 
(a) through (e), below, note that flow rate data recorded during 
short-term, non-representative operating conditions (e.g., a trial 
burn of a different type of fuel) shall be excluded from the 
analysis; however, if the high range is exceeded, 200.0 percent of 
the full-scale range must still be reported as the hourly flow rate 
for each hour of the full-scale exceedance, in accordance with 
paragraph (c) of this section. The owner or operator shall document 
all such unrepresentative operating conditions in the quarterly 
report required under Sec. 75.64 and shall indicate which data have 
been excluded from the quarterly span and range evaluation. Make 
each required span or range adjustment no later than 45 days after 
the end of the quarter in which the need to adjust the span or range 
is identified.
    (a) No span or range adjustment is required if, during a 
calendar quarter, the hourly flow rate exceeds the MPF but does not 
exceed the flow rate span value. However, for missing data purposes, 
if any of the hourly flow rates exceed the current MPF by 
5.0 percent, a new MPF equal to the highest quality 
assured hourly flow rate recorded during the quarter must be defined 
in the monitoring plan. Update the monitoring plan to reflect the 
new MPF value.
    (b) A span adjustment is required whenever any of the on-scale, 
quality assured, hourly flow rates exceed the flow rate span value 
by 10.0 percent during a quarter. Define a new MPF equal 
to the highest on-scale flow rate recorded during the quarter, and 
set the new flow rate span value according to section 2.1.4.2 of 
this appendix. Then, calculate the new calibration span value by 
converting the new flow rate span value from units of scfh to units 
of daily calibration. If the new flow rate span value exceeds the 
current full-scale range, adjust the range setting also. Update the 
monitoring plan to reflect the new span and (if applicable) range 
values.
    (c) Whenever the full-scale range is exceeded during a quarter, 
provided that the exceedance is not caused by a monitor out-of-
control period, report 200.0 percent of the current full-scale range 
as the hourly flow rate for each hour of the full-scale exceedance. 
If the range is exceeded, make adjustments to the MPF, flow rate 
span, and range to prevent future full-scale exceedances. Calculate 
the new calibration span value by converting the new flow rate span 
value from units of scfh to units of daily calibration. A 
calibration error test must be performed and passed to validate data 
on the new range.
    (d) If the fuel supply, stack or ductwork configuration, 
operating parameters, or other conditions change such that the 
maximum potential flow rate changes significantly, adjust the span 
and range to assure the continued accuracy of the flow monitor. The 
owner or operator should evaluate whether any planned changes in 
operation of the unit may affect the flow of the unit or stack and 
should plan any necessary span and range changes needed to account 
for these changes, so that they are made in as timely a manner as 
practicable to coordinate with the operational changes. Calculate 
the adjusted calibration span and flow rate span values using the 
procedures in section 2.1.4.2 of this appendix.
    (e) Whenever changes are made to the MPV, MPF, full-scale range, 
or span value of the flow monitor, as described in paragraphs (a) 
through (d) of this section, record and report (as applicable) the 
new full-scale range setting, calculations of the flow rate span 
value, calibration span value, MPV, and MPF in an updated monitoring 
plan for the unit. The monitoring plan update shall be made in the 
quarter in which the changes become effective. Record and report the 
adjusted calibration span and reference values as parts of the 
records for the calibration error test required by appendix B to 
this part. Whenever the calibration span value is adjusted, use 
reference values for the calibration error test that meet the 
requirements of section 2.2.2.1 of this appendix, based on the most 
recent adjusted calibration span value. Perform a calibration error 
test according to section 2.1.1 of appendix B to this part whenever 
making a change to the flow monitor span or range, unless the range 
change also triggers a recertification under Sec. 75.20(b).

2.1.5  Moisture Sensors

    The span value of a continuous moisture sensor shall be equal to 
the full-scale range of the instrument. The range shall be selected 
in accordance with the requirements of section 2.1 of this appendix.
* * * * *
    54. Section 3 of appendix A to part 75 is amended by revising 
section 3.1 and the last sentence in the first paragraph of section 
3.2; by adding a new section 3.3.6; and by revising section 3.5, to 
read as follows:

3. Performance Specifications

3.1  Calibration Error

    The initial calibration error of SO2 and 
NOX pollutant concentration monitors shall not deviate 
from the reference value of either the zero or upscale calibration 
gas by more than 2.5 percent of the span of the instrument, as 
calculated using Equation A-5 of this appendix. Alternatively, where 
the span value is less than 200 ppm, calibration error test results 
are also acceptable if the absolute value of the difference between 
the monitor response value and the reference value, |R-A| in 
Equation A-5 of this appendix, is 5 ppm. The calibration 
error of CO2 or O2 monitors (including 
O2 monitors used to measure CO2 emissions or 
percent moisture) shall not deviate from the reference value of the 
zero or upscale calibration gas by >0.5 percent O2 or 
CO2, as calculated using the term |R-A| in the numerator 
of Equation A-5 of this appendix. The calibration error of flow 
monitors shall not exceed 3.0 percent of the calibration span value 
of the instrument, as calculated using Equation A-6 of this 
appendix. For differential pressure-type flow monitors, the 
calibration error test results are also acceptable if |R--A|, the 
absolute value of the difference between the monitor response and 
the reference value in Equation A-6, does not exceed 0.01 inches of 
water. The calibration error of a continuous moisture sensor shall 
not exceed 3.0 percent of the span value, as calculated using 
Equation A-5 of this appendix.

3.2  Linearity Check

    * * * For CO2 or O2 monitors (including 
O2 monitors used to measure CO2 emissions or 
percent moisture):
* * * * *

3.3  * * *

3.3.6  Relative Accuracy for Moisture Monitoring Systems

    The relative accuracy of a moisture monitoring system shall not 
exceed 10.0 percent. The relative accuracy test results are also 
acceptable if the mean difference of the reference method 
measurements (in percent H2O) and the corresponding 
moisture monitoring system measurements (in percent H2O) 
are within 1.0 percent H2O.
* * * * *

3.5  Cycle Time

    The cycle time for pollutant concentration monitors, oxygen 
monitors used to determine percent moisture, and any other 
continuous emission monitoring system(s) required to perform a cycle 
time test shall not exceed 15 minutes.

    55. Section 4 of appendix A to part 75 is amended by revising the 
introductory paragraph and paragraph (6) to read as follows:

[[Page 28163]]

4. Data Acquisition and Handling Systems

    Automated data acquisition and handling systems shall: (1) Read 
and record the full range of pollutant concentrations and volumetric 
flow from zero through span; and (2) provide a continuous, permanent 
record of all measurements and required information as an ASCII flat 
file capable of transmission both by direct computer-to-computer 
electronic transfer via modem and EPA-provided software and by an 
IBM-compatible personal computer diskette.
* * * * *
    (6) Provide a continuous, permanent record of all measurements 
and required information as an ASCII flat file capable of 
transmission both by direct computer-to-computer electronic transfer 
via modem and EPA-provided software and by an IBM-compatible 
personal computer diskette.

    56. Section 5 of appendix A to part 75 is amended by revising 
sections 5.1, 5.2.1, 5.2.2, 5.2.3, and 5.2.4 to read as follows:

5. Calibration Gas

5.1  Reference Gases

    For the purposes of part 75, calibration gases include the 
following:

5.1.1  Standard Reference Materials (SRM)

    These calibration gases may be obtained from the National 
Institute of Standards and Technology (NIST) at the following 
address: Quince Orchard and Cloppers Road, Gaithersburg, MD 20899-
0001.

5.1.2  SRM-Equivalent Compressed Gas Primary Reference Material (PRM)

    Contact the Gas Metrology Team, Analytical Chemistry Division, 
Chemical Science and Technology Laboratory of NIST, at the above 
address, for a list of vendors and cylinder gases.

5.1.3  NIST Traceable Reference Materials

    Contact the Gas Metrology Team, Analytical Chemistry Division, 
Chemical Science and Technology Laboratory of NIST, at the above 
address, for a list of vendors and cylinder gases.

5.1.4  EPA Protocol Gases

    EPA Protocol gases must be vendor-certified to be within 2.0 
percent of the concentration specified on the cylinder label (tag 
value), using the uncertainty calculation procedure in section 2.1.8 
of the ``EPA Traceability Protocol for Assay and Certification of 
Gaseous Calibration Standards,'' September 1997, EPA-600/R-97/121.
    A copy of EPA-600/R-97/121 is available from the National 
Technical Information Service, 5285 Port Royal Road, Springfield, VA 
703-487-4650 and from the Office of Research and Development, (MD-
77B), U.S. Environmental Protection Agency, Research Triangle Park, 
NC 27711, Attn: Berne Bennett, 919-541-2366.

5.1.5  Research Gas Mixtures

    Research gas mixtures must be vendor-certified to be within 2.0 
percent of the concentration specified on the cylinder label (tag 
value), using the uncertainty calculation procedure in section 2.1.8 
of the ``EPA Traceability Protocol for Assay and Certification of 
Gaseous Calibration Standards,'' September 1997, EPA-600/R-97/121. 
Inquiries about the RGM program should be directed to: National 
Institute of Standards and Technology, Analytical Chemistry 
Division, Chemical Science and Technology Laboratory, B-324 
Chemistry, Gaithersburg, MD 20899.

5.1.6  Zero Air Material

    Zero air material is defined in Sec. 72.2 of this chapter.

5.1.7  NIST/EPA-Approved Certified Reference Materials

    Existing certified reference materials (CRMs) that are still 
within their certification period may be used as calibration gas.

5.1.8  Gas Manufacturer's Intermediate Standards

    Gas manufacturer's intermediate standards is defined in 
Sec. 72.2 of this chapter.
* * * * *

5.2.1  Zero-level Concentration

    0.0 to 20.0 percent of span, including span for high-scale or 
both low-and high-scale for SO2, NOX, 
CO2, and O2 monitors, as appropriate.

5.2.2  Low-level Concentration

    20.0 to 30.0 percent of span, including span for high-scale or 
both low-and high-scale for SO2, NOX, 
CO2, and O2 monitors, as appropriate.

5.2.3  Mid-level Concentration

    50.0 to 60.0 percent of span, including span for high-scale or 
both low-and high-scale for SO2, NOX, 
CO2, and O2 monitors, as appropriate.

5.2.4  High-level Concentration

    80.0 to 100.0 percent of span, including span for high-scale or 
both low-and high-scale for SO2, NOX, 
CO2, and O2 monitors, as appropriate.

    57. Section 6 of appendix A to part 75 is amended by revising 
sections 6.2, 6.3.1, 6.5, 6.5.1, 6.5.2, 6.5.6, 6.5.7, and 6.5.9 to read 
as follows:

6. Certification Tests and Procedures

* * * * *

6.2  Linearity Check

    For the purposes of initial certification, recertification, and 
quality assurance, check the linearity of each SO2, 
NOX, CO2, and O2 monitor while the 
unit, or group of units for a common stack, is combusting fuel at 
conditions of typical stack temperature and pressure; it is not 
necessary for the unit to be generating electricity during this 
test. Notwithstanding these requirements, if the SO2 or 
NOX span value for a particular monitor range is 
30 ppm, that range is exempted from the linearity test 
requirements of this part.
    Challenge each monitor with calibration gas, as defined in 
section 5.1 of this appendix, at the low-, mid-, and high-range 
concentrations specified in section 5.2 of this appendix. For units 
using emission controls and other units using both a high and a low 
span, perform a linearity check on both the low-and high-scales for 
initial certification. For on-going quality assurance of the CEMS, 
perform linearity tests on the range(s) and at the frequency 
specified in section 2.2.1 of appendix B to this part.
    Introduce the calibration gas at the gas injection port, as 
specified in section 2.2.1 of this appendix. Operate each monitor at 
its normal operating temperature and conditions. For extractive and 
dilution type monitors, pass the calibration gas through all 
filters, scrubbers, conditioners, and other monitor components used 
during normal sampling and through as much of the sampling probe as 
is practical. For in-situ type monitors, perform calibration 
checking all active electronic and optical components, including the 
transmitter, receiver, and analyzer. Challenge the monitor three 
times with each reference gas (see example data sheet in Figure 1). 
Do not use the same gas twice in succession. The linearity check 
must be done hands-off, as follows. No adjustments other than the 
calibration adjustments described in section 2.1.3 of appendix B to 
this part are permitted prior to or during the linearity test 
period. To the extent practicable, the duration of each linearity 
test, from the hour of the first injection to the hour of the last 
injection, shall not exceed 24 unit operating hours. Record the 
monitor response from the data acquisition and handling system. For 
each concentration, use the average of the responses to determine 
the error in linearity using Equation A-4 in this appendix.
    Linearity checks are acceptable for monitor or monitoring system 
certification, recertification, or quality assurance if none of the 
test results exceed the applicable performance specifications in 
section 3.2 of this appendix.
    The status of emission data from a CEMS prior to and during a 
linearity test period shall be determined as follows:
    (a) For the initial certification of a CEMS, data from the 
monitoring system are considered invalid until all certification 
tests, including the linearity test, have been successfully 
completed, unless the data validation procedures in Sec. 75.20(b)(3) 
are used. When the procedures in Sec. 75.20(b)(3) are followed, 
substitute the words ``initial certification'' for 
``recertification,'' and complete all of the initial certification 
tests by the applicable deadline in Sec. 75.4, rather than within 
the time periods specified in Sec. 75.20(b)(3)(iv) for the 
individual tests.
    (b) For the routine quality assurance linearity checks required 
by section 2.2.1 of appendix B to this part, use the data validation 
procedures in section 2.2.3 of appendix B to this part.
    (c) When a linearity test is required as a diagnostic test or 
for recertification, use the data validation procedures in 
Sec. 75.20(b)(3).
    (d) For linearity tests of non-redundant backup monitoring 
systems, use the data validation procedures in 
Sec. 75.20(d)(2)(iii).
    (e) For linearity tests performed during a grace period and 
after the expiration of a grace period, use the data validation 
procedures in sections 2.2.3 and 2.2.4, respectively, of appendix B 
to this part.

[[Page 28164]]

6.3  * * *

6.3.1  Pollutant Concentration Monitor and CO2 or 
O2 Monitor 7-day Calibration Error Test

    For the purposes of initial certification and recertification, 
measure the calibration error of each pollutant concentration 
monitor and CO2 or O2 monitor while the unit 
is combusting fuel at conditions of typical temperature and pressure 
(but not necessarily generating electricity) once each day for 7 
consecutive operating days according to the following procedures. 
(In the event that extended unit outages occur after the 
commencement of the test, the 7 consecutive unit operating days need 
not be 7 consecutive calendar days.) Units using dual span monitors 
must perform the calibration error test on both high-and low-scales 
of the pollutant concentration monitor. The daily calibration error 
test procedures in this section shall also be used to perform the 
daily assessments and additional calibration error tests required 
under sections 2.1.1 and 2.1.3 of appendix B to this part.
    Do not make manual or automatic adjustments to the monitor 
settings until after taking measurements at both zero and high 
concentration levels for that day during the 7-day test. If 
automatic adjustments are made following both injections, conduct 
the calibration error test such that the magnitude of the 
adjustments can be determined and recorded. Record and report test 
results for each day using the unadjusted concentration measured in 
the calibration error test prior to making any manual or automatic 
adjustments (i.e., resetting the calibration).
    The calibration error tests should be approximately 24 hours 
apart, (unless the 7-day test is performed over non-consecutive 
days). Perform calibration error tests at both the zero-level 
concentration and either the mid-level or high-level concentration, 
as specified in section 5.2 of this appendix. In addition, repeat 
the procedure for SO2 and NOX pollutant 
concentration monitors using the low-scale for units equipped with 
emission controls or other units with dual span monitors. Use only 
calibration gas, as specified in section 5.1 of this appendix.
    Introduce the calibration gas at the gas injection port, as 
specified in section 2.2.1 of this appendix. Operate each monitor in 
its normal sampling mode. For extractive and dilution type monitors, 
pass the calibration gas through all filters, scrubbers, 
conditioners, and other monitor components used during normal 
sampling and through as much of the sampling probe as is practical. 
For in-situ type monitors, perform calibration, checking all active 
electronic and optical components, including the transmitter, 
receiver, and analyzer. Challenge the pollutant concentration 
monitors and CO2 or O2 monitors once with each 
calibration gas. Record the monitor response from the data 
acquisition and handling system. Using Equation A-5 of this 
appendix, determine the calibration error at each concentration once 
each day (at approximately 24-hour intervals) for 7 consecutive days 
according to the procedures given in this section.
    Calibration error tests are acceptable for monitor or monitoring 
system certification if none of these daily calibration error test 
results exceed the applicable performance specifications in section 
3.1 of this appendix.
    The status of emission data from a CEMS during a 7-day 
calibration error test period shall be determined as follows:
    (a) For the initial certification of a CEMS, data from the 
monitoring system are considered invalid until all certification 
tests, including the 7-day calibration error test, have been 
successfully completed, unless the data validation procedures in 
Sec. 75.20(b)(3) are used. When the procedures in Sec. 75.20(b)(3) 
are followed, substitute the words ``initial certification'' for 
``recertification,'' and complete all of the initial certification 
tests by the applicable deadline in Sec. 75.4, rather than within 
the time periods specified in Sec. 75.20(b)(3)(iv) for the 
individual tests.
    (b) When a 7-day calibration error test is required as a 
diagnostic test or for recertification, use the data validation 
procedures in Sec. 75.20(b)(3).
* * * * *

6.5  Relative Accuracy and Bias Tests

    For the purposes of initial certification, recertification, and 
quality assurance, perform the required relative accuracy test 
audits as follows for each CO2 and SO2 
pollutant concentration monitor, each flow monitor, each 
NOX continuous emission monitoring system, each 
O2 monitor used to calculate heat input or CO2 
concentration, each moisture monitoring system, and each 
SO2-diluent continuous emission monitoring system (lb/
mmBtu) used by units with a qualifying Phase I technology for the 
period during which the units are required to monitor SO2 
emission removal efficiency, from January 1, 1997 through December 
31, 1999:
    (a) All relative accuracy test audits shall be done ``hands-
off'', as follows:
    (1) No adjustments, linearizations, or reprogramming of the 
CEMS, other than the calibration adjustments described in section 
2.1.3 of appendix B to this part, are permitted prior to and during 
the RATA test period.
    (2) For 2-level and 3-level flow monitor audits, no re-
linearization of the monitor (i.e., changing of the polynomial 
coefficients) is permitted between load levels.
    (b) Except as provided in Sec. 75.21(a)(5), perform each RATA 
while the unit (or units, if more than one unit exhausts into the 
flue) is combusting the fuel that is normal for that unit (for some 
units, more than one type of fuel may be considered normal; e.g., a 
unit that combusts gas or oil on a seasonal basis). When relative 
accuracy test audits are performed on continuous emission monitoring 
systems or component(s) on bypass stacks/ducts, use the fuel 
normally combusted by the unit (or units, if more than one unit 
exhausts into the flue) when emissions exhaust through the bypass 
stack/ducts.
    (c) Perform each RATA at the load level(s) specified in section 
6.5.1 or 6.5.2 of this appendix or in section 2.3.1.3 of appendix B 
to this part, as applicable.
    (d) For monitoring systems with dual ranges, perform the 
relative accuracy test on the range normally used for measuring 
emissions. For units with add-on SO2 or NOX 
controls or for units that need a dual range to record high 
concentration ``spikes'' during startup conditions, the low range is 
considered normal. However, for some dual span units (e.g., for 
units that switch fuels and have both a high and low span value), 
either of the two measurement ranges may be considered normal; in 
such cases, perform the RATA on the range that is in use at the time 
of the scheduled test.
    (e) Record monitor or monitoring system output from the data 
acquisition and handling system.
    (f) For initial certification and recertification RATAs and for 
the quality assurance RATAs required by Sec. 75.20(d) or by section 
2.3.1 of appendix B to this part, complete each single-load relative 
accuracy test audit within a period of 168 consecutive unit 
operating hours. For 2-level and 3-level flow monitor RATAs, 
complete all of the RATAs at all levels, to the extent practicable, 
within a period of 168 consecutive unit operating hours; however, if 
this is not possible, up to 720 consecutive unit operating hours may 
be taken to complete a multiple-load flow RATA.
    (g) The status of emission data from the CEMS prior to and 
during the RATA test period shall be determined as follows:
    (1) For the initial certification of a CEMS, data from the 
monitoring system are considered invalid until all certification 
tests, including the RATA, have been successfully completed, unless 
the data validation procedures in Sec. 75.20(b)(3) are used. When 
the procedures in Sec. 75.20(b)(3) are followed, substitute the 
words ``initial certification'' for ``recertification,'' and 
complete all of the initial certification tests by the applicable 
deadline in Sec. 75.4, rather than within the time periods specified 
in Sec. 75.20(b)(3)(iv) for the individual tests.
    (2) For the routine quality assurance RATAs required by section 
2.3.1 of appendix B to this part, use the data validation procedures 
in section 2.3.2 of appendix B to this part.
    (3) For recertification RATAs, use the data validation 
procedures in Sec. 75.20(b)(3).
    (4) For quality assurance RATAs of non-redundant backup 
monitoring systems, use the data validation procedures in 
Secs. 75.20(d)(2)(v) and (vi).
    (5) For RATAs performed during and after the expiration of a 
grace period, use the data validation procedures in sections 2.3.2 
and 2.3.3, respectively, of appendix B to this part.
    (h) For each SO2 or CO2 pollutant 
concentration monitor, each flow monitor, and each NOX 
continuous emission monitoring system, calculate the relative 
accuracy, in accordance with section 7.4 of this appendix. In 
addition (except for CO2 monitors), test for bias and 
determine the appropriate bias adjustment factor, in accordance with 
sections 7.6.4 and 7.6.5 of this appendix, using the data from the 
relative accuracy test audits.

6.5.1  Gas Monitoring System RATAs (Special Considerations)

    (a) For the purposes of initial certification, recertification, 
and quality assurance, perform the required relative accuracy test 
audits for each SO2 or CO2 pollutant

[[Page 28165]]

concentration monitor, each O2 monitor, each 
NOX continuous emission monitoring system, and each 
SO2-diluent continuous emission monitoring system (lb/
mmBtu) used by units with a qualifying Phase I technology for the 
period during which the units are required to monitor SO2 
emission removal efficiency, from January 1, 1997 through December 
31, 1999, at the normal load level for the unit (or combined units, 
if common stack), as defined in section 6.5.2.1 of this appendix. If 
two load levels have been designated as normal, the RATAs may be 
done at either load level.
    (b) For the initial certification of a gas monitoring system and 
for recertifications in which, in addition to a RATA, one or more 
other tests are required (i.e., a linearity test, cycle time test, 
or 7-day calibration error test), EPA recommends that the RATA not 
be commenced until the other required tests of the CEMS have been 
passed.

6.5.2  Flow Monitor RATAs (Special Considerations)

    (a) Except for flow monitors on bypass stacks/ducts and peaking 
units, perform relative accuracy test audits for the initial 
certification of each flow monitor at three different exhaust gas 
velocities (low, mid, and high), corresponding to three different 
load levels within the range of operation, as defined in section 
6.5.2.1 of this appendix. For a common stack/duct, the three 
different exhaust gas velocities may be obtained from frequently 
used unit/load combinations for the units exhausting to the common 
stack. Select the three exhaust gas velocities such that the audit 
points at adjacent load levels (i.e., low and mid or mid and high), 
in megawatts (or in thousands of lb/hr of steam production), are 
separated by no less than 25.0 percent of the range of operation, as 
defined in section 6.5.2.1 of this appendix.
    (b) For flow monitors on bypass stacks/ducts and peaking units, 
the flow monitor relative accuracy test audits for initial 
certification and recertification shall be single-load tests, 
performed at the normal load, as defined in section 6.5.2.1 of this 
appendix.
    (c) The semiannual and annual quality assurance flow monitor 
RATAs required under appendix B to this part shall be done at the 
load level(s) specified in section 2.3.1.3 of appendix B.
    (d) Flow monitor recertification RATAs shall be done at three 
load level(s), unless otherwise specified in paragraph (b) of this 
section or unless otherwise approved by the Administrator.

6.5.2.1  Range of Operation and RATA Load Levels (Definitions)

    The owner or operator shall determine the upper and lower 
boundaries of the ``range of operation'' for each unit (or 
combination of units, for common-stack configurations) that uses 
CEMS to account for its emissions. The lower boundary of the range 
of operation of a unit shall be the minimum safe, stable load (or, 
for common-stacks, the lowest of the minimum safe, stable loads for 
any of the units discharging through the stack). The upper boundary 
of the range of operation of a unit shall be the maximum sustainable 
load. The ``maximum sustainable load'' is the higher of: (1) the 
nameplate or rated capacity of the unit, less any physical or 
regulatory limitations or other deratings, or (2) the highest 
sustainable unit load, based on at least four quarters of 
representative historical operating data. For common-stacks, the 
maximum sustainable load is the sum of all of the maximum 
sustainable loads of the individual units discharging through the 
stack, unless this load is unattainable in practice, in which case 
use the highest sustainable combined load for the units that 
discharge through the stack, based on at least four quarters of 
representative historical operating data. The load values for the 
unit(s) shall be expressed either in units of megawatts or thousands 
of lb/hr of steam load.
    The operating levels for relative accuracy test audits shall, 
except for peaking units, be defined as follows: (1) the low 
operating level shall be the first 30.0 percent of the range of 
operation; (2) the mid operating level shall be the middle portion 
(30.0 to 60.0 percent) of the range of operation; and (3) the high 
operating level shall be the upper end (60.0 to 100.0 percent) of 
the range of operation. For example, if the upper and lower 
boundaries of the range of operation are 100 and 1100 megawatts, 
respectively, then the low, mid, and high operating levels would be 
100 to 400 megawatts, 400 to 700 megawatts, and 700 to 1100 
megawatts, respectively.
    The provisions of this paragraph become effective January 1, 
2000. This determination shall be made just prior to conducting the 
quality assurance RATAs required under section 2.3 of appendix B of 
this part (in the same calendar quarter in which the RATAs are 
conducted) but not required more frequently than once a year, if the 
RATA(s) are conducted semiannually. The owner or operator shall 
determine, for each unit or common stack (except for peaking units) 
the load level (low, mid or high) that is the most frequently used. 
In addition, the owner or operator shall determine which load level 
is the second most frequently-used. To make the determinations, the 
owner or operator shall construct a historical load frequency 
distribution (e.g., histogram), depicting the relative number of 
operating hours at each of the three load levels, low, mid and high. 
The frequency distribution shall be based upon all available data 
from the four most recent QA operating quarters, as defined in 
section 2.3.1.1 of appendix B of this part. The owner or operator 
shall use the frequency distribution to determine, to the nearest 
0.1 percent, the percentage of the time that each load level (low, 
mid, high) has been used in the previous four QA operating quarters. 
A summary of the data used for these determinations shall be kept 
on-site in a format suitable for inspection and the results of the 
determinations shall be included in the electronic quarterly report 
under Sec. 75.64.
    Except for peaking units, the owner or operator shall designate 
the most frequently used load level as the normal load level for 
each unit (or combination of units, for common stacks). The owner or 
operator may also, if appropriate, designate the second most 
frequently used load level as an additional normal load level for 
the unit or stack. For peaking units, the entire operating load 
range shall be considered normal.
    Beginning on January 1, 2000, the owner or operator shall report 
the upper and lower boundaries of the range of operation for each 
unit (or combination of units, for common stacks), in units of 
megawatts or thousands of lb/hr of steam production, in the 
electronic quarterly report required under Sec. 75.64. Except for 
peaking units, the owner or operator shall also indicate in the 
electronic quarterly report: (1) the two load levels (low, mid, or 
high) that are the most frequently used, as determined under this 
section; (2) the relative (percent) historical usage of each load 
level, as determined under this section; and (3) the load level (or 
levels) designated as normal under this section.

6.5.2.2  Multi-Load Flow RATA Results

    For each multi-load flow RATA, calculate the flow monitor 
relative accuracy at each operating level. If a flow monitor 
relative accuracy test is failed or aborted due to a problem with 
the monitor on any level of a 2-level (or 3-level) relative accuracy 
test audit, the RATA must be repeated at that load level. However, 
the entire 2-level (or 3-level) relative accuracy test audit does 
not have to be repeated unless the flow monitor polynomial 
coefficients are changed, in which case a 3-level RATA is required.
* * * * *

6.5.6  Reference Method Traverse Point Selection

    Select traverse points that ensure acquisition of representative 
samples of pollutant and diluent concentrations, moisture content, 
temperature, and flue gas flow rate over the flue cross section. To 
achieve this, the reference method traverse points shall meet the 
requirements of section 3.2 of Performance Specification 2 (``PS No. 
2'') in appendix B to part 60 of this chapter (for SO2, 
NOX, and moisture monitoring system RATAs), Performance 
Specification 3 in appendix B to part 60 of this chapter (for 
O2 and CO2 monitor RATAs), Method 1 (or 1A) 
(for volumetric flow rate monitor RATAs), Method 3 (for molecular 
weight), and Method 4 (for moisture determination) in appendix A to 
part 60 of this chapter.
    The following alternative reference method traverse point 
locations are permitted for moisture and gas monitor RATAs:
    (a) For all moisture determinations, a single reference method 
point, located at least 1.0 meter from the stack wall, may be used.
    (b) For gas monitoring system RATAs, the owner or operator may 
use any of the following options:
    (1) At any location (including locations where stratification is 
expected), use a minimum of six traverse points along a diameter, in 
the direction of any expected stratification. The points shall be 
located in accordance with Method 1 in appendix A to part 60 of this 
chapter.
    (2) At locations where section 3.2 of PS No. 2 allows the use of 
a short reference method measurement line (with three points located 
at 0.4, 1.0, and 2.0 meters from the stack wall), the owner or 
operator may use an alternative 3-point measurement line, locating 
the three points at 4.4, 14.6, and 29.6 percent of the way across 
the stack, in

[[Page 28166]]

accordance with Method 1 in appendix A to part 60 of this chapter.
    (3) At locations where stratification is likely to occur (i.e., 
following a wet scrubber or when dissimilar gas streams are 
combined), the short measurement line from section 3.2 of PS No. 2 
(or the alternative line described in paragraph (c) of this section) 
may be used in lieu of the prescribed ``long'' measurement line in 
section 3.2 of PS No. 2, provided that the 12-point stratification 
test described in section 6.5.6.1 of this appendix is performed and 
passed one time at the location (according to the acceptance 
criteria of section 6.5.6.3(a) of this appendix) and provided that 
either the 12-point stratification test or the alternative 
(abbreviated) stratification test in section 6.5.6.2 of this 
appendix is performed and passed prior to each subsequent RATA at 
the location (according to the acceptance criteria of section 
6.5.6.3(a) of this appendix).
    (4) A single reference method measurement point, located no less 
than 1.0 meter from the stack wall, may be used at any sampling 
location if the 12-point stratification test described in section 
6.5.6.1 of this appendix is performed and passed one time at the 
location (according to the acceptance criteria of section 6.5.6.3(b) 
of this appendix) and provided that either the 12-point 
stratification test or the alternative (abbreviated) stratification 
test in section 6.5.6.2 of this appendix is performed and passed 
prior to each subsequent RATA at the location (according to the 
acceptance criteria of section 6.5.6.3(b) of this appendix).

6.5.6.1  Stratification Test

    (a) With the unit(s) operating under steady-state conditions at 
normal load, as defined in section 6.5.2.1 of this appendix, use a 
traversing gas sampling probe to measure the pollutant 
(SO2 or NOX) and diluent (CO2 or 
O2) concentrations at a minimum of twelve (12) points, 
located according to Method 1 in appendix A to part 60 of this 
chapter.
    (b) Use Methods 6C, 7E, and 3A in appendix A to part 60 of this 
chapter to make the measurements. Data from the reference method 
analyzers must be quality assured by performing analyzer calibration 
error and system bias checks before the series of measurements and 
by conducting system bias and calibration drift checks after the 
measurements, in accordance with the procedures of Methods 6C, 7E, 
and 3A.
    (c) Measure for a minimum of 2 minutes at each traverse point. 
To the extent practicable, complete the traverse within a 2-hour 
period.
    (d) If the load has remained constant ( 3.0 percent) 
during the traverse and if the reference method analyzers have 
passed all of the required quality assurance checks, proceed with 
the data analysis.
    (e) Calculate the average NOX, SO2, and 
CO2 (or O2) concentrations at each of the 
individual traverse points. Then, calculate the arithmetic average 
NOX, SO2, and CO2 (or 
O2) concentrations for all traverse points.

6.5.6.2  Alternative (Abbreviated) Stratification Test

    (a) With the unit(s) operating under steady-state conditions at 
normal load, as defined in section 6.5.2.1 of this appendix, use a 
traversing gas sampling probe to measure the pollutant 
(SO2 or NOX) and diluent (CO2 or 
O2) concentrations at three points. The points shall be located 
according to the specifications for the long measurement line in 
section 3.2 of PS No. 2 (i.e., locate the points 16.7 percent, 50.0 
percent, and 83.3 percent of the way across the stack). 
Alternatively, the concentration measurements may be made at six 
traverse points along a diameter. The six points shall be located in 
accordance with Method 1 in appendix A to part 60 of this chapter.
    (b) Use Methods 6C, 7E, and 3A in appendix A to part 60 of this 
chapter to make the measurements. Data from the reference method 
analyzers must be quality assured by performing analyzer calibration 
error and system bias checks before the series of measurements and 
by conducting system bias and calibration drift checks after the 
measurements, in accordance with the procedures of Methods 6C, 7E, 
and 3A.
    (c) Measure for a minimum of 2 minutes at each traverse point. 
To the extent practicable, complete the traverse within a 1-hour 
period.
    (d) If the load has remained constant ( 3.0 percent) 
during the traverse and if the reference method analyzers have 
passed all of the required quality assurance checks, proceed with 
the data analysis.
    (e) Calculate the average NOX, SO2, and 
CO2 (or O2) concentrations at each of the 
individual traverse points. Then, calculate the arithmetic average 
NOX, SO2, and CO2 (or 
O2) concentrations for all traverse points.

6.5.6.3  Stratification Test Results and Acceptance Criteria

    (a) For each pollutant or diluent gas, the short reference 
method measurement line described in section 3.2 of PS No. 2 may be 
used in lieu of the long measurement line prescribed in section 3.2 
of PS No. 2, if the results of a stratification test, conducted in 
accordance with section 6.5.6.1 or 6.5.6.2 of this appendix (as 
appropriate; see section 6.5.6(b)(3) of this appendix), show that 
the concentration at each individual traverse point differs by no 
more than 10.0 percent from the arithmetic average 
concentration for all traverse points. The results are also 
acceptable if the concentration at each individual traverse point 
differs by no more than 5 ppm or 0.5 percent 
CO2 (or O2) from the arithmetic average 
concentration for all traverse points.
    (b) For each pollutant or diluent gas, a single reference method 
measurement point, located at least 1.0 meter from the stack wall 
may be used for that pollutant or diluent gas if the results of a 
stratification test, conducted in accordance with section 6.5.6.1 or 
6.5.6.2 of this appendix (as appropriate; see section 6.5.6(b)(4) of 
this appendix), show that the concentration at each individual 
traverse point differs by no more than 5.0 percent from 
the arithmetic average concentration for all traverse points. The 
results are also acceptable if the concentration at each individual 
traverse point differs by no more than 3 ppm or 
0.3 percent CO2 (or O2) from the 
arithmetic average concentration for all traverse points.
    (c) The owner or operator shall keep the results of all 
stratification tests on-site, suitable for inspection, as part of 
the supplementary RATA records required under Sec. 75.56(a)(7) or 
Sec. 75.59(a)(7), as applicable.

6.5.7  Sampling Strategy

    Conduct the reference method tests so they will yield results 
representative of the pollutant concentration, emission rate, 
moisture, temperature, and flue gas flow rate from the unit and can 
be correlated with the pollutant concentration monitor, 
CO2 or O2 monitor, flow monitor, and 
SO2 or NOX continuous emission monitoring 
system measurements. The minimum acceptable time for a gas 
monitoring system RATA run or for a moisture monitoring system RATA 
run is 21 minutes. For each run of a gas monitoring system RATA, all 
necessary pollutant concentration measurements, diluent 
concentration measurements, and moisture measurements (if 
applicable) must, to the extent practicable, be made within a 60-
minute period. For NOX-diluent or SO2-diluent 
monitoring system RATAs, the pollutant and diluent concentration 
measurements must be made simultaneously. For flow monitor RATAs, 
the minimum time per run shall be 5 minutes. Flow rate reference 
method measurements may be made either sequentially from port to 
port or simultaneously at two or more sample ports. The velocity 
measurement probe may be moved from traverse point to traverse point 
either manually or automatically. If, during a flow RATA, 
significant pulsations in the reference method readings are 
observed, be sure to allow enough measurement time at each traverse 
point to obtain an accurate average reading (e.g., a ``sight-
weighted'' average from a manometer). A minimum of one set of 
auxiliary measurements for stack gas molecular weight determination 
(i.e., diluent gas data and moisture data) is required for every 
clock hour of a flow RATA or for every three test runs (whichever is 
less restrictive). Successive flow RATA runs may be performed 
without waiting in-between runs. If an O2-diluent monitor 
is used as a CO2 continuous emission monitoring system, 
perform a CO2 system RATA (i.e., measure CO2, 
rather than O2, with the reference method). To properly 
correlate individual SO2 or NOX continuous 
emission monitoring system data (in lb/mmBtu) and volumetric flow 
rate data with the reference method data, annotate the beginning and 
end of each reference method test run (including the exact time of 
day) on the individual chart recorder(s) or other permanent 
recording device(s).
* * * * *

6.5.9  Number of Reference Method Tests

    Perform a minimum of nine sets of paired monitor (or monitoring 
system) and reference method test data for every required (i.e., 
certification, recertification, semiannual, or annual) relative 
accuracy test audit. For 2-level and 3-level relative accuracy test 
audits of flow monitors, perform a minimum of nine sets at each of 
the operating levels.

    Note: The tester may choose to perform more than nine sets of 
reference method tests. If this option is chosen, the tester may 
reject a maximum of three sets of the test results, as long as the 
total number of test

[[Page 28167]]

results used to determine the relative accuracy or bias is greater 
than or equal to nine. Report all data, including the rejected CEM 
data and corresponding reference method test results.
* * * * *
    58. Section 7 of appendix A to part 75 is amended by revising the 
introductory text of section 7.2.1 and the term ``R'' following 
equation A-5 and by revising section 7.6.4; and by adding 4 paragraphs 
at the end of section 7.6.5 and a new section 7.7 to read as follows:

7. Calculations

* * * * *

7.2  * * *

7.2.1  Pollutant Concentration and Diluent Monitors

    For each reference value, calculate the percentage calibration 
error based upon instrument span for daily calibration error tests 
using the following equation:
* * * * *
(Eq. A-5)

Where:

R=Reference value of zero or upscale (high-level or mid-level, as 
applicable) calibration gas introduced into the monitoring system.
* * * * *

7.6.4   Bias Test

    For gas monitoring systems, if the mean difference, d, is 
greater than the absolute value of the confidence coefficient, |cc|, 
the monitor or monitoring system has failed to meet the bias test 
requirement. For flow monitor bias tests, if the mean difference, d, 
is greater than |cc| at any load level designated as normal under 
section 6.5.2.1 of this appendix, the monitor has failed to meet the 
bias test requirement.

7.6.5  * * *

    For single-load RATAs of SO2-and NOX-
diluent monitoring systems and for single-load flow RATAs required 
or allowed under section 6.5.2 of this appendix and sections 
2.3.1.3(b) and 2.3.1.3(c) of appendix B to this part, the 
appropriate BAF is determined directly from the RATA results at 
normal load, using Equation A-12. Notwithstanding, when a 
NOX or SO2 CEMS installed on a low-emitting 
affected unit (i.e., average SO2 concentration during the 
RATA <250 ppm or average NOX emission rate <0.200 lb/
mmBtu) meets the normal 10.0 percent relative accuracy specification 
(as calculated using Equation A-10) or the alternate relative 
accuracy specification in section 3.3 of this appendix for low-
emitters, but fails the bias test, the BAF may be determined using 
Equation A-12, or a default BAF of 1.111 may be used.
    For a 2-level flow RATA, if the RATA is passed but the bias test 
is failed at a load level designated as normal under section 6.5.2.1 
of this appendix, use Equation A-12 to calculate the bias adjustment 
factor at both of the operating levels. For a 3-level flow monitor 
relative accuracy test audit, if the RATA is passed but the bias 
test is failed at a load level designated as normal under section 
6.5.2.1 of this appendix, calculate bias adjustment factors only for 
the two most-frequently used load levels, as determined in section 
6.5.2.1 of this appendix. For both 2-level and 3-level flow RATAs, 
whenever the bias test is failed at a load level designated as 
normal under section 6.5.2.1 of this appendix, apply the larger of 
the two calculated bias adjustment factors to subsequent flow 
monitor data using Equation A-11.
    Each time a RATA is successfully completed and the appropriate 
bias adjustment factor has been determined, apply the BAF 
prospectively to all monitoring system data, beginning with the 
first clock hour following the hour in which the RATA was completed. 
For a 2-load flow RATA, the ``hour in which the RATA was completed'' 
refers to the hour in which the testing at both loads was completed; 
for a 3-load RATA, it refers to the hour in which the testing at all 
three loads was completed.
    Use the bias-adjusted values in computing substitution values in 
the missing data procedure, as specified in subpart D of this part, 
and in reporting the concentration of SO2, the flow rate, 
and the average NOX emission rate, the unit heat input, 
and the calculated mass emissions of SO2 and 
CO2 during the quarter and calendar year, as specified in 
subpart G of this part.

7.7  Reference Flow-to-Load Ratio or Gross Heat Rate

    The owner or operator shall determine Rref, the 
reference value of the ratio of flow rate to unit load, each time 
that a successful flow RATA is performed at a load level designated 
as normal in section 6.5.2.1 of this appendix. The owner or operator 
shall report the current value of Rref in the electronic 
quarterly report required under Sec. 75.64 and shall also report the 
completion date of the associated RATA. If two load levels have been 
designated as normal under section 6.5.2.1 of this appendix, the 
owner or operator shall determine a separate Rref value 
for each of the normal load levels. The requirements of this section 
shall become effective as of January 1, 2000. The reference flow-to-
load ratio shall be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TP21MY98.007

(Eq. A-13)

Where:

Rref=Reference value of the flow-to-load ratio, from the 
most recent normal-load flow RATA, scfh/megawatts or scfh/1000 lb/hr 
of steam.
Qref=Average stack gas volumetric flow rate measured by 
the reference method during the normal-load RATA, scfh.
Lavg=Average unit load during the normal-load flow RATA, 
megawatts or 1000 lb/hr of steam.

    In Equation A-13, for a common stack, Lavg shall be 
the sum of the operating loads of all units that discharge through 
the stack. For a unit that discharges its emissions through multiple 
stacks, Qref will be the sum of the total volumetric flow 
rates that discharge through all of the stacks. Round off the value 
of Rref to 2 decimal places.
    In addition to determining Rref or as an alternative 
to determining Rref, a reference value of the gross heat 
rate (GHR) may be determined. In order to use this option, quality 
assured diluent gas (CO2 or O2) must be 
available for each hour of the most recent normal-load flow RATA. 
The reference value of the GHR shall be determined as follows:
[GRAPHIC] [TIFF OMITTED] TP21MY98.008

(Eq. A-13a)

Where:

(GHR)ref=Reference value of the gross heat rate at the 
time of the most recent normal-load flow RATA, Btu/kwh or Btu/lb 
steam load.
(Heat Input)avg=Average hourly heat input during the 
normal-load flow RATA, as determined using the applicable equation 
in appendix F to this part, mmBtu/hr.
Lavg=Average unit load during the normal-load flow RATA, 
megawatts or 1000 lb/hr of steam.

    In the calculation of (Heat Input)avg, use 
Qref, the average volumetric flow rate measured by the 
reference method during the RATA, and use the average diluent gas 
concentration measured during the flow RATA.
* * * * *
    59. Section 1 of appendix B to part 75 is revised as follows:

Appendix B to Part 75--Quality Assurance and Quality Control 
Procedures

1. Quality Assurance/Quality Control Program

    Develop and implement a quality assurance/quality control (QA/
QC) program for the continuous emission monitoring systems, excepted 
monitoring systems approved under appendix D, E, or I to this part, 
and alternative monitoring systems under subpart E of this part, and 
their components. At a minimum, include in each QA/QC program a 
written plan that describes in detail (or that refers to separate 
documents containing) complete, step-by-step procedures and 
operations for each of the following activities. Upon request from 
regulatory authorities, the source shall make all procedures, 
maintenance records, and ancillary supporting documentation from the 
manufacturer (e.g., software coefficients and troubleshooting 
diagrams) available for review during an audit.

1.1  Requirements for All Monitoring Systems

1.1.1  Preventive Maintenance

    Keep a written record of procedures needed to maintain the 
monitoring system in proper operating condition and a schedule for 
those procedures. This shall, at a minimum, include procedures 
specified by the manufacturers of the equipment and, if applicable, 
additional or alternate procedures developed for the equipment.

[[Page 28168]]

1.1.2  Recordkeeping and Reporting

    Keep a written record describing procedures that will be used to 
implement the recordkeeping and reporting requirements in subparts 
E, F, and G and appendices D, E, and I of this part, as applicable.

1.1.3  Maintenance Records

    Keep a record of all testing, maintenance, or repair activities 
performed on any monitoring system or component in a location and 
format suitable for inspection. A maintenance log may be used for 
this purpose. The following records should be maintained: date, 
time, and description of any testing, adjustment, repair, 
replacement, or preventive maintenance action performed on any 
monitoring system and records of any corrective actions associated 
with a monitor's outage period. Additionally, any adjustment that 
recharacterizes a system's ability to record and report emissions 
data must be recorded (e.g., changing flow monitor polynomial 
coefficients, temperature and pressure coefficients, and dilution 
ratio settings), and a written explanation of the procedures used to 
make the adjustment(s) shall be kept.

1.2  Specific Requirements for Continuous Emissions Monitoring 
Systems

1.2.1  Calibration Error Test and Linearity Check Procedures

    Keep a written record of the procedures used for daily 
calibration error tests and linearity checks (e.g., how gases are to 
be injected, adjustments of flow rates and pressure, introduction of 
reference values, length of time for injection of calibration gases, 
steps for obtaining calibration error or error in linearity, 
determination of interferences, and when calibration adjustments 
should be made). Identify any calibration error test and linearity 
check procedures specific to the continuous emission monitoring 
system that vary from the procedures in appendix A to this part.

1.2.2  Calibration and Linearity Adjustments

    Explain how each component of the continuous emission monitoring 
system will be adjusted to provide correct responses to calibration 
gases, reference values, and/or indications of interference both 
initially and after repairs or corrective action. Identify 
equations, conversion factors, assumed moisture content, and other 
factors affecting calibration of each continuous emission monitoring 
system.

1.2.3  Relative Accuracy Test Audit Procedures

    Keep a written record of procedures and details peculiar to the 
installed continuous emission monitoring systems that are to be used 
for relative accuracy test audits, such as sampling and analysis 
methods.

1.2.4  Parametric Monitoring for Units with Add-on Emission Controls

    The owner or operator shall keep a written (or electronic) 
record including a list of operating parameters for the add-on 
SO2 or NOX emission controls, including 
parameters in Sec. 75.55(b) or Sec. 75.58(b), as applicable, and the 
range of each operating parameter that indicates the add-on emission 
controls are operating properly. The owner or operator shall keep a 
written (or electronic) record of the parametric monitoring data 
during each SO2 or NOX missing data period.

1.3  Specific Requirements for Excepted Systems Approved under 
Appendices D, E, and I

1.3.1  Fuel Flowmeter Accuracy Test Procedures

    Keep a written record of the specific fuel flowmeter accuracy 
test procedures. These may include: standard methods or 
specifications listed in Sec. 75.20(g) and section 2.1.5.1 of 
appendix D to this part and incorporated by reference under 
Sec. 75.6; the procedures of sections 2.1.5.2 or 2.1.7 of appendix D 
to this part; or other methods approved by the Administrator through 
the petition process of Sec. 75.66(c).

1.3.2  Transducer or Transmitter Accuracy Test Procedures

    Keep a written record of the procedures for testing the accuracy 
of transducers or transmitters of an orifice-, nozzle-, or venturi-
type fuel flowmeter under section 2.1.6 of appendix D to this part. 
These procedures should include a description of equipment used, 
steps in testing, and frequency of testing.

1.3.3  Fuel Flowmeter, Transducer, or Transmitter Calibration and 
Maintenance Records

    Keep a record of adjustments, maintenance, or repairs performed 
on the fuel flowmeter monitoring system. Keep records of the data 
and results for fuel flowmeter accuracy tests and transducer 
accuracy tests, consistent with appendix D to this part.

1.3.4  Primary Element Inspection Procedures

    Keep a written record of the standard operating procedures for 
inspection of the primary element (i.e., orifice, venturi, or 
nozzle) of an orifice-, venturi-, or nozzle-type fuel flowmeter. 
Examples of the types of information to be included are: what to 
examine on the primary element; how to identify if there is 
corrosion sufficient to affect the accuracy of the primary element; 
and what inspection tools (e.g., boroscope), if any, are used.

1.3.5  Fuel Sampling Method and Sample Retention

    Keep a written record of the standard procedures used to perform 
fuel sampling, either by utility personnel or by fuel supply company 
personnel. These procedures should specify the portion of the ASTM 
method used, as incorporated by reference under Sec. 75.6, or other 
methods approved by the Administrator through the petition process 
of Sec. 75.66(c). These procedures should describe safeguards for 
ensuring the availability of an oil sample (e.g., procedure and 
location for splitting samples, procedure for maintain sample splits 
on site, and procedure for transmitting samples to an analytical 
laboratory). These procedures should identify the ASTM analytical 
methods used to analyze sulfur content, gross calorific value, and 
density, as incorporated by reference under Sec. 75.6, or other 
methods approved by the Administrator through the petition process 
of Sec. 75.66(c).

1.3.6  Appendix E Monitoring System Quality Assurance Information

    Identify the unit manufacturer's recommended range of quality 
assurance- and quality control-related operating parameters. Keep 
records of these operating parameters for each hour of unit 
operation (i.e., fuel combustion). Keep a written record of the 
procedures used to perform NOX emission rate testing. 
Keep a copy of all data and results from the initial and from the 
most recent NOX emission rate testing, including the 
values of quality assurance parameters specified in section 2.3 of 
appendix E to this part.

1.3.7  Appendix I Additional Requirements

    1.3.7.1  For all appendix I systems, the fuel sampling and 
analysis requirements in section 1.3.5 of this appendix shall be 
met; and, for the diluent monitor, the Calibration Error Test and 
Linearity Check Procedures requirements in sections 1.2.1 and 1.2.2 
of this appendix shall be met.
    1.3.7.2  For appendix I systems that are certified according to 
the system certification procedures, the Relative Accuracy Test 
Audit Procedures requirement in section 1.2.3 of this appendix shall 
be met for the annual or semiannual Method 2 flow RATA.
    1.3.7.3  For appendix I systems that are certified according to 
the component-by-component certification procedures, the fuel 
flowmeter requirements applicable to the type of fuel flowmeter used 
in sections 1.3.1 through 1.3.5 of this appendix shall be met. The 
Relative Accuracy Test Audit Procedures requirement in section 1.2.3 
of this appendix shall be met for the diluent monitor that is part 
of the appendix I system.

1.4  Requirements for Alternative Systems Approved under Subpart E

1.4.1  Daily Quality Assurance Tests

    Explain how the daily assessment procedures specific to the 
alternative monitoring system are to be performed.

1.4.2  Daily Quality Assurance Test Adjustments

    Explain how each component of the alternative monitoring system 
will be adjusted in response to the results of the daily 
assessments.

1.4.3  Relative Accuracy Test Audit Procedures

    Keep a written record of procedures and details peculiar to the 
installed alternative monitoring system that are to be used for 
relative accuracy test audits, such as sampling and analysis 
methods.

    60. Section 2 of appendix B to part 75 is amended by:
    a. Revising sections 2.1.1, 2.1.3, 2.1.4, 2.2, 2.3; revising 
paragraph (1) of section 2.1.5.1;
    b. Redesignating existing section 2.4 as section 2.5; and
    c. Adding a new section 2.4, to read as follows:

[[Page 28169]]

2. Frequency of Testing

* * * * *

2.1  * * *

2.1.1  Calibration Error Test

    Except as provided in section 2.1.1.2 of this appendix, perform 
the daily calibration error test of each gas monitoring system 
(including moisture monitoring systems consisting of wet- and dry-
basis O2 analyzers) according to the procedures in 
section 6.3.1 of appendix A to this part, and perform the daily 
calibration error test of each flow monitoring system according to 
the procedure in section 6.3.2 of appendix A to this part. For 
continuous moisture sensors, follow the manufacturer's recommended 
procedures for the daily calibration error check. Include the 
calibration procedures as part of the quality assurance program 
required under section 1 of this appendix.
* * * * *

2.1.3  Additional Calibration Error Tests and Calibration Adjustments

    In addition to the daily calibration error tests required under 
section 2.1.1 of this appendix, a calibration error test of a CEMS 
shall be performed in accordance with section 2.1.1 of this 
appendix, as follows: (1) whenever a daily calibration error test is 
failed; (2) whenever a monitoring system is returned to service 
following repair or corrective maintenance that could affect the 
monitor's ability to accurately measure and record emissions data; 
and (3) after making certain calibration adjustments, as described 
in this section. In all cases, data from the CEMS are considered 
invalid until the required additional calibration error test has 
been successfully completed.
    Routine calibration adjustments of a monitor are permitted after 
any successful calibration error test. These routine adjustments 
shall be made so as to bring the monitor readings as close as 
practicable to the known tag values of the calibration gases or to 
the actual value of the flow monitor reference signals. An 
additional calibration error test is required following routine 
calibration adjustments where the monitor's calibration has been 
physically adjusted (e.g., by turning a potentiometer) to verify 
that the adjustments have been made properly. An additional 
calibration error test is not required, however, if the routine 
calibration adjustments are made by means of a mathematical 
algorithm programmed into the data acquisition and handling system. 
The EPA recommends that routine calibration adjustments be made, at 
a minimum, whenever the daily calibration error exceeds the limits 
of the applicable performance specification in appendix A to this 
part for the pollutant concentration monitor, CO2 or 
O2 monitor, or flow monitor.
    Additional (non-routine) calibration adjustments of a monitor 
are permitted, provided that an appropriate technical justification 
is included in the quality control program required under section 1 
of this appendix. The allowable non-routine adjustments are as 
follows. The owner or operator may physically adjust the calibration 
of a monitor (e.g., by means of a potentiometer), provided that the 
post-adjustment zero and upscale responses of the monitor are within 
the performance specifications of the instrument given in section 
3.1 of appendix A to this part. An additional calibration error test 
is required following such adjustments to verify that the monitor is 
operating within the performance specifications.

2.1.4  Data Validation

    (a) An out-of-control period occurs when the calibration error 
of an SO2 or NOX pollutant concentration 
monitor exceeds 5.0 percent of the span value (or exceeds 10 ppm, 
for span values <200 ppm), when the calibration error of a 
CO2 or O2 monitor (including O2 
monitors used to measure CO2 emissions or percent 
moisture) exceeds 1.0 percent O2 or CO2, or 
when the calibration error of a flow monitor or a moisture sensor 
exceeds 6.0 percent of the span value, which is twice the applicable 
specification of appendix A to this part. Notwithstanding, a 
differential pressure-type flow monitor for which the calibration 
error exceeds 6.0 percent of the span value shall not be considered 
out-of-control if |R-A|, the absolute value of the difference 
between the monitor response and the reference value in Equation A-
6, is 0.02 inches of water. The out-of-control period 
begins with the hour of completion of the failed calibration error 
test and ends with the hour following the hour of completion of a 
successful calibration error test. Note, however, that if the failed 
calibration, corrective action, and successful calibration error 
test occur within the same hour, emission data for that hour 
recorded by the monitor after the successful calibration error test 
may be used for reporting purposes, provided that 2 or more valid 
readings are obtained as required by Sec. 75.10. A NOX-
diluent continuous emission monitoring system is considered out-of-
control if the calibration error of either component monitor exceeds 
twice the applicable performance specification in appendix A to this 
part. Emission data shall not be reported from an out-of-control 
monitor.
    (b) An out-of-control period also occurs whenever interference 
of a flow monitor is identified. The out-of-control period begins 
with the hour of completion of the failed interference check and 
ends with the hour of completion of an interference check that is 
passed.

2.1.5  * * *

2.1.5.1  * * *

    (1) Data from a monitoring system are invalid, beginning with 
the first hour following the expiration of a 26-hour data validation 
period or beginning with the first hour following the expiration of 
an 8-hour start-up grace period (as provided under section 2.1.5.2 
of this appendix), if the required subsequent daily assessment has 
not been conducted.
* * * * *

2.2  Quarterly Assessments

    For each primary and redundant backup continuous emission 
monitoring system, perform the following quarterly assessments. This 
requirement is effective as of the calendar quarter following the 
calendar quarter in which the monitor or continuous emission 
monitoring system is provisionally certified.

2.2.1  Linearity Check

    Perform a linearity check, in accordance with the procedures in 
section 6.2 of appendix A to this part, for each primary and 
redundant backup SO2 and NOX pollutant 
concentration monitor and each primary and redundant backup 
CO2 or O2 monitor (including O2 
monitors used to measure CO2 emissions or to continuously 
monitor moisture) at least once during each QA operating quarter. A 
QA operating quarter is a calendar quarter in which the unit 
operates (i.e., combusts fuel) for at least 168 hours or, for common 
stacks and bypass stacks, a calendar quarter in which flue gases are 
discharged through the stack for at least 168 hours. For units using 
both a low and high span value, a linearity check is required only 
on the range(s) used to record and report emission data during the 
QA operating quarter. Conduct the linearity checks no less than 30 
days apart, to the extent practicable. The data validation 
procedures in section 2.2.3 of this appendix shall be followed.

2.2.2  Leak Check

    For differential pressure flow monitors, perform a leak check of 
all sample lines (a manual check is acceptable) at least once during 
each QA operating quarter. For this test, the unit does not have to 
be in operation. Conduct the leak checks no less than 30 days apart, 
to the extent practicable. If a leak check is failed, follow the 
applicable data validation procedures in section 2.2.3(f) of this 
appendix.

2.2.3  Data Validation

    (a) A routine quality assurance linearity test shall not be 
commenced if the monitoring system is operating out-of-control with 
respect to any of the daily, quarterly, or semiannual quality 
assurance assessments required by sections 2.1, 2.2, and 2.3 of this 
appendix or with respect to the additional calibration error test 
requirements in section 2.1.3 of this appendix.
    (b) Linearity checks shall be done hands-off, as follows. No 
adjustments of the monitor are permitted prior to or during the 
linearity test period, other than the routine and non-routine 
calibration adjustments described in section 2.1.3 of this appendix. 
The non-routine adjustments are permitted only prior to the test, 
not during the test period.
    (c) If a daily calibration error test is failed during a 
linearity test period, prior to completing the test, the linearity 
test is invalidated and must be repeated. Data from the monitor are 
invalidated prospectively from the hour of the failed calibration 
error test until the hour of completion of a subsequent successful 
calibration error test. The linearity test shall not be re-commenced 
until the monitor has successfully completed a calibration error 
test.
    (d) An out-of-control period occurs when a linearity test is 
failed (i.e., when the error in linearity at any of the three 
concentrations in the quarterly linearity check (or any of the six 
concentrations, when both ranges of a single analyzer with a dual 
range are tested) exceeds the applicable specification in

[[Page 28170]]

section 3.2 of appendix A to this part) or when a linearity test is 
aborted due to a problem with the CEMS. For a NOX-diluent 
or SO2-diluent continuous emission monitoring system, the 
system is considered out-of-control if either of the component 
monitors exceeds the applicable specification in section 3.2 of 
appendix A to this part or if the linearity test of either component 
is aborted due to a problem with the monitor. The out-of-control 
period begins with the hour of the failed or aborted linearity check 
and ends with the hour of completion of a satisfactory linearity 
check following corrective action and/or monitor repair. Note that a 
monitor shall not be considered out-of-control when a linearity test 
is aborted for a reason unrelated to the monitor's performance 
(e.g., a forced unit outage).
    (e) No more than four successive calendar quarters shall elapse 
after the quarter in which a linearity check of a CEMS (or range of 
a CEMS) was last performed without a subsequent linearity test 
having been conducted. If a linearity test has not been completed by 
the end of the fourth calendar quarter since the last linearity 
test, then the linearity test must be completed within a 168 unit 
operating hour ``grace period'' (as provided in section 2.2.4 of 
this appendix) following the end of the fourth successive elapsed 
calendar quarter, or data from the CEMS (or range) will become 
invalid.
    (f) An out-of-control period also occurs when a flow monitor 
sample line leak is detected. The out-of-control period begins with 
the hour of the failed leak check and ends with the hour of a 
satisfactory leak check following corrective action.
    (g) For each monitoring system, report the results of all 
completed and partial linearity tests that affect data validation 
(i.e., all completed, passed linearity checks; all completed, failed 
linearity checks; and all linearity checks aborted due to a problem 
with the monitor) in the quarterly report required under Sec. 75.64. 
Note that linearity attempts which are aborted or invalidated due to 
problems with the reference calibration gases or due to operational 
problems with the affected unit(s) need not be reported. Such 
partial tests do not affect the validation status of emission data 
recorded by the monitor. However, a record of all linearity tests 
and attempts (whether reported or not) must be kept on-site as part 
of the official test log for each monitoring system.

2.2.4  Linearity and Leak Check Grace Period

    When a required linearity test or flow monitor leak check has 
not been completed by the end of the QA operating quarter in which 
it is due or if, due to infrequent operation of a unit or infrequent 
use of a required high range of a CEMS, four successive calendar 
quarters have elapsed after the quarter in which a linearity check 
of a CEMS (or range) was last performed without a subsequent 
linearity test having been done, the owner or operator has a grace 
period of 168 consecutive unit operating hours in which to perform a 
linearity test or leak check of that CEMS (or range). The grace 
period begins with the first unit operating hour following the 
calendar quarter in which the linearity test was due. Data 
validation during a linearity or leak check grace period shall be 
done in accordance with the applicable provisions in section 2.2.3 
of this appendix.
    If, at the end of the 168 unit operating hour grace period, the 
required linearity test or leak check has not been completed, data 
from the monitoring system (or range) shall be invalid, beginning 
with the hour following the expiration of the grace period. Data 
from the monitoring system (or range) remain invalid until the hour 
of completion of a subsequent successful hands-off linearity test or 
leak check of the CEMS (or range). Note that when a linearity test 
or a leak check is conducted within a grace period for the purpose 
of satisfying the linearity test or leak check requirement from a 
previous QA operating quarter, the results of that linearity test or 
leak check may only be used to meet the linearity check or leak 
check requirement of the previous quarter, not the quarter in which 
the grace period is used.

2.2.5  Flow-to-Load Ratio or Gross Heat Rate Evaluation

    For each installed flow rate monitoring system on each unit or 
common stack, the owner or operator shall evaluate the flow-to-load 
ratio quarterly, i.e., for each QA operating quarter, as defined in 
sections 2.2.1 and 2.3.1.1 of this appendix. At the end of each QA 
operating quarter, the owner or operator shall use Equation B-1 in 
this appendix to calculate the flow-to-load ratio for every hour 
during the quarter in which: (1) the unit (or combination of units, 
for a common stack) operated within 10.0 percent of 
Lavg, the average load during the most recent normal-load 
flow RATA; and (2) a quality assured hourly average flow rate was 
obtained with a certified flow rate monitor.
[GRAPHIC] [TIFF OMITTED] TP21MY98.009

(Eq. B-1)

Where:

Rh = Hourly value of the flow-to-load ratio, scfh/
megawatts or scfh/1000 lb/hr of steam load.
Qh = Hourly stack gas volumetric flow rate, as measured 
by the flow rate monitor, scfh.
Lh = Hourly unit load, megawatts or 1000 lb/hr of steam; 
must be within 10.0 percent of Lavg during 
the most recent normal-load flow RATA.

    In Equation B-1, the owner or operator may use either bias-
adjusted flow rates or unadjusted flow rates, provided that all of 
the ratios are calculated the same way. For a common stack, 
Lh shall be the sum of the hourly operating loads of all 
units that discharge through the stack. For a unit that discharges 
its emissions through multiple stacks or monitors its emissions in 
multiple breechings, Qh will be the combined hourly volumetric flow 
rate for all of the stacks or ducts. Round off each value of 
Rh to 2 decimal places.
    Alternatively, the owner or operator may calculate the hourly 
gross heat rates (GHR) in lieu of the hourly flow-to-load ratios. 
The hourly GHR shall be determined only for those hours in which 
quality assured flow rate data and diluent gas (CO2 or 
O2) concentration data are both available from a 
certified CEMS or reference method. If this option is selected, 
calculate each hourly GHR value as follows:
[GRAPHIC] [TIFF OMITTED] TP21MY98.010

(Eq. B-1a)

Where:

(GHR)h = Hourly value of the gross heat rate, Btu/kwh or 
Btu/lb steam load.
(Heat Input)h = Hourly heat input, as determined from the 
quality assured flow rate and diluent data, using the applicable 
equation in appendix F to this part, mmBtu/hr.
Lh = Hourly unit load, megawatts or 1000 lb/hr of steam; 
must be within  10.0 percent of Lavg during 
the most recent normal-load flow RATA.

    In Equation B-1a, the owner or operator may either use bias-
adjusted flow rates or unadjusted flow rates in the calculation of 
(Heat Input)h, provided that all of the heat input values are 
determined in the same manner.
    The owner or operator shall evaluate the calculated hourly flow-
to-load ratios (or gross heat rates) as follows. A separate data 
analysis shall be performed for each primary and each redundant 
backup flow rate monitor used to record and report data during the 
quarter. Each analysis shall be based on a minimum of 168 hours of 
data. When two RATA load levels are designated as normal, the 
analysis shall be performed at the higher load level, unless there 
are fewer than 168 data points available at that load level, in 
which case the analysis shall be performed at the lower load level. 
If, for a particular flow monitor, fewer than 168 hourly flow-to-
load ratios (or GHR values) are available at any of the load levels 
designated as normal, a flow-to-load (or GHR) evaluation is not 
required for that monitor for that calendar quarter.
    For each flow monitor, use Equation B-2 in this appendix to 
calculate Eh, the absolute percentage difference between 
each hourly Rh value and Rref, the reference 
value of the flow-to-load ratio, as determined in accordance with 
section 7.7 of appendix A to this part. Note that Rref 
shall always be based upon the most recent normal-load RATA, even if 
that RATA was performed in the calendar quarter being evaluated.
[GRAPHIC] [TIFF OMITTED] TP21MY98.011

(Eq. B-2)

Where:

Eh = Absolute percentage difference between the hourly 
average flow-to-load ratio and the reference value of the flow-to-
load ratio at normal load.
Rh = The hourly average flow-to-load ratio, for each flow 
rate recorded at a load level within  10.0 percent of 
Lavg.

[[Page 28171]]

Rref = The reference value of the flow-to-load ratio from 
the most recent normal-load flow RATA, determined in accordance with 
section 7.7 of appendix A to this part.

    Equation B-2 shall be used in a consistent manner. That is, use 
Rref and Rh if the flow-to-load ratio is being 
evaluated, and use (GHR)ref and (GHR)h if the 
gross heat rate is being evaluated. Finally, calculate 
Ef, the arithmetic average of all of the hourly 
Eh values. The owner or operator shall report the results 
of each quarterly flow-to-load (or gross heat rate) evaluation, as 
determined from Equation B-2, in the electronic quarterly report 
required under Sec. 75.64.
    The results of a quarterly flow-to-load (or gross heat rate) 
evaluation are acceptable, and no further action is required, if the 
calculated value of Ef is less than or equal to: (i) 15.0 
percent, if Lavg for the most recent normal-load flow 
RATA is 50 megawatts (or 500 klb/hr of steam) 
and if unadjusted flow rates were used in the calculations; (ii) 
10.0 percent, if Lavg for the most recent normal-load 
flow RATA is 50 megawatts (or 500 klb/hr of 
steam) and if bias-adjusted flow rates were used in the 
calculations; (iii) 20.0 percent, if Lavg for the most 
recent normal-load flow RATA is <50 megawatts (or <500 klb/hr of 
steam) and if unadjusted flow rates were used in the calculations; 
or (iv) 15.0 percent, if Lavg for the most recent normal-
load flow RATA is <50 megawatts (or <500 klb/hr of steam) and if 
bias-adjusted flow rates were used in the calculations.
    If Ef is above these limits, the owner or operator 
shall: (a) implement Option 1 in section 2.2.5.1 of this appendix; 
(b) perform a RATA in accordance with Option 2 in section 2.2.5.2 of 
this appendix; or (c) re-examine the hourly data used for the flow-
to-load or GHR analysis and recalculate Ef, after 
excluding all non-representative hourly flow rates.
    If the owner or operator chooses to recalculate Ef, 
the flow rates for the following hours are considered non-
representative and may be excluded from the data analysis:
    (1) Any hour in which the type of fuel combusted was different 
from the fuel burned during the most recent normal-load RATA. For 
purposes of this determination, the type of fuel is different if the 
fuel is in a different state of matter (i.e., solid, liquid, or gas) 
than is the fuel burned during the RATA or if the fuel is a 
different classification of coal (e.g., bituminous versus sub-
bituminous);
    (2) Any hour in which an SO2 scrubber was bypassed;
    (3) Any hour in which ``ramping'' occurred, i.e., the hourly 
load differed by more than 15.0 percent from the load 
during the preceding hour or the subsequent hour;
    (4) If a normal-load flow RATA was performed and passed during 
the quarter being analyzed, any hour prior to completion of that 
RATA; and
    (5) If a problem with the accuracy of the flow monitor was 
discovered during the quarter and was corrected (as evidenced by 
passing the abbreviated flow-to-load test in section 2.2.5.3 of this 
appendix), any hour prior to completion of the abbreviated flow-to-
load test.
    After identifying and excluding all non-representative hourly 
data in accordance with (1) through (5) above, the owner or operator 
may analyze the remaining data a second time. At least 168 
representative hourly ratios or GHR values must be available to 
perform the analysis; otherwise, the flow-to-load (or GHR) analysis 
is not required for that monitor for that calendar quarter.
    If, after re-analyzing the data, Ef meets the 
applicable limit in (i),(ii), (iii), or (iv), above, no further 
action is required. If, however, Ef is still above the 
applicable limit, the monitor shall be declared out-of-control, 
beginning with the first hour of the quarter following the quarter 
in which Ef exceeded the applicable limit. The owner or 
operator shall then either implement Option 1 in section 2.2.5.1 of 
this appendix or Option 2 in section 2.2.5.2 of this appendix.

2.2.5.1  Option 1

    Within one week of the end of the calendar quarter for which the 
flow-to-load (or GHR) evaluation indicates noncompliance, 
investigate and troubleshoot each flow monitor for which 
Ef has been found to be above the applicable limit. 
Evaluate the results of each investigation as follows:
    (a) If the investigation fails to uncover a problem with the 
flow monitor, a RATA shall be performed in accordance with Option 2 
in section 2.2.5.2 of this appendix.
    (b) If a problem with the flow monitor is identified through the 
investigation (including the need to re-linearize the monitor by 
changing the polynomial coefficients), corrective actions shall be 
taken. All corrective actions (e.g., non-routine maintenance, 
repairs, major component replacements, re-linearization of the 
monitor, etc.) shall be documented in the operation and maintenance 
records for the monitor. Data from the monitor shall remain invalid 
until a probationary calibration error test of the monitor is passed 
following completion of all corrective actions, at which point data 
from the monitor are conditionally valid. The owner or operator 
shall then either: (1) complete the abbreviated flow-to-load test in 
section 2.2.5.3 of this appendix; or (2) perform a 3-level 
recertification RATA according to the recertification test period 
and data validation procedures of Sec. 75.20(b)(3), if the 
corrective action has affected the linearity of the flow monitor 
(e.g., by requiring changes to the flow monitor polynomial 
coefficients).

2.2.5.2  Option 2

    Perform a single-load RATA (at a load designated as normal under 
section 6.5.2.1 of appendix A to this part) of each flow monitor for 
which Ef is outside of the applicable limit. Data from 
the monitor remain invalid until the required RATA has been 
successfully completed.

2.2.5.3  Abbreviated Flow-to-Load Test

    The following abbreviated flow-to-load test may be performed 
after any documented repair, component replacement, or other 
corrective maintenance to a flow monitor (except for changes 
affecting the linearity of the flow monitor, such as adjusting the 
flow monitor coefficients) to demonstrate that the repair, 
replacement, or other maintenance has not significantly affected the 
monitor's ability to accurately measure the stack gas volumetric 
flow rate. Data from the monitoring system are considered invalid 
from the hour of commencement of the repair, replacement, or 
maintenance until the hour in which a probationary calibration error 
test is passed following completion of the repair, replacement, or 
maintenance and any associated adjustments to the monitor. The 
abbreviated flow-to-load test shall be completed within 168 unit 
operating hours of the probationary calibration error test (or, for 
peaking units, within 30 unit operating days, if that is less 
restrictive). Data from the monitor are considered to be 
conditionally valid (as defined in Sec. 72.2 of this chapter), 
beginning with the hour of the probationary calibration error test.
    Operate the unit(s) in such a way as to reproduce, as closely as 
practicable, the exact conditions at the time of the most recent 
normal-load flow RATA. To achieve this, it is recommended that the 
load be held constant to within 5.0 percent of the 
average load during the RATA and that the diluent gas 
(CO2 or O2) concentration be maintained within 
0.5 percent CO2 or O2 of the 
average diluent concentration during the RATA. For common stacks, to 
the extent practicable, use the same combination of units and load 
levels that were used during the RATA. When the process parameters 
have been set, record a minimum of 6 and a maximum of 12 consecutive 
hourly average flow rates, using the flow monitor(s) for which 
Ef was outside the applicable limit. For peaking units, a 
minimum of 3 and a maximum of 12 consecutive hourly average flow 
rates are required. Also record the corresponding hourly load values 
and, if applicable, the hourly diluent gas concentrations. Calculate 
the flow-to-load ratio (or GHR) for each hour in the test hour 
period, using Equation B-1 or B-1a. Determine Eh for each 
hourly flow-to-load ratio (or GHR), using Equation B-2 of this 
appendix and then calculate Ef, the arithmetic average of 
the Eh values.
    The results of the abbreviated flow-to-load test shall be 
considered acceptable, and no further action is required if the 
value of Ef does not exceed the applicable limit 
specified in section 2.2.5.1 of this appendix. All conditionally 
valid data recorded by the flow monitor shall be considered quality 
assured, beginning with the hour of the probationary calibration 
error test that preceded the abbreviated flow-to-load test. However, 
if Ef is outside the applicable limit, all conditionally 
valid data recorded by the flow monitor shall be considered invalid 
back to the hour of the probationary calibration error test that 
preceded the abbreviated flow-to-load test, and a single-load RATA 
is required in accordance with section 2.2.5.2 of this appendix. If 
the flow monitor must be re-linearized, however, a 3-load RATA is 
required, in accordance with the recertification test period and 
data validation procedures of Sec. 75.20(b)(3).

2.3  Semiannual and Annual Assessments

    For each primary and redundant backup continuous emission 
monitoring system, perform relative accuracy assessments either

[[Page 28172]]

semiannually or annually, as specified in subsection 2.3.1.1 or 
2.3.1.2, below, for the type of test and the performance achieved. 
This requirement is effective as of the calendar quarter following 
the calendar quarter in which the continuous emission monitoring 
system is provisionally certified. A summary chart showing the 
frequency with which a relative accuracy test audit must be 
performed, depending on the accuracy achieved, is located at the end 
of this appendix in Figure 2.

2.3.1  Relative Accuracy Test Audit (RATA)

2.3.1.1  Standard RATA Frequencies

    Except as otherwise specified in Sec. 75.21(a)(6) or (a)(7) or 
in section 2.3.1.2 of this appendix, perform relative accuracy test 
audits semiannually, i.e., once every two successive QA operating 
quarters for each primary and redundant backup SO2 
pollutant concentration monitor, flow monitor, CO2 
pollutant concentration monitor (including O2 monitors used to 
determine CO2 emissions), moisture monitoring system, 
NOX-diluent continuous emission monitoring system, or 
SO2-diluent continuous emission monitoring system used by 
units with a Phase I qualifying technology for the period during 
which the units are required to monitor SO2 emission 
removal efficiency, from January 1, 1997 through December 31, 1999. 
A QA operating quarter is a calendar quarter in which the unit 
operates for at least 168 hours or, for a common stack or bypass 
stack, a calendar quarter in which flue gases are discharged through 
the stack for at least 168 hours. A calendar quarter that does not 
qualify as a QA operating quarter shall be excluded in determining 
the deadline for the next RATA. No more than eight successive 
calendar quarters shall elapse after the quarter in which a RATA was 
last performed without a subsequent RATA having been conducted. If a 
RATA has not been completed by the end of the eighth calendar 
quarter since the quarter of the last RATA, then the RATA must be 
completed within a 720 unit operating hour grace period (as provided 
in section 2.3.3 of this appendix) following the end of the eighth 
successive elapsed calendar quarter, or data from the CEMS will 
become invalid.
    The relative accuracy test audit frequency of a CEMS may be 
reduced, as specified in subsection 2.3.1.2, below, for primary or 
redundant backup monitoring systems which qualify for less frequent 
testing. Perform all required RATAs in accordance with the 
applicable procedures and provisions in sections 6.5 through 6.5.2.2 
of appendix A to this part and subsections 2.3.1.3 and 2.3.1.4 of 
this appendix.

2.3.1.2  Reduced RATA Frequencies

    Relative accuracy test audits of primary and redundant backup 
SO2 pollutant concentration monitors, CO2 
pollutant concentration monitors (including O2 monitors used to 
determine CO2 emissions), moisture monitors, flow 
monitors, or NOX-diluent or SO2-diluent 
monitoring systems may be performed annually (i.e., once every four 
successive QA operating quarters, rather than once every two 
successive QA operating quarters) if any of the following conditions 
are met for the specific monitoring system involved: (1) the 
relative accuracy during the audit of an SO2 or 
CO2 pollutant concentration monitor (including an O2 
pollutant monitor used to measure CO2 using the 
procedures in appendix F to this part) or of a NOX-
diluent or SO2-diluent continuous emissions monitoring 
system is 7.5 percent; (2) prior to January 1, 2000, the 
relative accuracy during the audit of a flow monitor is 
10.0 percent at each operating level tested; (3) on and 
after January 1, 2000, the relative accuracy during the audit of a 
flow monitor is 7.5 percent at each operating level 
tested; (4) on low flow (10.0 fps) stacks/ducts, when 
flow monitor achieves a relative accuracy 7.5 percent 
(10.0 percent if prior to January 1, 2000) during the audit or when 
the monitor mean, calculated using Equation A-7 in appendix A to 
this part, is within 1.5 fps of the reference method 
mean; (5) on low SO2 emitting units (average 
SO2 concentrations 250 ppm, or average SO2 
emission rate 0.500 lb/mmBtu for SO2-diluent continuous 
emission monitoring systems), when the CEMS achieves a relative 
accuracy 7.5 percent during the audit or when the monitor 
mean value from the RATA is within  12 ppm (or 0.025 lb/
mmBtu for SO2-diluent continuous emission monitoring 
systems) of the reference method mean value; (6) on low 
NOX emitting units (average NOX emission rate 
0.200 lb/mmBtu), when the NOX continuous 
emission monitoring system achieves a relative accuracy 
7.5 percent or when the monitoring system mean value from 
the RATA, calculated using Equation A-7 in appendix A to this part, 
is within  0.015 lb/mmBtu of the reference method mean 
value; (7) for a CO2 or O2 monitor, when the mean 
difference between the reference method values from the RATA and the 
corresponding monitor values is within 0.7 percent 
CO2 or O2; and (8) when the relative accuracy of a 
continuous moisture monitoring system is 7.5 percent or 
when the mean difference between the reference method values from 
the RATA and the corresponding monitoring system values is within 
0.7 percent H2O.

2.3.1.3  RATA Load Levels

    (a) For SO2 pollutant concentration monitors, 
CO2 pollutant concentration monitors (including 
O2 monitors used to determine CO2 emissions), 
moisture monitoring systems, and SO2-diluent and 
NOX-diluent monitoring systems, the required RATA tests 
shall be done at the load level designated as normal under section 
6.5.2.1 of appendix A to this part. If two load levels are 
designated as normal, the required RATA(s) may be done at either 
load level.
    (b) For flow monitors installed on peaking units and bypass 
stacks, all required relative accuracy test audits shall be single-
load audits at the normal load, as defined in section 6.5.2.1 of 
appendix A to this part.
    (c) For all other flow monitors, the RATAs shall be performed as 
follows. When a flow monitor qualifies for an annual RATA frequency 
under section 2.3.1.2 of this appendix, the annual RATA shall be 
done at the two most frequently used load levels, as determined 
under section 6.5.2.1 of appendix A to this part. The annual 2-load 
flow RATA may be performed alternately with a single-load flow RATA 
at the most frequently used (normal) load level if the flow monitor 
is on a semiannual RATA frequency. In addition, a single-load flow 
RATA, at the most frequently used load level, may be performed in 
lieu of the 2-load RATA if, for the four QA operating quarters prior 
to the quarter in which the RATA is performed, the historical load 
frequency distribution determined under section 6.5.2.1 of appendix 
A to this part shows that the unit has operated at the most 
frequently used load level for 85.0 percent of the time. 
Finally, a 3-load RATA, at the low-, mid-, and high-load levels, 
determined under section 6.5.2.1 of appendix A to this part, shall 
be performed at least once in every period of five consecutive 
calendar years, and a 3-load RATA is required whenever a flow 
monitor is re-linearized, i.e., when one or more of its polynomial 
coefficients are changed. For all multi-level flow audits, the audit 
points at adjacent load levels (e.g., mid and high) shall be 
separated by no less than 25.0 percent of the ``range of 
operation,'' as defined in section 6.5.2.1 of appendix A to this 
part.

2.3.1.4  Number of RATA Attempts

    The owner or operator may perform as many RATA attempts as are 
necessary to achieve the desired relative accuracy test audit 
frequencies and/or bias adjustment factors. However, the data 
validation procedures in section 2.3.2 of this appendix must be 
followed.

2.3.2  Data Validation

    (a) A routine quality assurance RATA shall not commence if the 
monitoring system is operating out-of-control with respect to any of 
the daily and quarterly quality assurance assessments required by 
sections 2.1 and 2.2 of this appendix or with respect to the 
additional calibration error test requirements in section 2.1.3 of 
this appendix.
    (b) All RATAs must be done hands-off, as follows. No adjustment 
of the monitor's calibration is permitted prior to or during the 
RATA test period, other than the adjustments described in section 
2.1.3 of this appendix. The non-routine calibration adjustments 
described in section 2.1.3 of this appendix are permitted only prior 
to the RATA, not during the test period. For 2-level and 3-level 
flow monitor audits, no linearization of the monitor is permitted 
in-between load levels.
    (c) For single-load RATAs, if a daily calibration error test is 
failed during a RATA test period, prior to completing the test, the 
RATA is invalidated and must be repeated. Data from the monitor are 
invalidated prospectively from the hour of the failed calibration 
error test until the hour of completion of a subsequent successful 
RATA. The subsequent RATA shall not be re-commenced until the 
monitor has successfully passed a calibration error test in 
accordance with section 2.1.3 of this appendix. For multiple-load 
flow RATAs, each load level is treated as a separate RATA (i.e., 
when a calibration error test is failed prior to completing the RATA 
at a particular load level, only the RATA at that load level is 
invalidated; the results of any previously-passed RATA(s) at the 
other load level(s) are unaffected).
    (d) If a RATA is failed (that is, if the relative accuracy 
exceeds the applicable

[[Page 28173]]

specification in section 3.3 of appendix A to this part) or if the 
RATA is aborted prior to completion due to a problem with the CEMS, 
then all emission data from the CEMS are invalidated prospectively 
from the hour in which the RATA is failed or aborted. Data from the 
CEMS remain invalid until the hour of completion of a subsequent 
RATA that meets the applicable specification in section 3.3 of 
appendix A to this part. Note that a monitoring system shall not be 
considered out-of-control when a RATA is aborted for a reason other 
than monitoring system malfunction (see paragraph (g) of this 
section).
    (e) For a 2-level or 3-level flow RATA, if, at any load level, a 
RATA is failed or aborted due to a problem with the CEMS, the RATA 
at that load level must be repeated. Data from the flow monitor are 
invalidated from the hour in which the test is failed or aborted and 
remain invalid until the successful completion of a RATA at the 
failed load level. RATA(s) that were previously passed at the other 
load level(s) do not have to be repeated unless the flow monitor 
must be re-linearized following the failed or aborted test. If the 
monitor is re-linearized, a subsequent 3-load RATA is required.
    (f) For a CO2 pollutant concentration monitor (or an 
O2 monitor used to measure CO2 emissions) 
which also serves as the diluent component in a NOX-
diluent (or SO2-diluent) monitoring system, if the 
CO2 (or O2) RATA is failed, then both the 
CO2 (or O2) monitor and the associated 
NOX-diluent (or SO2-diluent) system are 
considered out-of-control until the hour of completion of subsequent 
hands-off RATAs which demonstrate that both systems have met the 
applicable relative accuracy specifications in sections 3.3.2 and 
3.3.3 of appendix A to this part. The out-of-control period for each 
monitoring system begins with the hour of completion of the failed 
CO2 (or O2) monitor RATA.
    (g) For each monitoring system, report the results of all 
completed and partial RATAs that affect data validation (i.e., all 
completed, passed RATAs; all completed, failed RATA; and all RATAs 
aborted due to a problem with the CEMS) in the quarterly report 
required under Sec. 75.64. Note that RATA attempts that are aborted 
or invalidated due to problems with the reference method or due to 
operational problems with the affected unit(s) need not be reported. 
Such runs do not affect the validation status of emission data 
recorded by the CEMS. In addition, aborted RATA attempts that are 
part of the process of optimizing a monitoring system's performance 
do not have to be reported, provided that, in the period extending 
from the hour in which the test is aborted to the hour of 
commencement of the next RATA attempt: (1) no corrective maintenance 
or reprogramming of the monitoring system is done; and (2) only the 
calibration adjustments allowed under section 2.1.3 of this appendix 
are made. However, a record of all RATAs and RATA attempts (whether 
reported or not) must be kept on-site as part of the official test 
log for each monitoring system.
    (h) Each time that a hands-off RATA of an SO2 
pollutant concentration monitor, a NOX-diluent monitoring 
system, or a flow monitor is successfully completed, perform a bias 
test in accordance with section 7.6.4 of appendix A to this part. 
Apply the appropriate bias adjustment factor to the reported 
SO2, NOX, or flow rate data, in accordance 
with section 7.6.5 of appendix A to this part.
    (i) Failure of the bias test does not result in the monitoring 
system being out-of-control.

2.3.3  RATA Grace Period

    The owner or operator has a grace period of 720 consecutive unit 
operating hours in which to complete the required RATA for a 
particular CEMS, whenever: (a) a required RATA has not been 
performed by the end of the QA operating quarter in which it is due; 
(b) five consecutive calendar years have elapsed without a required 
3-load flow RATA having been conducted; (c) an SO2 RATA 
has not been completed by the end of the calendar quarter in which 
the annual usage of fuel(s) with a total sulfur content greater than 
the total sulfur content of natural gas exceeds 480 hours, for a 
unit which is conditionally exempted under Sec. 75.21(a)(7) from the 
SO2 RATA requirements of this part; or (d) eight 
successive calendar quarters have elapsed, following the quarter in 
which a RATA was last performed, without a subsequent RATA having 
been done, due to: (1) infrequent operation of the unit(s); (2) 
frequent combustion of fuel(s) with a total sulfur content no 
greater than the total sulfur content of natural gas (i.e., 
0.05 percent sulfur by weight) (SO2 monitors, 
only); or (3) a combination of factors (1) and (2).
    Except for SO2 monitoring system RATAs, the grace 
period shall begin with the first unit operating hour following the 
calendar quarter in which the required RATA was due. For 
SO2 monitor RATAs, the grace period shall begin with the 
first unit operating hour in which fuel with a total sulfur content 
greater than the total sulfur content of natural gas (i.e., >0.05 
percent sulfur by weight) is burned in the unit(s), following the 
quarter in which the required RATA is due. Data validation during a 
RATA grace period shall be done in accordance with the applicable 
provisions in section 2.3.2 of this appendix.
    If, at the end of the 720 unit operating hour grace period, the 
RATA has not been completed, data from the monitoring system shall 
be invalid, beginning with the first unit operating hour following 
the expiration of the grace period. Data from the CEMS remain 
invalid until the hour of completion of a subsequent hands-off RATA. 
Note that when a RATA (or RATAs, if more than one attempt is made) 
is done during a grace period in order to satisfy a RATA requirement 
from a previous quarter (i.e., for reasons (a), (b), or (d) in this 
section), the deadline for the next RATA shall be determined from 
the quarter in which the RATA was due, not from the quarter in which 
the grace period is used.

2.3.4  Bias Adjustment Factor

    Except as otherwise specified in section 7.6.5 of appendix A to 
this part, if an SO2 pollutant concentration monitor, 
flow monitor, or NOX continuous emission monitoring 
system fails the bias test specified in section 7.6 of appendix A to 
this part, use the bias adjustment factor given in Equations A-11 
and A-12 of appendix A to this part to adjust the monitored data.

2.4  Recertification, Quality Assurance, and RATA Deadlines

    When a significant change is made to a monitoring system such 
that recertification of the monitoring system is required in 
accordance with Sec. 75.20(b), a recertification test (or tests) 
must be performed to ensure that the CEMS continues to generate 
valid data. In many instances, a required recertification test is 
the same type of test as one of the routine, periodic quality 
assurance tests required by this appendix (e.g., a linearity test or 
a RATA). When this occurs, the recertification test may be used to 
satisfy the quality assurance test requirement of this appendix. For 
example, if, for a particular change made to a CEMS, one of the 
required recertification tests is a linearity check and the 
linearity test is successful, then, unless another recertification 
event occurs in that same QA operating quarter, it would not be 
necessary to perform a subsequent linearity test of the CEMS in that 
quarter. For this reason, EPA recommends that owners or operators 
coordinate component replacements, system upgrades, and other events 
that may require recertification, to the extent practicable, with 
the periodic quality assurance testing required by this appendix. 
When a quality assurance test is done for the dual purpose of 
recertification and routine quality assurance, the applicable data 
validation procedures in Sec. 75.20(b)(3) shall be followed in lieu 
of the procedures in this appendix.
    Except as provided in section 2.3.3 of this appendix, whenever a 
successful RATA of a gas monitor or a successful 2-load or 3-load 
RATA of a flow monitor is performed (irrespective of whether the 
RATA is done to satisfy a recertification requirement or to meet the 
quality assurance requirements of this appendix, or both), the 
deadline for the next RATA shall be established based upon the date 
and time of completion of the RATA and the relative accuracy 
percentage obtained. For 2-load and 3-load flow RATAs, use the 
highest percentage relative accuracy at any of the loads to 
determine the deadline for the next RATA. The results of a single-
load flow RATA may be used to establish a RATA deadline when: (1) 
the single-load flow RATA is specifically required under section 
2.3.1.3(b) of this appendix (for flow monitors installed on peaking 
units and bypass stacks); or (2) the single-load RATA is allowed for 
a unit that has operated at the most frequently used load level for 
85.0 percent of the time, under section 2.3.1.3(c) of 
this appendix. No other single-load flow RATA may be used to 
establish an annual RATA frequency; however, a 2-load flow RATA may 
be performed in place of any required single-load RATA, in order to 
establish an annual RATA frequency.

2.5  Other Audits

* * * * *
    61. Figures 1 and 2 at the end of appendix B are revised to read as 
follows:

[[Page 28174]]



                                 Figure 1.--Quality Assurance Test Requirements                                 
----------------------------------------------------------------------------------------------------------------
                                                                         QA test frequency requirements         
                             Test                             --------------------------------------------------
                                                                    Daily*         Quarterly*      Semiannual*  
----------------------------------------------------------------------------------------------------------------
Calibration Error (2 pt.)....................................                                            
Interference (flow)..........................................                                            
Flow-to-Load Ratio...........................................  ...............                           
Leak Check (DP flow monitors)................................  ...............                           
Linearity (3 pt.)............................................  ...............                           
RATA (SO2, NOX, CO2, percent H2O) 1..........................  ...............                           
RATA (flow ) 1, 2............................................  ...............  ...............          
----------------------------------------------------------------------------------------------------------------
*For monitors on bypass stack/duct, ``daily'' means bypass operating days, only. ``Quarterly'' means once every 
  QA operating quarter. ``Semiannual'' means once every two QA operating quarters.                              
1 Conduct RATA annually (i.e., once every four QA operating quarters), if monitor meets accuracy requirements to
  qualify for less frequent testing.                                                                            
2 For flow monitors installed on peaking units and bypass stacks, conduct all RATAs at a single, normal load.   
  For other flow monitors, conduct RATAs at the two most frequently used loads. Alternating single-load and 2-  
  load RATAs may be done if a monitor is on a semiannual frequency. A single-load RATA may be done in lieu of a 
  2-load RATA if, in the past four QA operating quarters, the unit has operated at one load level for  85.0 percent of the time. A 3-load RATA is required at least once in every period of five consecutive     
  calendar years and whenever a flow monitor is re-linearized.                                                  


                          Figure 2.--Relative Accuracy Test Frequency Incentive System                          
----------------------------------------------------------------------------------------------------------------
                     RATA                           Semiannual1  (percent)                   Annual1            
----------------------------------------------------------------------------------------------------------------
SO2..........................................  7.5% < RA  10.0% or    RA  7.5.% or  15.0 ppm 2.          minus> 12.0 ppm 2             
SO2/diluent..................................  7.5% < RA  10.0% or    RA  7.5% or  0.030 lb/mmBtu 2.    minus> 0.025 lb/mmBtu 2       
NOX/diluent..................................  7.5% < RA  10.0% or    RA  7.5% or  0.020 lb/mmBtu 2.    minus>0.015 lb/mmBtu 2        
Flow (Phase I)...............................  10.0% < RA  15.0% or   RA  10.0%           
                                                 1.5 fps 2.                                         
Flow (Phase II)..............................  7.5% < RA  10.0% or    RA  7.5%            
                                                 1.5 fps 2.                                         
CO2/O2.......................................  7.5% < RA  10.0% or    RA  7.5% or  1.0% CO2/O22.        minus> 0.7% CO2/O22           
Moisture.....................................  7.5% < RA  10.0% or    RA  7.5% or  1.0% H2O2.           minus> 0.7% H2O2              
----------------------------------------------------------------------------------------------------------------
1 The deadline for the next RATA is the end of the second (if semiannual) or fourth (if annual) successive QA   
  operating quarter following the quarter in which the CEMS was last tested. Exclude calendar quarters in which 
  the unit operates for < 168 hours (or, for common stacks and bypass stacks, exclude quarters in which gases   
  discharge through the stack for < 168 hours) in determining the RATA deadline. For SO2 monitors, QA operating 
  quarters in which only fuel with a total sulfur content no greater than the total sulfur content of natural   
  gas (i.e.,  0.05 percent sulfur by weight) is combusted may also be excluded. However, the         
  exclusion of calendar quarters is limited as follows: the deadline for the next RATA shall be no more than 8  
  calendar quarters after the quarter in which a RATA was last performed.                                       
2 The difference between monitor and reference method mean values applies to moisture monitors, CO2, and O2     
  monitors, low emitters, or low flow, only.                                                                    

    62. Section 2 of appendix C to part 75 is amended by revising 
sections 2.1 and 2.2.1 and by revising Table C-1 to read as follows:

Appendix C to Part 75--Missing Data Estimation Procedures

* * * * *

2. Load-Based Procedure for Missing Flow Rate and NOX 
Emission Rate Data

2.1  Applicability

    This procedure is applicable for data from all affected units 
for use in accordance with the provisions of this part to provide 
substitute data for volumetric flow rate (scfh) and NOX 
emission rate (in lb/mmBtu).
    2.2  * * *
    2.2.1  For a single unit, establish 10 operating load ranges 
defined in terms of percent of the maximum hourly average gross load 
of the unit, in gross megawatts (MWge), as shown in Table C-1. (Do 
not use integrated hourly gross load in MW-hr.) For units sharing a 
common stack monitored with a single flow monitor, the load ranges 
for flow (but not for NOX) may be broken down into 20 
operating load ranges in increments of 5.0 percent of the combined 
maximum hourly average gross load of all units utilizing the common 
stack. If this option is selected, the twentieth (uppermost) 
operating load range shall include all values greater than 95.0 
percent of the maximum hourly average gross load. For a cogenerating 
unit or other unit at which some portion of the heat input is not 
used to produce electricity or for a unit for which hourly average 
gross load in MWge is not recorded separately, use the hourly gross 
steam load of the unit, in pounds of steam per hour at the measured 
temperature ( deg.F) and pressure (psia) instead of MWge. Indicate a 
change in the number of load ranges or the units of loads to be used 
in the precertification section of the monitoring plan.

     Table C-1.--Definition of Operating Load Ranges for Load-Based     
                      Substitution Data Procedures                      
------------------------------------------------------------------------
            Operating load range                  Hourly gross load*    
------------------------------------------------------------------------
 1.........................................  0-10                       
 2.........................................  >10-20                     
 3.........................................  >20-30                     
 4.........................................  >30-40                     
 5.........................................  >40-50                     
 6.........................................  >50-60                     
 7.........................................  >60-70                     
 8.........................................  >70-80                     
 9.........................................  >80-90                     
10.........................................  >90                        
------------------------------------------------------------------------
*Percent of maximum hourly gross load or maximum hourly gross steam load
  (percent).                                                            

* * * * *
    63. Section 1 of appendix D to part 75 is amended by revising 
section 1.1 to read as follows:

Appendix D to Part 75--Optional SO2 Emissions Data 
Protocol for Gas-Fired and Oil-Fired Units

1. Applicability

    1.1  This protocol may be used in lieu of continuous 
SO2 pollutant concentration and flow monitors for the 
purpose of determining hourly SO2 emissions and heat 
input from:

[[Page 28175]]

(1) gas-fired units, as defined in Sec. 72.2 of this chapter; or (2) 
oil-fired units, as defined in Sec. 72.2 of this chapter. This 
optional SO2 emissions data protocol contains procedures 
for conducting oil sampling and analysis in section 2.2 of this 
appendix; the procedures for oil sampling may be used for any gas-
fired unit or oil-fired unit. In addition, this optional 
SO2 emissions data protocol contains three procedures for 
determining SO2 emissions due to the combustion of 
gaseous fuels having a total sulfur content no greater than 20 
grains per 100 standard cubic foot.
* * * * *
    64. Section 2 of appendix D to part 75 is amended by:
    a. Revising section 2.1 Flowmeter Measurements;
    b. Revising sections 2.2, 2.2.1, 2.2.3, 2.2.4, 2.2.6, and 2.2.8; 
and removing and reserving section 2.2.2;
    c. Revising sections 2.3, 2.3.1, 2.3.1.3, 2.3.2; redesignating 
section 2.3.1.4 as 2.3.1.4.1 and revising it; and adding sections 
2.3.1.4.1, 2.3.1.4.2, 2.3.1.4.3, and 2.3.3; and
    d. Revising section 2.4.1; removing section 2.4.2; redesignating 
sections 2.4.3, 2.4.3.1, 2.4.3.2, and 2.4.3.3 as 2.4.2, 2.4.2.1, 
2.4.2.2, and 2.4.2.3, respectively; revising newly designated sections 
2.4.2, 2.4.2.1, and 2.4.2.3; and redesignating section 2.4.4 as 2.4.3.

2. Procedure

2.1  Flowmeter Measurements

    For each hour when the unit is combusting fuel, measure and 
record the flow rate of fuel combusted by the unit, except as 
provided for gas in section 2.1.4.1 of this appendix. Measure the 
flow rate of fuel with an in-line fuel flowmeter, and automatically 
record the data with a data acquisition and handling system, except 
as provided in section 2.1.4 of this appendix.
    2.1.1  Measure the flow rate of each fuel entering and being 
combusted by the unit. If a portion of the flow greater than 5.0 
percent of the annual average flow rate from the main pipe is 
diverted from the unit without being burned and that diversion 
occurs downstream of the fuel flowmeter, an additional in-line fuel 
flowmeter is required to account for the unburned fuel. In this 
case, record the flow rate of each fuel combusted by the unit as the 
difference between the flow measured in the pipe leading to the unit 
and the flow in the pipe diverting fuel away from the unit. The 
hourly average proportion of flow rate from the pipe diverting fuel 
away from the unit to total fuel usage by the unit may be determined 
by using fuel usage data from fuel flowmeters in a previous year or 
by using a method approved by the Administrator under the provisions 
of Sec. 75.66(i).
    2.1.2  Install and use fuel flowmeters meeting the requirements 
of this appendix in a pipe going to each unit, or install and use a 
fuel flowmeter in a common pipe header (i.e., a pipe carrying fuel 
for multiple units). However, the use of a fuel flowmeter in a 
common pipe header and the provisions of sections 2.1.2.1 and 
2.1.2.2 of this appendix are not applicable to any unit that is 
using the provisions of subpart H of this part to monitor, record, 
and report NOX mass emissions under a state or federal 
NOX mass emission reduction program. For all other units, 
if the fuel flowmeter is installed in a common pipe header, do one 
of the following:
    2.1.2.1  Measure the fuel flow rate in the common pipe, and 
combine SO2 mass emissions for the affected units for 
recordkeeping and compliance purposes; or
    2.1.2.2  Provide information satisfactory to the Administrator 
on methods for apportioning SO2 mass emissions and heat 
input to each of the affected units demonstrating that the method 
ensures complete and accurate accounting of the actual emissions 
from each of the affected units included in the apportionment and 
all emissions regulated under this part. The information shall be 
provided to the Administrator through a petition submitted by the 
designated representative under Sec. 75.66. Satisfactory information 
includes apportionment, using fuel flow measurements, the ratio of 
hourly integrated gross load (in MWe-hr) in each unit to the total 
load for all units receiving fuel from the common pipe header, or 
the ratio of hourly steam flow (in 1000 lb) at each unit to the 
total steam flow for all units receiving fuel from the common pipe 
header, and documentation that shows the provisions of sections 
2.1.5 and 2.1.6 of this appendix have been met for the fuel 
flowmeter used in the apportionment.
    2.1.3  For a gas-fired unit or an oil-fired unit that 
continuously or frequently combusts a supplemental fuel for flame 
stabilization or safety purposes, measure the flow rate of the 
supplemental fuel with a fuel flowmeter meeting the requirements of 
this appendix.
    2.1.4  Situations in Which Certified Flowmeter Is Not Required
    2.1.4.1  Start-up or Ignition Fuel
    For an oil-fired unit that uses gas solely for start-up or 
burner ignition or a gas-fired unit that uses oil solely for start-
up or burner ignition, a flowmeter for the start-up fuel is not 
required. Estimate the volume of oil combusted for each start-up or 
ignition either by using a fuel flowmeter or by using the dimensions 
of the storage container and measuring the depth of the fuel in the 
storage container before and after each start-up or ignition. A fuel 
flowmeter used solely for start-up or ignition fuel is not subject 
to the calibration requirements of sections 2.1.5 and 2.1.6 of this 
appendix. Gas combusted solely for start-up or burner ignition does 
not need to be measured separately.

2.1.4.2  Gas Flowmeter Used for Commercial Billing

    A gas flowmeter used for commercial billing of pipeline natural 
gas may be used to measure, record, and report hourly fuel flow 
rate. A gas flowmeter used for commercial billing of pipeline 
natural gas is not required to meet the certification requirements 
of section 2.1.5 of this appendix or the quality assurance 
requirements of section 2.1.6 of this appendix under the following 
circumstances: (1) the gas flowmeter is used for commercial billing 
under a contract, provided that the company providing the gas under 
the contract and each unit combusting the gas do not have any common 
owners and are not owned by subsidiaries or affiliates of the same 
company; (2) the designated representative reports hourly records of 
gas flow rate, heat input rate, and emissions due to combustion of 
pipeline natural gas; (3) the designated representative also reports 
hourly records of heat input rate for each unit, if the gas 
flowmeter is on a common pipe header, consistent with section 2.1.2 
of this appendix; (4) the designated representative reports hourly 
records directly from the gas flowmeter used for commercial billing 
if these records are the values used, without adjustment, for 
commercial billing, or reports hourly records using the missing data 
procedures of section 2.4 of this appendix if these records are not 
the values used, without adjustment, for commercial billing; and (5) 
the designated representative identifies the gas flowmeter in the 
unit's monitoring plan.
    2.1.5  For the purposes of initial certification, each fuel 
flowmeter used to meet the requirements of this protocol shall meet 
a flowmeter accuracy of  2.0 percent of the upper range 
value (i.e, maximum calibrated fuel flow rate) across the range of 
fuel flow rate to be measured at the unit. Flowmeter accuracy may be 
determined under section 2.1.5.1 of this appendix for initial 
certification either by design or by measurement under laboratory 
conditions by the manufacturer, by an independent laboratory, or by 
the owner or operator, or may be determined under section 2.1.5.2 of 
this appendix by measurement against a NIST traceable reference 
method.
    2.1.5.1  Use the procedures in the following standards to verify 
flowmeter accuracy or design, as appropriate to the type of 
flowmeter: ASME MFC-3M-1989 with September 1990 Errata 
(``Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and 
Venturi''); ASME MFC-4M-1986 (Reaffirmed 1990), ``Measurement of Gas 
Flow by Turbine Meters''; American Gas Association Report No. 3, 
``Orifice Metering of Natural Gas and Other Related Hydrocarbon 
Fluids Part 1: General Equations and Uncertainty Guidelines'' 
(October 1990 Edition), Part 2: ``Specification and Installation 
Requirements'' (February 1991 Edition), and Part 3: ``Natural Gas 
Applications'' (August 1992 edition) (excluding the modified flow-
calculation method in Part 3); Section 8, Calibration from American 
Gas Association Transmission Measurement Committee Report No. 7: 
Measurement of Gas by Turbine Meters (1985 Edition); ASME MFC-5M-
1985 (``Measurement of Liquid Flow in Closed Conduits Using Transit-
Time Ultrasonic Flowmeters''); ASME MFC-6M-1987 with June 1987 
Errata (``Measurement of Fluid Flow in Pipes Using Vortex Flow 
Meters''); ASME MFC-7M-1987 (Reaffirmed 1992), ``Measurement of Gas 
Flow by Means of Critical Flow Venturi Nozzles''; ISO 8316: 1987(E) 
``Measurement of Liquid Flow in Closed Conduits--Method by 
Collection of

[[Page 28176]]

the Liquid in a Volumetric Tank''; American Petroleum Institute 
(API) Section 2, ``Conventional Pipe Provers,'' from Chapter 4 of 
the Manual of Petroleum Measurement Standards, October 1988 
(Reaffirmed 1993); or MFC-9M-1988 with December 1989 Errata 
(``Measurement of Liquid Flow in Closed Conduits by Weighing 
Method'') for all other flowmeter types (incorporated by reference 
under Sec. 75.6). The Administrator may also approve other 
procedures that use equipment traceable to National Institute of 
Standards and Technology standards. Document such procedures, the 
equipment used, and the accuracy of the procedures in the monitoring 
plan for the unit, and submit a petition signed by the designated 
representative under Sec. 75.66(c). If the flowmeter accuracy 
exceeds 2.0 percent of the upper range value, the 
flowmeter does not qualify for use under this part.
    2.1.5.2  Alternatively, determine the flowmeter accuracy of a 
fuel flowmeter used for the purposes of this part by comparing it to 
the measured flow from a reference flowmeter which has been either 
designed according to the specifications of American Gas Association 
Report No. 3 or ASME MFC-3M-1989, as cited in section 2.1.5.1 of 
this appendix, or tested for accuracy during the previous 365 days, 
using a standard listed in section 2.1.5.1 of this appendix or other 
procedure approved by the Administrator under Sec. 75.66 (all 
standards incorporated by reference under Sec. 75.6). Any secondary 
elements, such as pressure and temperature transmitters, must be 
calibrated immediately prior to the comparison. Perform the 
comparison over a period of no more than seven consecutive unit 
operating days. Compare the average of three fuel flow rate readings 
over 20 minutes or longer for each meter at each of three different 
flow rate levels. The three flow rate levels shall correspond to: 
(1) normal full unit operating load, (2) normal minimum unit 
operating load, and (3) a load point approximately equally spaced 
between the full and minimum unit operating loads. Calculate the 
flowmeter accuracy at each of the three flow levels using the 
following equation:
[GRAPHIC] [TIFF OMITTED] TP21MY98.012

(Eq. D-1)

Where:

ACC = Flowmeter accuracy as a percentage of the upper range value, 
including all error from all parts of both flowmeters.
R = Average of the three flow measurements of the reference 
flowmeter.
A = Average of the three measurements of the flowmeter being tested.
URV = Upper range value of fuel flowmeter being tested (i.e. maximum 
measurable flow).

    Notwithstanding the requirement for calibration of the reference 
flowmeter within 365 days prior to an accuracy test, when an in-
place reference meter or prover is used, the reference meter 
calibration requirement may be waived if, during the previous in-
place accuracy test with that reference meter, the reference 
flowmeter and the flowmeter being tested agreed to within 
 1.0 percent of each other at all levels tested. This 
exception to calibration and flowmeter accuracy testing requirements 
for the reference flowmeter shall apply for periods of no longer 
than five consecutive years (i.e., 20 consecutive calendar 
quarters).
    2.1.5.3  If the flowmeter accuracy exceeds the specification in 
section 2.1.5 of this appendix, the flowmeter does not qualify for 
use for this appendix. Either recalibrate the flowmeter until the 
flowmeter accuracy is within the performance specification, or 
replace the flowmeter with another one that is demonstrated to meet 
the performance specification. Substitute for fuel flow rate using 
the missing data procedures in section 2.4.2 of this appendix until 
quality assured fuel flow data become available.
    2.1.5.4  For purposes of initial certification, when a flowmeter 
is tested against a reference fuel flow rate (i.e., fuel flow rate 
from another fuel flowmeter under section 2.1.5.2 of this appendix 
or flow rate from a procedure according to a standard incorporated 
by reference under section 2.1.5.1 of this appendix), report the 
results of flowmeter accuracy tests using Table D-1 below.

                                 Table D-1.--Table of Flowmeter Accuracy Results                                
----------------------------------------------------------------------------------------------------------------
                                                                                                       Percent  
                                                                Time of     Candidate    Reference     accuracy 
 Measurement level  (percent of URV)          Run  No.        run  (HHMM)   flowmeter       flow     (percent of
                                                                             reading      reading        URV)   
----------------------------------------------------------------------------------------------------------------
                      Test number:__Test completion date \1\:__Test completion time \1\: __                     
                                                                                                                
             Reinstallation date \2\ (for testing under 2.1.5.1 only):__ Reinstallation time \2\:__             
                                                                                                                
                                 Unit or pipe ID:      Component/System ID :                                    
                                                                                                                
                              Flowmeter serial number:      Upper range value:                                  
                                                                                                                
                          Units of measure for flowmeter and reference flow readings:                           
----------------------------------------------------------------------------------------------------------------
Low (Minimum) level..................  1                                                                        
__ percent \3\ of URV................  2                                                                        
                                       3                                                                        
                                       Average                                                                  
Mid-level............................  1                                                                        
__ percent \3\ of URV................  2                                                                        
                                       3                                                                        
                                       Average                                                                  
High (Maximum) level.................  1                                                                        
__ percent \3\ of URV................  2                                                                        
                                       3                                                                        
                                       Average                                                                  
----------------------------------------------------------------------------------------------------------------
\1\ Report the date, hour, and minute that all test runs were completed.                                        
\2\ For laboratory tests not performed inline, report the date, hour, and minute that the fuel flowmeter was    
  reinstalled following the test.                                                                               
\3\ It is required to test at least at three different levels, from minimum to maximum.                         

2.1.6  Quality Assurance

    Test the accuracy of each fuel flowmeter prior to use under this 
part and at least once every four fuel flowmeter QA operating 
quarters thereafter. A ``fuel flowmeter QA operating quarter'' is a 
unit operating quarter in which the unit combusts the fuel measured 
by the fuel flowmeter for more than 168 hours. Notwithstanding these 
requirements, no more than 20 successive calendar quarters shall 
elapse after the quarter in which a fuel flowmeter was last tested 
for accuracy without a subsequent flowmeter accuracy test having 
been conducted. Test the flowmeter accuracy more frequently if 
required by manufacturer specifications.
    Except for orifice-, nozzle-, and venturi-type flowmeters, 
perform the required flowmeter accuracy testing using the procedures 
in either section 2.1.5.1 or section 2.1.5.2 of this appendix. Each 
fuel flowmeter

[[Page 28177]]

must meet the accuracy specification in section 2.1.5 of this 
appendix.
    For orifice-, nozzle-, and venturi-type flowmeters (that are 
designed according to the specifications of American Gas Association 
Report No. 3 or ASME MFC-3M-1989, as cited in section 2.1.5.1 of 
this appendix (both standards incorporated by reference under 
Sec. 75.6) or that have satisfied the initial certification test 
requirement by meeting an accuracy of 2.0 percent of the upper range 
value or less by comparison with another fuel flowmeter, following 
the procedures of section 2.1.5.2 of this appendix), perform a 
transmitter accuracy test once every four flowmeter QA operating 
quarters and a primary element visual inspection once every 12 
calendar quarters, according to the procedures in sections 2.1.6.1 
through 2.1.6.6 of this appendix for periodic quality assurance.
    Notwithstanding the requirements of this section, if the 
procedures of section 2.1.7 of this appendix are performed during 
each fuel flowmeter QA operating quarter, subsequent to a required 
flowmeter accuracy test or transmitter accuracy test and primary 
element inspection, where applicable, those procedures may be used 
to meet the requirement for periodic quality assurance testing for a 
period of up to 20 calendar quarters from the previous accuracy test 
or transmitter accuracy test and primary element inspection, where 
applicable.

2.1.6.1  Transmitter or Transducer Accuracy Test for Orifice-, Nozzle-, 
and Venturi-Type Flowmeters

    Calibrate the differential pressure transmitter or transducer, 
static pressure transmitter or transducer, and temperature 
transmitter or transducer, as applicable, using equipment that has a 
current certificate of traceability to NIST standards. Check the 
calibration of each transmitter or transducer by comparing its 
readings to that of the NIST traceable equipment at least once at 
each of the following levels: the zero-level and at least two other 
levels across the range of readings on the transmitter or transducer 
corresponding to normal unit operation. Determine either the 
accuracy of each individual transmitter or transducer of the 
orifice-, nozzle-, or venturi-type flowmeter according to section 
2.1.6.2 of this appendix, or determine the accuracy of the entire 
orifice-, nozzle-, or venturi-type flowmeter according to section 
2.1.6.3 of this appendix.

2.1.6.2  Transmitter or Transducer Accuracy Calculation

    Calculate the flowmeter accuracy at each level across the range 
of readings on the transmitter or transducer corresponding to normal 
unit operation by using the following equation:
[GRAPHIC] [TIFF OMITTED] TP21MY98.013

(Eq. D-1a)

Where:

ACC=Accuracy of the transmitter or transducer as a percentage of 
full-scale.
R=Reading of the NIST-traceable reference value (in milliamperes, 
inches of water, psi, or degrees).
T=Reading of the transmitter or transducer being tested (in 
milliamperes, inches of water, psi, or degrees, consistent with the 
units of measure of the NIST-traceable reference value).
FS = Full-scale range of the transmitter or transducer being tested.

2.1.6.3  Total Flowmeter Accuracy Calculation

    Use the transmitter or transducer accuracy calculated from 
Equation D-1a to determine if each individual transmitter or 
transducer meets an accuracy of  1.0 percent of its 
full-scale range at each level. If one or more of the transmitters 
or transducers does not meet this accuracy at each level, then 
either: (1) follow the data validation procedures in section 2.1.6.5 
of this appendix, or (2) determine the total flowmeter accuracy at 
each level, i.e. error in the volumetric flow rate, including all 
transmitters or transducers and the primary element, using the 
following equation:
[GRAPHIC] [TIFF OMITTED] TP21MY98.014

(Eq. D-1b)

Where:

dqv/qv=Error in the volumetric flow rate due 
to transmitter drift at a given level.
K=Original error resulting from installation of orifice (including 
all other variables). For an orifice-, nozzle-, or venturi-type 
flowmeter that was originally installed to the specifications of AGA 
Report No. 3 or ASME MFC-3M, as cited in section 2.1.5.1 of this 
appendix, an assumed value of 1.0 percent of the upper range value 
may be used for ``K'' if original error data or dimensional 
information from installation of the meter or other information on 
total installation error are not available.
dPf=Average difference between static pressure 
transmitter reading(s) and reference static pressure reading(s) at a 
given level.
Pf=Average reference static pressure reading at a given 
level.
dP=Average difference between differential pressure 
transmitter reading(s) and reference differential pressure 
reading(s) at a given level.
P = Average reference differential pressure reading at a 
given level.
dTf=Average difference between temperature transmitter 
reading(s) and reference temperature reading(s) at a given level.
Tf=Average reference temperature reading at a given 
level.

    Note: For gases, overall flow rate is directly related to 
pressure and is inversely related to temperature. Therefore, when 
performing this test on a gas fuel flowmeter, it is recommended that 
readings be entered into the equation at the following levels:

  Table D-2--Recommended Levels for Using Transmitter Test Results to Calculate Overall Gas Flowmeter Accuracy  
----------------------------------------------------------------------------------------------------------------
                                       Level of static pressure    Level of differential    Level of temperature
   Level of total flow calculation              reading              pressure reading             reading       
----------------------------------------------------------------------------------------------------------------
Low..................................  Low.....................  Low.....................  High.                
Mid..................................  Mid.....................  Mid.....................  Mid.                 
High.................................  High....................  High....................  Low.                 
----------------------------------------------------------------------------------------------------------------

    If the overall flowmeter accuracy at each flow rate level is 
less than or equal to  2.0 percent of the upper range 
value of the fuel flowmeter, then the fuel flow rate data remain 
valid, and the data invalidation procedures of section 2.1.6.5 of 
this appendix are not required. If the overall flowmeter accuracy at 
any flow rate level is greater than  2.0 percent of the 
upper range value of the

[[Page 28178]]

fuel flowmeter, then data from the fuel flowmeter are considered 
invalid, beginning with the date and hour of a failed accuracy test 
and continuing until the date and hour of a successful accuracy test 
for all transmitters or transducers; during the period when data 
from the fuel flowmeter are considered invalid, provide data from 
another fuel flowmeter that meets the requirements of Sec. 75.20(d) 
and section 2.1.5 of this appendix, or substitute for fuel flow rate 
using the missing data procedures in section 2.4.2 of this appendix.

2.1.6.4  Recordkeeping and Reporting of Transmitter or Transducer 
Accuracy Results

    Record the accuracy of the orifice, nozzle, or venturi meter or 
its individual transmitters or transducers and keep this information 
in a file at the site or other location suitable for inspection. 
When testing individual orifice, nozzle, or venturi meter 
transmitters or transducers for accuracy, include the information 
displayed in Table D-3 below. At a minimum, record results for each 
transmitter or transducer at the zero-level and at least two other 
levels across the range of the transmitter or transducer readings 
that correspond to normal unit operation.

                                        Table D-3.--Table of Flowmeter Transmitter or Transducer Accuracy Results                                       
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                             Expected                                   
                                                          Run number (if                   Transmitter/    transmitter/       Actual          Percent   
       Measurement level  (percent of full-scale)         multiple runs)     Run time       Transducer      transducer     transmitter/      accuracy   
                                                                 2            (HHMM)        input (pre-       output        transducer      (percent of 
                                                                                           calibration)     (reference)      output 3       full-scale) 
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                              Test number: __ Test completion date: __ Unit or pipe ID: __                                              
                                                                                                                                                        
                                                  Flowmeter serial number:    Component/System ID:                                                      
                                                                                                                                                        
                                                         Full-scale value:    Units of measure 3:                                                       
                                                                                                                                                        
                           Transducer/Transmitter Type (check one): __ Differential Pressure __ Static Pressure __ Temperature                          
--------------------------------------------------------------------------------------------------------------------------------------------------------
Low (Minimum) level.....................................                                                                                                
__ percent1 of full-scale...............................                                                                                                
Mid-level...............................................                                                                                                
__ percent1 of full-scale...............................                                                                                                
(If tested at more than 3 levels).......................                                                                                                
2nd Mid-level...........................................                                                                                                
__ percent1 of full-scale...............................                                                                                                
(If tested at more than 3 levels).......................                                                                                                
High (Maximum) level....................................                                                                                                
__ percent1 of full-scale...............................                                                                                                
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ At a minimum, it is required to test at zero-level and at least two other levels across the range of the transmitter or transducer readings         
  corresponding to normal unit operation.                                                                                                               
\2\ It is required to test at least once at each level.                                                                                                 
\3\ Use the same units of measure for all readings (e.g., use degrees ( deg.), inches of water (in H2O), pounds per square inch (psi), or milliamperes  
  (ma) for both transmitter or transducer readings and reference readings).                                                                             

    In addition, when testing the whole orifice, nozzle, or venturi 
meter for accuracy, record the information displayed in Table D-1 
above. At a minimum, record the overall flowmeter accuracy results 
for the entire fuel flowmeter at the zero-level and at least two 
other levels across the range of normal unit operation.
    Report the final result of the accuracy test (pass or fail) for 
the combination of all transmitters or transducers of the orifice, 
nozzle or venturi meter in the emissions report of the quarter in 
which the accuracy is determined, using the electronic format 
specified by the Administrator under Sec. 75.64.

2.1.6.5  Failure of Transducer or Transmitter

    Except as provided in section 2.1.6.3 of this appendix, if the 
accuracy during a calibration or test of an individual transmitter 
or transducer is greater than 1.0 percent of the full-
scale range for that transmitter or transducer at any level or if 
the individual transmitter or transducer fails to operate properly, 
recalibrate the transmitter or transducer or replace the transmitter 
or transducer with another one until the transmitter or transducer 
accuracy is less than or equal to 1.0 percent of the 
full-scale range for that transmitter or transducer, consistent with 
sections 2.1.6.1 and 2.1.6.2 of this appendix. Data from the fuel 
flowmeter are considered invalid, beginning with the date and hour 
of a failed accuracy test (or a failure to operate properly) for any 
transmitter or transducer and continuing until the date and hour of 
an accuracy test for all transmitters or transducers in which all 
transmitters or transducers meet an accuracy of 1.0 
percent of the full-scale range for that transducer or transmitter. 
During this period, provide data from another fuel flowmeter that 
meets the requirements of Sec. 75.20(d) and section 2.1.5 of this 
appendix, or substitute for fuel flow rate using the missing data 
procedures in section 2.4.2 of this appendix. Record and report test 
data and results, consistent with section 2.1.6.4 of this appendix 
and Sec. 75.56 or Sec. 75.59, as applicable.

2.1.6.6  Primary Element Inspection

    Conduct a visual inspection of the orifice, nozzle, or venturi 
at least once every twelve calendar quarters. Notwithstanding this 
requirement, the procedures of section 2.1.7 of this appendix may be 
used to reduce the inspection frequency of the orifice, nozzle, or 
venturi to at least once every twenty calendar quarters. The 
inspection may be performed using a boroscope. If the visual 
inspection indicates that the orifice, nozzle, or venturi has become 
damaged or corroded, then: (1) replace the primary element with 
another primary element meeting the requirements of American Gas 
Association Report No. 3 or ASME MFC-3M-1989, as cited in section 
2.1.5.1 of this appendix (both standards incorporated by reference 
under Sec. 75.6); (2) replace the primary element with another 
primary element, and demonstrate that the overall flowmeter accuracy 
meets the accuracy specification in section 2.1.5 of this appendix 
under the procedures of section 2.1.5.2 of this appendix; or (3) 
restore the damaged or corroded primary element to ``as new'' 
condition; determine the overall accuracy of the flowmeter, using 
either the specifications of American Gas Association Report No. 3 
or ASME MFC-3M-1989, as cited in section 2.1.5.1 of this appendix 
(both standards incorporated by reference under Sec. 75.6); and 
retest the transmitters or transducers prior to providing quality 
assured data from the flowmeter. If the primary element size is 
changed, calibrate the transmitter or transducers consistent with 
the new primary element size. Data from the fuel flowmeter are 
considered invalid, beginning with the date and hour of a failed 
visual inspection and continuing until the date and hour when: (1) 
the damaged or corroded primary element is replaced with another 
primary element meeting the requirements of American Gas Association 
Report No. 3 or ASME MFC-3M-1989, as cited in section 2.1.5.1 of 
this appendix (both standards incorporated by reference under 
Sec. 75.6); (2) the damaged or corroded primary element is replaced, 
and the overall accuracy of the flowmeter is demonstrated to meet 
the accuracy specification in section 2.1.5 of this

[[Page 28179]]

appendix under the procedures of section 2.1.5.2 of this appendix; 
or (3) the restored primary element is installed to meet the 
requirements of American Gas Association Report No. 3 or ASME MFC-
3M-1989, as cited in section 2.1.5.1 of this appendix (both 
standards incorporated by reference under Sec. 75.6) and its 
transmitters or transducers are retested to meet the accuracy 
specification in section 2.1.6.4 of this appendix. During this 
period, provide data from another fuel flowmeter that meets the 
requirements of Sec. 75.20(d) and section 2.1.5 of this appendix, or 
substitute for fuel flow rate using the missing data procedures in 
section 2.4.2 of this appendix.

2.1.7  Fuel Flow-to-Load Quality Assurance Testing for Certified Fuel 
Flowmeters

    The procedures of this section may be used as an optional 
supplement to the quality assurance procedures in section 2.1.5.1, 
2.1.5.2, 2.1.6.1, or 2.1.6.6 of this appendix when conducting 
periodic quality assurance testing of a certified fuel flowmeter. 
Note, however, that these procedures may not be used unless the 168 
hour baseline data requirement of 2.1.7.2 has been met. If, 
following a flowmeter accuracy test or flowmeter transmitter test 
and primary element inspection, where applicable, the procedures of 
this section are performed during each subsequent flowmeter QA 
operating quarter, as defined in section 2.1.6 of this appendix 
(excluding the quarter(s) in which the baseline data are collected), 
then these procedures may be used to meet the requirement for 
periodic quality assurance for a period of up to 20 calendar 
quarters from the previous periodic quality assurance procedure(s) 
performed according to sections 2.1.5.1, 2.1.5.2, or 2.1.6.1 through 
2.1.6.6 of this appendix. The procedures of this section are not 
required for any quarter in which a flowmeter accuracy test or a 
transmitter accuracy test and a primary element inspection, where 
applicable, are conducted. Notwithstanding the requirements of 
Sec. 75.54(a) or Sec. 75.57(a), as applicable, when using the 
procedures of this section, keep records of the test data and 
results from the previous flowmeter accuracy test under section 
2.1.5.1 or 2.1.5.2 of this appendix, records of the test data and 
results from the previous transmitter or transducer accuracy test 
under section 2.1.6.1 of this appendix for orifice-, nozzle-, and 
venturi-type fuel flowmeters, and records of the previous visual 
inspection of the primary element required under section 2.1.6.6 of 
this appendix for orifice-, nozzle-, and venturi-type fuel 
flowmeters until the next flowmeter accuracy test, transmitter 
accuracy test, or visual inspection is performed, even if the 
previous flowmeter accuracy test, transmitter accuracy test, or 
visual inspection was performed more than three years previously.

2.1.7.1  Baseline Flow Rate-to-Load Ratio or Heat Input-to-Load Ratio

    Determine Rbase, the baseline value of the ratio of 
fuel flow rate to unit load, following each successful periodic 
quality assurance procedure performed according to section 2.1.5.1, 
2.1.5.2, or 2.1.6.1 and 2.1.6.6 of this appendix. Establish a 
baseline period of data consisting, at a minimum, of 168 hours of 
quality assured fuel flowmeter data taken immediately after the most 
recent quality assurance procedure(s), during which only the fuel 
measured by the fuel flowmeter is combusted (i.e. only gas, only 
residual oil, or only diesel fuel is combusted by the unit). During 
the baseline data collection period, the owner or operator may 
exclude the following data as non-representative: (1) any hour in 
which the unit is ``ramping'' up or down, i.e., the load during the 
hour differs by more than 15.0 percent from the load in the previous 
or subsequent hour; and (2) any hour in which the unit load is in 
the lower 10.0 percent of the range of operation, as defined in 
section 6.5.2.1 of appendix A to this part, unless operation in this 
lower portion of the range is considered normal for the unit. The 
baseline data must be obtained no later than the end of the second 
calendar quarter following the calendar quarter of the most recent 
quality assurance procedure for that fuel flowmeter. For orifice-, 
nozzle-, and venturi-type fuel flowmeters, if the fuel flow-to-load 
ratio is to be used as a supplement both to the transmitter accuracy 
test under section 2.1.6.1 of this appendix and to primary element 
inspections under section 2.1.6.6 of this appendix, then the 
baseline data must be obtained after both procedures are completed 
and no later than the end of the second calendar quarter following 
the calendar quarter of both the most recent transmitter or 
transducer test and the most recent primary element inspection for 
that fuel flowmeter. From these 168 (or more) hours of baseline 
data, calculate the baseline fuel flow rate-to-load ratio as 
follows:
[GRAPHIC] [TIFF OMITTED] TP21MY98.015

(Eq. D-1c)

Where:

Rbase=Value of the fuel flow rate-to-load ratio during 
the baseline period; 100 scfh/MWe or 100 scfh/klb per hour steam 
load for gas-firing; (lb/hr)/MWe or (lb/hr)/klb per hour steam load 
for oil-firing.
Qbase=Average fuel flow rate measured by the fuel 
flowmeter during the baseline period, 100 scfh for gas-firing and 
lb/hr for oil-firing.
Lavg=Average unit load during the baseline period, 
megawatts or 1000 lb/hr of steam.

    In Equation D-1c, for a common pipe header, Lavg is 
the sum of the operating loads of all units that receive fuel 
through the common pipe header. For a unit that receives its fuel 
through multiple pipes, Qbase is the sum of the fuel flow 
rates for a particular fuel (i.e., gas, diesel fuel, or residual 
oil) from each of the pipes. Round off the value of Rbase 
to the nearest tenth.
    Alternatively, a baseline value of the gross heat rate (GHR) may 
be determined in lieu of Rbase. The baseline value of the 
GHR, GHRbase, shall be determined as follows:
[GRAPHIC] [TIFF OMITTED] TP21MY98.016

(Eq. D-1d)

Where:

(GHR)base=Baseline value of the gross heat rate during 
the baseline period, Btu/kwh or Btu/lb steam load.
(Heat Input)avg=Average (mean) hourly heat input rate 
recorded by the fuel flowmeter during the baseline period, as 
determined using the applicable equation in appendix F to this part, 
mmBtu/hr.
Lavg=Average (mean) unit load during the baseline period, 
megawatts or 1000 lb/hr of steam.

    Report the current value of Rbase (or 
GHRbase) and the completion date of the associated 
quality assurance procedure in each electronic quarterly report 
required under Sec. 75.64.

2.1.7.2  Data Preparation and Analysis

    Evaluate the fuel flow rate-to-load ratio (or GHR) for each 
flowmeter QA operating quarter, as defined in section 2.1.6 of this 
appendix. At the end of each flowmeter QA operating quarter, use 
Equation D-1e in this appendix to calculate Rh, the 
hourly fuel flow-to-load ratio, for every quality assured hourly 
average fuel flow rate obtained with a certified fuel flowmeter.
[GRAPHIC] [TIFF OMITTED] TP21MY98.017

(Eq. D-1e)

Where:

Rh=Hourly value of the fuel flow rate-to-load ratio; 100 
scfh/MWe, (lb/hr)/MWe, 100 scfh/1000 lb/hr of steam load, or (lb/
hr)/1000 lb/hr of steam load.
Qh = Hourly fuel flow rate, as measured by the fuel 
flowmeter, 100 scfh for gas-firing or lb/hr for oil-firing.
Lh = Hourly unit load, megawatts or 1000 lb/hr of steam.

    For a common pipe header, Lh shall be the sum of the 
hourly operating loads of all units that receive fuel through the 
common pipe header. For a unit that receives its fuel through 
multiple pipes, Qh will be the sum of the fuel flow rates 
for a particular fuel (i.e., gas, diesel fuel, or residual oil) from 
each of the pipes. Round off each value of Rh to the 
nearest tenth.
    Alternatively, calculate the hourly gross heat rates (GHR) in 
lieu of the hourly flow-to-load ratios. If this option is selected, 
calculate each hourly GHR value as follows:
[GRAPHIC] [TIFF OMITTED] TP21MY98.018

(Eq. D-1f)

Where:

(GHR)h = Hourly value of the gross heat rate, Btu/kwh or 
Btu/lb steam load.
(Heat Input)h = Hourly heat input rate, as determined 
using the applicable equation in appendix F to this part, mmBtu/hr.
Lh = Hourly unit load, megawatts or 1000 lb/hr of steam.

    Evaluate the calculated flow rate-to-load ratios (or gross heat 
rates) as follows. Perform a separate data analysis for each fuel 
flowmeter following the procedures of this

[[Page 28180]]

section. Base each analysis on a minimum of 168 hours of data. If, 
for a particular fuel flowmeter, fewer than 168 hourly flow-to-load 
ratios (or GHR values) are available, a flow-to-load (or GHR) 
evaluation is not required for that flowmeter for that calendar 
quarter.
    For each hourly flow-to-load ratio or GHR value, calculate the 
percentage difference (percent Dh) from the baseline fuel 
flow-to-load ratio using Equation D-1g.
[GRAPHIC] [TIFF OMITTED] TP21MY98.019

(Eq. D-1g)

Where:

%Dh = Absolute value of the percentage difference between 
the hourly fuel flow rate-to-load ratio and the baseline value of 
the fuel flow rate-to-load ratio (or hourly and baseline GHR).
Rh = The hourly fuel flow rate-to-load ratio (or GHR).
Rbase = The value of the fuel flow rate-to-load ratio (or 
GHR) from the baseline period, determined in accordance with section 
2.1.7.1 of this appendix.

    Consistently use Rbase and Rh in Equation 
D-1g if the fuel flow-to-load ratio is being evaluated, and 
consistently use (GHR)base and (GHR)h in 
Equation D-1g if the gross heat rate is being evaluated.
    Next, determine the arithmetic average of all of the hourly 
percent difference (percent Dh) values using Equation D-
1h, as follows:
[GRAPHIC] [TIFF OMITTED] TP21MY98.024

(Eq. D-1h)

Where:

Ef = Quarterly average percentage difference between 
hourly flow rate-to-load ratios and the baseline value of the fuel 
flow rate-to-load ratio (or hourly and baseline GHR).
%Dh = Percentage difference between the hourly fuel flow 
rate-to-load ratio and the baseline value of the fuel flow rate-to-
load ratio (or hourly and baseline GHR).
q = Number of hours used in fuel flow-to-load (or GHR) evaluation.

    When the quarterly average load value used in the data analysis 
is greater than 50 MWe (or 500 klb steam per hour), the results of a 
quarterly fuel flow rate-to-load (or GHR) evaluation are acceptable 
and no further action is required, if the quarterly average 
percentage difference (Ef) is no greater than 10.0 
percent. When the arithmetic average of the hourly load values used 
in the data analysis is  50 MWe (or 500 klb steam per 
hour), the results of the analysis are acceptable if the value of 
Ef is no greater than 15.0 percent.

2.1.7.3  Optional Data Exclusions

    If Ef is outside the limits in section 2.1.7.2 of 
this appendix, the owner or operator may re-examine the hourly fuel 
flow rate-to-load ratios (or GHRs) that were used for the data 
analysis and identify and exclude fuel flow-to-load ratios or GHR 
values for any non-representative fuel flow-to-load ratios or GHR 
values. Specifically, the Rh or (GHR)h values 
for the following hours shall be considered non-representative: (1) 
any hour in which the unit combusted another fuel in addition to the 
fuel measured by the fuel flowmeter being tested; (2) any hour for 
which the load differed by more than  15.0 percent from 
the load during either the preceding hour or the subsequent hour; 
and (3) any hour for which the unit load was in the lower 10.0 
percent of the range of operation, as defined in section 6.5.2.1 of 
appendix A to this part, unless operation in this lower portion of 
the range is considered normal for the unit.
    After identifying and excluding all non-representative hourly 
fuel flow-to-load ratios or GHR values, analyze the quarterly fuel 
flow rate-to-load data a second time.

2.1.7.4  Consequences of Failed Fuel Flow-to-Ratio Test

    If Ef is outside the applicable limit in section 
2.1.7.2 of this appendix (after analysis using any optional data 
exclusions under section 2.1.7.3 of this appendix), perform 
transmitter accuracy tests according to section 2.1.6.1 of this 
appendix for
orifice-, nozzle-, and venturi-type flowmeters, or perform a fuel 
flowmeter accuracy test, in accordance with section 2.1.5.1 or 
2.1.5.2 of this appendix, for each fuel flowmeter for which 
Ef is outside of the applicable limit. In addition, for 
an orifice-, nozzle-, or venturi-type fuel flowmeter, repeat the 
fuel flow-to-load ratio comparison of section 2.1.7.2 of this 
appendix using six to twelve hours of data following a passed 
transmitter accuracy test in order to verify that no significant 
corrosion has affected the primary element. If, for the abbreviated 
6-to-12 hour test, the orifice-, nozzle-, or venturi-type fuel 
flowmeter is not able to meet the limit in section 2.1.7.2 of this 
appendix, then perform a visual inspection of the primary element 
according to section 2.1.6.6 of this appendix, and repair or replace 
the primary element, as necessary.
    Substitute for fuel flow rate, for any hour when that fuel is 
combusted, using the missing data procedures in section 2.4.2 of 
this appendix, beginning with the first hour of the calendar quarter 
following the quarter for which Ef was found to be 
outside the applicable limit and continuing until quality assured 
fuel flow data become available. Following a failed flow rate-to-
load or GHR evaluation, data from the flowmeter shall not be 
considered quality assured until the hour in which all required 
flowmeter accuracy tests, transmitter accuracy tests, visual 
inspections and diagnostic tests have been passed. Additionally, a 
new value of Rbase or (GHR)base shall be 
established no later than two flowmeter QA operating quarters after 
the quarter in which the required quality assurance tests are 
completed (for orifice-, nozzle-, or venturi-type fuel flowmeters, a 
new value of Rbase or (GHR)base shall only be 
established if both a transmitter accuracy test and a primary 
element inspection have been performed).

2.1.7.5  Test Results

    Report the results of each quarterly flow rate-to-load (or GHR) 
evaluation, as determined from Equation D-1h, in the electronic 
quarterly report required under Sec. 75.64. Table D-4 is provided as 
a reference on the type of information to be recorded under 
Sec. 75.59 and reported under Sec. 75.64.

 Table D-4.--Baseline Information and Test Results for Fuel Flow-to-Load
                                  Test                                  
------------------------------------------------------------------------
                               Time period                              
-------------------------------------------------------------------------
            Baseline period                          Quarter            
------------------------------------------------------------------------
       Plant name:______    State:________     ORIS code:________       
                                                                        
 Unit/pipe ID #:________ Fuel flowmeter component and system ID #s:____-
                                  ____                                  
                                                                        
         Calendar quarter (1st, 2nd, 3rd, 4th) and year:________        
                                                                        
  Range of operation:________ to________ MWe or klb steam/hr (indicate  
                                 units)                                 
------------------------------------------------------------------------
Completion date and time of most recent  Number of hours excluded from  
 primary element inspection (orifice-,    quarterly average due to co-  
 nozzle-, and venturi-type flowmeters     firing different              
 only).                                   fuels:________hrs.            
____/____/____  ____:____                                               
Completion date and time of most recent  Number of hours excluded from  
 flowmeter or transmitter accuracy test.  quarterly average due to      
                                          ramping load:________hrs.     
____/____/____  ____:____                                               
Beginning date and time of baseline      Number of hours in the lower   
 period.                                  10.0 percent of the range of  
                                          operation excluded from       
                                          quarterly average:________hrs.

[[Page 28181]]

                                                                        
____/____/____  ____:____                                               
End date and time of baseline period:    Number of hours included in    
                                          quarterly average:________hrs.
____/____/____  ____:____                                               
Average fuel flow rate:________          Quarterly percentage difference
(100 scfh for gas and lb/hr for oil)...   between hourly ratios and     
                                          baseline ratio:________       
                                          percent.                      
Average load:________                    Test result: pass, fail        
(MWe or 1000 lb steam/hr)..............                                 
------------------------------------------------------------------------


------------------------------------------------------------------------
                                                                        
------------------------------------------------------------------------
      Plant name:________    State:________     ORIS code:________      
                                                                        
  Unit/pipe ID#:________ Fuel flowmeter component and system ID #:____- 
                                  ____                                  
                                                                        
         Calendar quater (1st, 2nd, 3rd, 4th) and year:________         
                                                                        
    Range of operation:________ MWe or klb steam/hr (indicate units)    
------------------------------------------------------------------------
                               Time period                              
------------------------------------------------------------------------
Baseline fuel flow-to-load                                              
 ratio:________                                                         
Units of fuel flow-to-load:________                                     
Baseline GHR:________                                                   
Units of fuel flow-to-load:________                                     
Number of hours excluded from baseline                                  
 ratio or GHR due to ramping                                            
 load:________ hrs.                                                     
Number of hours in the lower 10.0                                       
 percent of the range of operation                                      
 excluded from baseline ratio or                                        
 GHR:________ hrs.                                                      
------------------------------------------------------------------------

2.2  Oil Sampling and Analysis

    Perform sampling and analysis of oil to determine the percentage 
of sulfur by weight in the oil combusted by the unit. Calculate 
SO2 mass emissions and heat input rate using the sulfur 
content, density, and gross calorific value (heat content), as 
described in the sections below and in Table D-5.

Table D-5.--Oil Sampling Methods and Sulfur, Density and Gross Calorific
                       Value Used in Calculations                       
------------------------------------------------------------------------
                               Sampling technique/      Value used in   
          Parameter                 frequency           calculations    
------------------------------------------------------------------------
Oil Sulfur Content..........  Daily manual          Highest sulfur      
                               sampling.             content from       
                                                     previous 30 daily  
                                                     samples.           
                              Flow proportional/    Actual measured     
                               weekly composite...   value.             
                              In storage tank       Actual measured     
                               (after addition of    value OR highest of
                               fuel to tank).        all sampled values 
                                                     in previous        
                                                     calendar year OR   
                                                     maximum value      
                                                     allowed by         
                                                     contract.\1\       
                              As delivered (in      Highest of all      
                               delivery truck or     sampled values in  
                               barge).\1\.           previous calendar  
                                                     year OR maximum    
                                                     value allowed by   
                                                     contract.\1\       
Oil Density.................  Daily manual          Actual measured     
                               sampling.             value.             
                              Flow proportional/    Actual measured     
                               weekly composite...   value.             
                              In storage tank       Actual measured     
                               (after addition of    value OR highest of
                               fuel to tank).        all sampled values 
                                                     in previous        
                                                     calendar year OR   
                                                     maximum value      
                                                     allowed by         
                                                     contract.\1\       
                              As delivered (in      Highest of all      
                               delivery truck or     sampled values in  
                               barge).\1\.           previous calendar  
                                                     year OR maximum    
                                                     value allowed by   
                                                     contract.\1\       
Oil GCV.....................  Daily manual          Actual measured     
                               sampling.             value.             
                              Flow proportional/    Actual measured     
                               weekly composite.     value.             
                              In storage tank       Actual measured     
                               (after addition of    value OR highest of
                               fuel to tank).        all sampled values 
                                                     in previous        
                                                     calendar year OR   
                                                     maximum value      
                                                     allowed by         
                                                     contract.\1\       
                              As delivered (in      Highest of all      
                               delivery truck or     sampled values in  
                               barge).\1\.           previous calendar  
                                                     year OR maximum    
                                                     value allowed by   
                                                     contract.\1\       
------------------------------------------------------------------------
\1\ Assumed values may only be used if sulfur content, gross calorific  
  value, or density of each sample is no greater than the assumed value 
  used to calculate emissions or heat input.                            

    2.2.1  When combusting oil, sample the oil: (1) from the storage 
tank for the unit after each addition of oil to the storage tank, in 
accordance with section 2.2.4.2 of this appendix; (2) from the fuel 
lot in the shipment tank or container upon receipt of each oil 
delivery or from the fuel lot in the oil supplier's storage 
container, in accordance with section 2.2.4.3 of this appendix; (3) 
following the flow proportional sampling methodology in section 
2.2.3 of this appendix; or (4) following the daily manual sampling 
methodology in section 2.2.4.1 of this appendix. For purposes of 
this appendix, a fuel lot of oil is the mass or volume of product 
oil from one source (supplier or pretreatment facility), intended as 
one shipment or delivery (ship load, barge load, group of trucks, 
discrete purchase of diesel fuel through pipeline, etc.), which 
meets the fuel purchase specifications for sulfur content and GCV. A 
storage tank is a container at a plant holding oil that is actually 
combusted by the unit, such that

[[Page 28182]]

blending of any other fuel with the fuel in the storage tank occurs 
from the time that the fuel lot is transferred to the storage tank 
to the time when the fuel is combusted in the unit.
    2.2.2  [Reserved]

2.2.3  Flow Proportional Sampling

    Conduct flow proportional oil sampling or continuous drip oil 
sampling in accordance with ASTM D4177-82 (Reapproved 1990), 
``Standard Practice for Automatic Sampling of Petroleum and 
Petroleum Products'' (incorporated by reference under Sec. 75.6), 
every day the unit is combusting oil. Extract oil at least once 
every hour and blend into a composite sample. The sample compositing 
period may not exceed 7 calendar days (168 hr). Use the actual 
sulfur content (and where density data are required, the actual 
density) from the composite sample to calculate the hourly 
SO2 mass emission rates for each operating day 
represented by the composite sample. Calculate the hourly heat input 
rates for each operating day represented by the composite sample, 
using the actual gross calorific value from the composite sample.

2.2.4  Manual Sampling

2.2.4.1  Daily Samples

    Representative oil samples may be taken from the storage tank or 
fuel flow line manually every day that the unit combusts oil 
according to ASTM D4057-88, ``Standard Practice for Manual Sampling 
of Petroleum and Petroleum Products'' (incorporated by reference 
under Sec. 75.6), provided that the highest fuel sulfur content 
recorded at that unit from the most recent 30 daily samples is used 
for the purpose of calculating SO2 emissions under 
section 3 of this appendix. Use the gross calorific value measured 
from that day's samples to calculate heat input. If oil supplies 
with different sulfur contents are combusted on the same day, sample 
the highest sulfur fuel combusted that day.

2.2.4.2  Sampling from a Unit's Storage Tank

    Take a manual sample after each addition of oil to the storage 
tank. No additional fuel shall be blended with the sampled fuel 
prior to combustion. Sample according to the single tank composite 
sampling procedure or all-levels sampling procedure in ASTM D4057-
88, ``Standard Practice for Manual Sampling of Petroleum and 
Petroleum Products'' (incorporated by reference under Sec. 75.6). 
Use the sulfur content (and where required, the density) of either 
the most recent sample or one of the conservative assumed values 
described in section 2.2.4.3 of this appendix, to calculate 
SO2 mass emission rate. Calculate heat input rate using 
the gross calorific value from either: (1) the most recent oil 
sample taken or (2) one of the conservative assumed values described 
in section 2.2.4.3 of this appendix.

2.2.4.3  Sampling from Each Delivery

    Alternatively, an oil sample may be taken from the shipment tank 
or container upon receipt of each lot of fuel oil or from the 
supplier's storage container which holds the lot of fuel oil. For 
the purpose of this section, a lot is defined as a shipment or 
delivery (e.g., ship load, barge load, group of trucks, discrete 
purchase of diesel fuel through a pipeline, etc.) which meets the 
fuel purchase specifications for sulfur content and GCV. Oil 
sampling may be performed either by the owner or operator of an 
affected unit, an outside laboratory, or a fuel supplier, provided 
that samples are representative and that sampling is performed 
according to either the single tank composite sampling procedure or 
the all-levels sampling procedure in ASTM D4057-88, ``Standard 
Practice for Manual Sampling of Petroleum and Petroleum Products'' 
(incorporated by reference under Sec. 75.6). Except as otherwise 
provided in this section 2.2.4.3, calculate SO2 mass 
emission rate using the sulfur content (and where required, the 
density) from one of the two values below, and calculate heat input 
using the gross calorific value from one of the two following 
values: (1) the highest value sampled during the previous calendar 
year or (2) the maximum value indicated in the contract with the 
fuel supplier unit. Continue to use this assumed value unless and 
until the actual sampled sulfur content, density, or gross calorific 
value of a delivery exceeds the assumed value.
    If the actual sampled sulfur content, gross calorific value, or 
density of an oil sample is greater than the assumed value for that 
parameter, then use the actual sampled value for sulfur content, 
gross calorific value, or density of fuel to calculate 
SO2 mass emission rate or heat input rate as the new 
assumed sulfur content, gross calorific value, or density. Continue 
to use this new assumed value to calculate SO2 mass 
emission rate or heat input rate unless and until: (1) it is 
superseded by a higher value from an oil sample; (2) a new contract 
with a higher maximum sulfur content, gross calorific value, or 
density is adopted, in which case the new contract value becomes the 
assumed value; or (3) both the calendar year in which the sampled 
value exceeded the assumed value and the subsequent calendar year 
have elapsed.
* * * * *
    2.2.6  Where the flowmeter records volumetric flow rate rather 
than mass flow rate, analyze oil samples to determine the density or 
specific gravity of the oil.
* * * * *
    2.2.8  Results from the oil sample analysis must be available no 
later than thirty calendar days after the sample is composited or 
taken. However, during an audit, the Administrator may require that 
the results of the analysis be available as soon as practicable, and 
no later than 5 business days after receipt of a request from the 
Administrator.

2.3  SO2 Emissions from Combustion of Gaseous Fuels

    Account for the hourly SO2 mass emissions due to 
combustion of gaseous fuels for each day when gaseous fuels are 
combusted by the unit using the procedures in either section 2.3.1 
or 2.3.2. The procedures in section 2.3.1 may be used for accounting 
for SO2 mass emissions from any gaseous fuel with a total 
sulfur content 20.0 gr/100 scf. The procedures in section 
2.3.2 may be used for pipeline natural gas or for any gaseous fuel 
for which the designated representative demonstrates to the 
satisfaction of the Administrator, in a petition to the 
Administrator under Sec. 75.66(i), that the fuel has an 
SO2 emission rate no greater than 0.0006 lb/mmBtu. Values 
used for calculations of SO2 mass emission rates are 
summarized in Table D-6, below.

   Table D-6.--Gas Sampling Methods and Sulfur and Heat Content (GCV)   
                       Values Used in Calculations                      
------------------------------------------------------------------------
                               Sampling technique/      Value used in   
          Parameter                 frequency           calculations    
------------------------------------------------------------------------
Gas Sulfur Content..........  Gaseous fuel in       Highest of all      
                               lots--as-delivered    sampled values in  
                               sampling 1.           previous calendar  
                                                     year OR maximum    
                                                     value allowed by   
                                                     contract 1         
                              Any gaseous fuel--    Highest sulfur in   
                               daily sampling 2.     previous 30 daily  
                                                     samples.           
                              Any gaseous fuel--    Actual measured     
                               continuous sampling   hourly average     
                               (at least hourly)     sulfur content.    
                               with a gas                               
                               chromatograph.                           
Gas GCV/heat content........  Gaseous fuel in       Highest of all      
                               lots--as-delivered    sampled values in  
                               sampling 1.           previous calendar  
                                                     year OR maximum    
                                                     value allowed by   
                                                     contract.1         
                              Gaseous fuels other   Highest GCV in      
                               than pipeline         previous 30 daily  
                               natural gas that      samples.           
                               are sampled for                          
                               sulfur content--                         
                               daily sampling.                          
                              Gaseous fuels other   Actual measured     
                               than pipeline         hourly average GCV 
                               natural gas that      or highest GCV in  
                               are sampled for       previous 30 unit   
                               sulfur content--      operating days.    
                               continuous sampling                      
                               (at least hourly).                       
                              Pipeline natural      Actual measured GCV 
                               gas--monthly          OR highest of all  
                               sampling for GCV      sampled values in  
                               only..                previous calendar  
                                                     year OR maximum    
                                                     value allowed by   
                                                     contract.3         
------------------------------------------------------------------------
\1\ Assumed sulfur and GCV values may only continue to be used if sulfur
  content and gross calorific value of each as-delivered sample is no   
  greater than the assumed value used to calculate emissions or heat    
  input.                                                                

[[Page 28183]]

                                                                        
\2\ Continuous sampling (at least hourly) may be required if the sulfur 
  content exhibits too much variability (see section 2.3.3.4, below).   
\3\ Assumed GCV values of the highest sampled value in the previous     
  calendar year or the maximum value allowed by contract may only       
  continue to be used if gross calorific value of each monthly sample is
  no greater than the assumed value used to calculate heat input.       

    2.3.1  For gaseous fuels received in shipments or lots, sample 
each shipment or lot of fuel. A fuel lot for gaseous fuel is the 
volume of product gas from one source (supplier or pretreatment 
facility), intended as one shipment or delivery, which meets the 
fuel purchase specifications for sulfur content and GCV. For gaseous 
fuels, other than pipeline natural gas, that are not delivered in 
discrete lots or shipments, sample the gaseous fuel at least daily. 
Continuous sampling (at least hourly) with a gas chromatograph may 
be required if the sulfur content exhibits too much variability (see 
section 2.3.3.4, below). For gaseous fuel meeting the definition of 
pipeline natural gas in Sec. 72.2 of this chapter, either use the 
procedures of section 2.3.2 of this appendix or sample the gaseous 
fuel at least daily. Sampling may be performed by either the owner 
or operator or by the fuel supplier.
* * * * *
    2.3.1.3  Determine the heat content or gross calorific value for 
a sample using the procedures of section 5.5 of appendix F to this 
part to determine the heat input rate for each hour the unit 
combusted gaseous fuel. Calculate heat input using the appropriate 
GCV from sections 2.3.1.4.1 through 2.3.1.4.3 of this appendix.
    2.3.1.4  Calculate the hourly SO2 mass emission rate, 
in lb/hr, using Equation D-4 of this appendix. Multiply the hourly 
metered volumetric flow rate of gas combusted (in 100 scfh) by the 
appropriate sulfur content from sections 2.3.1.4.1 through 2.3.1.4.2 
of this appendix.
    2.3.1.4.1  For gaseous fuels received in shipments or lots, use 
one of the following values: (1) the highest sulfur content and GCV 
from all shipments in the previous calendar year or (2) the maximum 
sulfur content and maximum GCV values established by agreement with 
the fuel supplier through a contract. Continue to use this assumed 
value until and unless the actual sampled sulfur content or gross 
calorific value of a delivery exceeds the previously reported 
assumed value.
    If the actual sampled sulfur content or gross calorific value of 
a gas sample is greater than the assumed value for that parameter, 
then use the actual sampled value for sulfur content or gross 
calorific value of gas to calculate SO2 mass emission 
rate or heat input rate as the new assumed sulfur content or gross 
calorific value. Continue to use this sampled value to calculate 
SO2 mass emission rate or heat input rate until: (1) it 
is superseded by a new, higher value from a gas sample; (2) a new 
contract with a higher maximum sulfur content or gross calorific 
value is adopted, in which case the new contract value becomes the 
new assumed value; or (3) both the calendar year in which the 
sampled value exceeded the assumed value and the subsequent calendar 
year have elapsed.
    2.3.1.4.2  For gaseous fuels other than pipeline natural gas 
that are not received in shipments or lots that are transmitted by 
pipeline and sampled daily, use the highest sulfur content and GCV 
from the previous 30 daily gas samples. When continuous gas sampling 
(at least hourly) is required, use the actual measured hourly 
average sulfur content for each hour that the gaseous fuel is 
combusted.
    2.3.1.4.3  For pipeline natural gas, use the highest sulfur 
content in the previous 30 daily gas samples, and the GCV from: (1) 
one or more samples taken during the most recent month when the unit 
burned gas for at least 48 hours; (2) the highest GCV from all 
samples in the previous calendar year; or (3) the maximum GCV values 
established by agreement with the fuel supplier through a contract. 
Continue to use this assumed value unless and until the actual 
sampled sulfur content or gross calorific value of a delivery 
exceeds the previously reported assumed value.
    If the actual sampled sulfur content or gross calorific value of 
a gas sample is greater than the assumed value for that parameter, 
use the actual sampled value for sulfur content or gross calorific 
value of gas to calculate SO2 mass emission rate or heat 
input rate as the new assumed sulfur content or gross calorific 
value. Continue to use this sampled value to calculate 
SO2 mass emission rate or heat input rate until: (1) it 
is superseded by a new, higher value from a gas sample; (2) a new 
contract with a higher maximum sulfur content or gross calorific 
value is adopted, in which case the new contract value becomes the 
new assumed value; or (3) both the calendar year in which the 
sampled value exceeded the assumed value and the subsequent calendar 
year have elapsed.
    2.3.2  If the fuel is pipeline natural gas, as defined in 
Sec. 72.2 of this chapter, calculate SO2 emissions under 
this section using a default SO2 emission rate of 0.0006 
lb/mmBtu.
    2.3.2.1  Use the default SO2 emission rate of 0.0006 
lb/mmBtu and the hourly heat input rate from pipeline natural gas in 
mmBtu/hr, as determined using the procedures in section 5.5 of 
appendix F to this part. Calculate SO2 mass emission rate 
using Equation D-5 of this appendix. Determine the heat content or 
gross calorific value for at least one sample each month that the 
gaseous fuel is combusted using the procedures in section 5.5 of 
appendix F to this part.
    2.3.2.2  The procedures in this section 2.3.2 may also be used 
for a gaseous fuel other than pipeline natural gas if the 
Administrator approves a petition under Sec. 75.66(i) in which the 
designated representative demonstrates that the gaseous fuel 
combusted at the unit has an SO2 emission rate no greater 
than 0.0006 lb/mmBtu. To demonstrate this, the petition shall 
include at least 720 hours of fuel sampling data, indicating the 
total sulfur content and GCV of the fuel for each hour. Each hourly 
value of the total sulfur content in the gas or blend (in gr/100 
scf) shall be converted to a ``fuel sulfur-to-heating value ratio,'' 
by dividing the total sulfur content by the gross calorific value of 
the fuel (in Btu/100 scf) and then multiplying by a conversion 
factor of 10\6\ Btu/mmBtu. The mean value of the fuel sulfur-to-
heating value ratios shall then be calculated. If the mean value of 
the ratios does not exceed 2.0 grains of sulfur per mmBtu, then the 
default SO2 emission rate of 0.0006 lb/mmBtu may be used 
to account for SO2 mass emissions under this part, 
whenever the gaseous fuel is combusted.
    2.3.3  For all types of gaseous fuels, the owner or operator 
shall provide, in the monitoring plan for the unit, historical fuel 
sampling information on the sulfur content of the gaseous fuel 
sufficient to demonstrate that use of this appendix is applicable 
because the gas has a total sulfur content of 20.0 grain/100 scf or 
less. Provide this information with the initial monitoring plan for 
the unit and following any significant changes in gas contract or 
source of supply. However, for units combusting pipeline natural gas 
that have gas flowmeters certified prior to the effective date of 
this rule, this information may be retained on site in a form 
suitable for inspection, rather than submitted as an update to the 
monitoring plan. In addition, provide the following specific 
information in the monitoring plan required under Sec. 75.53, 
depending on the type of gaseous fuel:
    2.3.3.1  For pipeline natural gas, provide information 
demonstrating that the definition of pipeline natural gas in 
Sec. 72.2 of this chapter has been met. This demonstration must be 
made using one of the following sources of information: (1) the gas 
quality characteristics specified by a purchase contract or by a 
pipeline transportation contract; (2) a certification of the gas 
vendor, based on routine vendor sampling and analysis; or (3) at 
least one year's worth of analytical data on the fuel hydrogen 
sulfide content from samples taken monthly or more frequently.
    2.3.3.2  For gaseous fuel other than pipeline natural gas for 
which a petition has been submitted and approved under section 
2.3.2.2 of this appendix, provide the information required to be 
included in the petition pursuant to section 2.3.2.2.
    2.3.3.3  For liquefied petroleum gas and other gaseous fuels 
provided in batches or lots having uniform sulfur content, provide 
either contractual information from the fuel supplier or provide 
historical information on each lot of liquefied petroleum gas from 
at least one year.
    2.3.3.4  For any other gaseous fuel or blend, including gas 
produced by a variable process (e.g., digester gas or landfill gas), 
provide data on the fuel sulfur content, as follows. Provide a 
minimum of 720 hours of data, indicating the total sulfur content of 
the gas or blend (in gr/100 scf). The data shall be obtained with a 
gas chromatograph, and, for gaseous fuel produced by a variable 
process, the data shall be representative of all process operating 
conditions. The data shall be reduced to hourly averages and shall 
be

[[Page 28184]]

used to determine whether daily sampling of the sulfur content of 
the gas or blend is sufficient or whether sampling, at least hourly, 
with a gas chromatograph is required. Specifically, daily gas 
sampling shall be sufficient, provided that either: (1) the mean 
value of the total sulfur content of the gas or blend is 
7 grains per 100 scf; or (2) the standard deviation of 
the hourly average values from the mean does not exceed 5 grains per 
100 scf. If the gas or blend does not meet requirement (1) or (2), 
then sampling, at least hourly, of the fuel with a gas chromatograph 
(GCH) and hourly reporting of the hourly average sulfur content of 
the fuel is required. If sampling, at least hourly, from a gas 
chromatograph is required, the owner or operator shall develop and 
implement a program to quality assure the data from the GCH, in 
accordance with the manufacturer's recommended procedures. The 
quality assurance procedures shall be kept on-site, in a form 
suitable for inspection.
    2.4  * * *

2.4.1  Missing Data for Oil and Gas Samples

    When oil sulfur content, density, or gross calorific value data 
are missing or invalid for an oil or gas sample taken according to 
the procedures in section 2.2.3, 2.2.4.1, 2.2.4.2, 2.2.4.3, 2.3.1, 
2.3.1.1, 2.3.1.2, or 2.3.1.3 of this appendix, then substitute the 
maximum potential sulfur content, density, or gross calorific value 
of that fuel from Table D-7 of this appendix.

  Table D-7.--Missing Data Substitution Procedures for Sulfur, Density, 
                        and Gross Calorific Value                       
------------------------------------------------------------------------
                                  Data                                  
-------------------------------------------------------------------------
                                   Missing data substitution maximum    
          Parameter                         potential value             
------------------------------------------------------------------------
Oil Sulfur Content...........  3.5 percent for residual oil, or. 1.0    
                                percent for diesel fuel.                
Oil Density..................  8.5 lb/gal for residual oil, or 7.4 lb/  
                                gal for diesel fuel.                    
Oil GCV......................  19,500 Btu/lb for residual oil, or 20,000
                                Btu/lb for diesel fuel.                 
Gas Sulfur Content...........  0.30 gr/100 scf for pipeline natural gas,
                                or 20.0 gr/100 scf for other gaseous    
                                fuel.                                   
Gas GCV/Heat Content.........  1100 Btu/scf for pipeline natural gas, or
                                2100 Btu/scf for other gaseous fuel.    
------------------------------------------------------------------------

    2.4.2  Whenever data are missing from any fuel flowmeter that is 
part of an excepted monitoring system under appendix D or E to this 
part, where the fuel flowmeter data are required to determine the 
amount of fuel combusted by the unit, use the procedures in sections 
2.4.2.2 and 2.4.2.3 of this appendix to account for the flow rate of 
fuel combusted at the unit for each hour during the missing data 
period. In addition, a fuel flowmeter used for measuring fuel 
combusted by a peaking unit may use the simplified fuel flow missing 
data procedure in section 2.4.2.1 of this appendix.
    2.4.2.1  Simplified Fuel Flow Missing Data for Peaking Units.
    If no fuel flow rate data are available for a fuel flowmeter 
system installed on a peaking unit (as defined in Sec. 72.2 of this 
chapter), then substitute for each hour of missing data using the 
maximum potential fuel flow rate. The maximum potential fuel flow 
rate is the lesser of the following: (1) the maximum fuel flow rate 
the unit is capable of combusting or (2) the maximum flow rate that 
the flowmeter can measure (i.e, upper range value of flowmeter 
leading to a unit).
    2.4.2.2  * * *
    2.4.2.3  For hours where two or more fuels are combusted, 
substitute the maximum hourly fuel flow rate measured and recorded 
by the flowmeter (or flowmeters, where fuel is recirculated) for the 
fuel for which data are missing at the corresponding load range 
recorded for each missing hour during the previous 720 hours when 
the unit combusted that fuel with any other fuel. For hours where no 
previous recorded fuel flow rate data are available for that fuel 
during the missing data period, calculate and substitute the maximum 
potential flow rate of that fuel for the unit as defined in section 
2.4.2.2 of this appendix.
    2.4.3  * * *
    65. Section 3 of appendix D to part 75 is amended by:
    a. Revising sections 3, 3.1, 3.2, 3.2.1, 3.2.3, 3.2.4, and 3.3;
    b. Redesignating section 3.4 as section 3.5 and revising the 
introductory text; and
    c. Adding a new section 3.4, to read as follows:

3. Calculations

    Use the calculation procedures in section 3.1 of this appendix 
to calculate SO2 mass emission rate. Where an oil 
flowmeter records volumetric flow rate, use the calculation 
procedures in section 3.2 of this appendix to calculate the mass 
flow rate of oil. Calculate hourly SO2 mass emission rate 
from gaseous fuel using the procedures in section 3.3 of this 
appendix. Calculate hourly heat input rate for oil and for gaseous 
fuel using the equations in section 5.5 of appendix F to this part. 
Calculate total SO2 mass emissions and heat input as 
provided under section 3.4 of this appendix.

3.1  SO2 Mass Emission Rate Calculation for Oil

    3.1.1  Use the following equation to calculate SO2 
mass emissions per hour (lb/hr):
[GRAPHIC] [TIFF OMITTED] TP21MY98.021

(Eq. D-2)
where:
MSO2 = Hourly mass emission rate of SO2 
emitted from combustion of oil, lb/hr.
Moil = Mass rate of oil consumed per hr, lb/hr.
%Soil = Percentage of sulfur by weight measured in the 
sample.
2.0 = Ratio of lb SO2/lb S.
    3.1.2  Record the SO2 mass emission rate from oil for 
each hour that oil is combusted.

3.2  Mass Flow Rate Calculation for Oil Using Volumetric Flow Rate

    3.2.1  Where the oil flowmeter records volumetric flow rate 
rather than mass flow rate, calculate and record the oil mass flow 
rate for each hourly period using hourly oil flow rate measurements 
and the density or specific gravity of the oil sample.
* * * * *
    3.2.3  Where density of the oil is determined by the applicable 
ASTM procedures from section 2.2.5 of this appendix, use the 
following equation to calculate the rate of the mass of oil consumed 
(in lb/hr):

Moil=Voil x Doil

(Eq. D-3)

Where:

Moil = Mass rate of oil consumed per hr, lb/hr.
Voil = Volume rate of oil consumed per hr, measured in 
scf, gal, barrels, or m\3\.
Doil = Density of oil, measured in lb/scf, lb/gal, lb/
barrel, or lb/m\3\.
    3.2.4  Calculate the hourly heat input rate to the unit from oil 
(mmBtu/hr) by multiplying the heat content of the daily oil sample 
by the hourly oil mass rate.

3.3  SO2 Mass Emissions Rate Calculation for Gaseous 
Fuels

    3.3.1  Use the following equation to calculate the 
SO2 emission rate using the gas sampling and analysis 
procedures in section 2.3.1 of this appendix:
[GRAPHIC] [TIFF OMITTED] TP21MY98.022

(Eq. D-4)

Where:

M(SO2)g = Hourly mass rate of SO2 emitted due 
to combustion of gaseous fuel, lb/hr.
Qg = Hourly metered flow rate of gaseous fuel combusted, 
100 scf/hr.
Sg = Sulfur content of gaseous fuel, in grain/100 scf.
2.0 = Ratio of lb SO2/lb S.
7000 = Conversion of grains/100 scf to lb/100 scf.

    3.3.2  Use the following equation to calculate the 
SO2 emission rate using the

[[Page 28185]]

0.0006 lb/mmBtu emission rate in section 2.3.2 of this appendix:

M(SO2)g = ER  x  HIg

(Eq. D-5)

Where:

M(SO2)g = Hourly mass rate of SO2 emissions 
from combustion of pipeline natural gas, lb/hr.
ER = SO2 emission rate of 0.0006 lb/mmBtu for pipeline 
natural gas.
Hig = Hourly heat input rate of pipeline natural gas, 
calculated using procedures in appendix F to this part, in mmBtu/hr.

    3.3.3  Record the SO2 mass emission rate for each 
hour when the unit combusts gaseous fuel.

3.4  Conversion of Rates to Totals and Summation of Quarterly and 
Cumulative Values

    3.4.1  SO2 Mass Emissions Conversions and Summations.
    For a unit or for a common pipe, calculate total quarterly 
SO2 mass emissions (using Equation D-6) and total 
cumulative SO2 mass emissions (using Equation D-7). First 
convert hourly SO2 mass emission rates for each fuel to 
total hourly SO2 mass emissions, by multiplying the 
hourly rates by the fuel usage time. Second, sum the total hourly 
SO2 mass emissions from all fuels for the quarter. Third, 
convert the quarterly SO2 mass emission total to tons. 
Finally, for cumulative emissions, sum the quarterly SO2 
mass emission totals, in tons, for each quarter in the year to date.
[GRAPHIC] [TIFF OMITTED] TP21MY98.023

(Eq. D-6)

Where:

SO2q = Total SO2 mass emissions for the 
quarter, tons.
SO2i fuel system = SO2 mass emission rate for 
a given fuel for a particular fuel flow system, lb/hr.
ti = Fuel usage time for the fuel and system, hour or 
fraction of an hour.
[GRAPHIC] [TIFF OMITTED] TP21MY98.024

(Eq. D-7)

Where:

SO2c = Total SO2 mass emissions for the year 
to date, tons.
SO2q = Total SO2 mass emissions for the 
quarter, tons.
    3.4.2  Heat Input Conversions and Summations

    Calculate total quarterly (using Equation D-8) and total 
cumulative (using Equation D-9) heat input for a unit or common pipe 
with fuel flow systems.
[GRAPHIC] [TIFF OMITTED] TP21MY98.025

(Eq. D-8)

Where:

HIq = Total heat input for the quarter, mmBtu.
HIi fuel system = Heat input rate during fuel usage for a 
given fuel for a particular fuel flow system, using Equation F-19 or 
F-20, mmBtu/hr.
ti = Fuel usage time for the fuel and system, hour or 
fraction of an hour.
[GRAPHIC] [TIFF OMITTED] TP21MY98.026

(Eq. D-9)

Where:

HIc=Total heat input for the year to date, mmBtu.
HIq=Total heat input for the quarter, mmBtu.

3.5  Records and Reports

    Calculate and record quarterly and cumulative SO2 
mass emissions and heat input for each calendar quarter using the 
procedures and equations of section 3.4 of this appendix.
* * * * *

APPENDIX E TO PART 75--OPTIONAL NOX EMISSIONS ESTIMATION 
PROTOCOL FOR GAS-FIRED PEAKING UNITS AND OIL-FIRED PEAKING UNITS

* * * * *
    66. Section 2 of appendix E to part 75 is amended by revising 
sections 2.5.4 and 2.5.5 to read as follows:

2. Procedure

* * * * *

2.5  Missing Data Procedures

* * * * *
    2.5.4  Substitute missing data from a fuel flowmeter using the 
procedures in section 2.4.2 of appendix D to this part.
    2.5.5  Substitute missing data for gross calorific value of fuel 
using the procedures in sections 2.4.1 of appendix D to this part.
    67. Section 3 of Appendix E to part 75 is amended by revising 
sections 3.1, 3.3.1, and 3.3.4 to read as follows:

3. Calculations

3.1  Heat Input

    Calculate the total heat input by summing the product of heat 
input rate and fuel usage time of each fuel, as in the following 
equation:

HT=HIfuel 1t1+HIfuel 2t2
+HIfuel 3t3+...+HIlastfueltlast


(Eq. E-1)

Where:


[[Page 28186]]


HT=Total heat input of fuel flow or a combination of fuel 
flows to a unit, mmBtu.
HIfuel 1,2,3,...last=Heat input rate from each fuel, in 
mmBtu/hr as determined using Equation F-19 or F-20 in section 5.5 of 
appendix F to this part, mmBtu/hr.
t1,2,3....last=Fuel usage time for each fuel (rounded up 
to the nearest fraction of an hour (in equal increments that can 
range from one hundredth to one quarter of an hour, at the option of 
the owner or operator)).
* * * * *

3.3  * * *

    3.3.1  Conversion from Concentration to Emission Rate.
    Convert the NOX concentrations (ppm) and 
O2 concentrations to NOX emission rates (to 
the nearest 0.01 lb/mmBtu for tests performed prior to January 1, 
2000 or to the nearest 0.001 lb/mmBtu for tests performed on and 
after January 1, 2000), according to the appropriate one of the 
following equations: F-5 in appendix F to this part for dry basis 
concentration measurements or 19-3 in Method 19 of appendix A to 
part 60 of this chapter for wet basis concentration measurements.
* * * * *
    3.3.4  Average NOX Emission Rate During Co-firing of 
Fuels.
[GRAPHIC] [TIFF OMITTED] TP21MY98.027

(Eq. E-2)
Where:
Eh=NOX emission rate for the unit for the 
hour, lb/mmBtu.
Ef=NOX emission rate for the unit for a given 
fuel at heat input rate HIf, lb/mmBtu.
HIf=Heat input rate for the hour for a given fuel, during 
the fuel usage time, as determined using Equation F-19 or F-20 in 
section 5.5 of appendix F to this part, mmBtu/hr
HT=Total heat input for all fuels for the hour from 
Equation E-1.
tf=Fuel usage time for each fuel (rounded up to the 
nearest fraction of an hour (in equal increments that can range from 
one hundredth to one quarter of an hour, at the option of the owner 
or operator)).
    Note: For hours where a fuel is combusted for only part of the 
hour, use the fuel flow rate or mass flow rate during the fuel usage 
time, instead of the total fuel flow or mass flow during the hour, 
when calculating heat input rate using Equation F-19 or F-20.

    68. Section 2 of appendix F to part 75 is revised to read as 
follows:

Appendix F to Part 75--Conversion Procedures

* * * * *

2. Procedures for SO2 Emissions

    Use the following procedures to compute hourly SO2 
mass emission rate (in lb/hr) and quarterly and annual 
SO2 total mass emissions (in tons). Use the procedures in 
Method 19 in appendix A to part 60 of this chapter to compute hourly 
SO2 emission rates (in lb/mmBtu) for qualifying Phase I 
technologies. When computing hourly SO2 emission rate in 
lb/mmBtu, a minimum concentration of 5.0 percent CO2 and 
a maximum concentration of 14.0 percent O2 may be 
substituted for measured diluent gas concentration values at boilers 
during hours when the hourly average concentration of CO2 
is less than 5.0 percent CO2 or the hourly average 
concentration of O2 is greater than 14.0 percent 
O2.
    2.1 When measurements of SO2 concentration and flow 
rate are on a wet basis, use the following equation to compute 
hourly SO2 mass emission rate (in lb/hr):

Eh = KChQh

(Eq. F-1)

Where:

Eh = Hourly SO2 mass emission rate during unit 
operation, lb/hr.
K = 1.660  x  10-7 for SO2, (lb/scf)/ppm.
Ch = Hourly average SO2 concentration during 
unit operation, stack moisture basis, ppm.
Qh = Hourly average volumetric flow rate during unit 
operation, stack moisture basis, scfh.

2.2  When measurements by the SO2 pollutant concentration 
monitor are on a dry basis and the flow rate monitor measurements 
are on a wet basis, use the following equation to compute hourly 
SO2 mass emission rate (in lb/hr): 
[GRAPHIC] [TIFF OMITTED] TP21MY98.028

(Eq. F-2)

Where:

Eh = Hourly SO2 mass emission rate during unit 
operation, lb/hr.
K = 1.660  x  10-7 for SO2, (lb/scf)/ppm.
Chp = Hourly average SO2 concentration during 
unit operation, ppm (dry).
Qhs= Hourly average volumetric flow rate during unit 
operation, scfh as measured (wet).
%H2O = Hourly average stack moisture content during unit 
operation, percent by volume.

    2.3  Use the following equations to calculate total 
SO2 mass emissions for each calendar quarter (Equation F-
3) and for each calendar year (Equation F-4), in tons: 
[GRAPHIC] [TIFF OMITTED] TP21MY98.029

(Eq. F-3)

Where:

Eq = Quarterly total SO2 mass emissions, tons.
Eh = Hourly SO2 mass emission rate, lb/hr.
th = Unit operating time, hour or fraction of an hour (in 
equal increments that can range from one hundredth to one quarter of 
an hour, at the option of the owner or operator).
n = Number of hourly SO2 emissions values during calendar 
quarter.
2000 = Conversion of 2000 lb per ton. 
[GRAPHIC] [TIFF OMITTED] TP21MY98.030

(Eq. F-4)

Where:

Ea = Annual total SO2 mass emissions, tons.
Eq = Quarterly total SO2 mass emissions, tons.
q = Quarters for which Eq are available during calendar 
year.

    2.4  Round all SO2 mass emission rates and totals to 
the nearest tenth.

    69. Section 3 of appendix F to part 75 is amended by revising 
sections 3.3.2, 3.3.3, 3.3.4, 3.4, and 3.5 to read as follows:

3. Procedures for NOX Emission Rate

* * * * *
    3.3  * * *
3.3.2  E = Pollutant emissions during unit operation, lb/mmBtu.
3.3.3  Ch = Hourly average pollutant concentration during 
unit operation, ppm.
3.3.4  %O2, %CO2 = Oxygen or carbon dioxide 
volume during unit operation (expressed as percent O2 or 
CO2). A minimum concentration of 5.0 percent 
CO2 and a maximum concentration of 14.0 percent 
O2 may be substituted for measured diluent gas 
concentration values at boilers during hours when the hourly average 
concentration of CO2 is <5.0 percent CO2 or 
the hourly average concentration of O2 is >14.0 percent 
O2. A minimum concentration of 1.0 percent CO2 
and a maximum concentration of 19.0 percent O2 may be 
substituted for measured diluent gas concentration values at 
stationary gas turbines during hours when the hourly average 
concentration of CO2 is <1.0 percent CO2 or 
the hourly average concentration of O2 is >19.0 percent 
O2.
* * * * *
    3.4  Use the following equations to calculate the average 
NOX emission rate for each calendar quarter (Equation F-
9) and the average emission rate for the calendar year (Equation F-
10), in lb/mmBtu: 
[GRAPHIC] [TIFF OMITTED] TP21MY98.031

(Eq. F-9)

Where:

Eq = Quarterly average NOX emission rate, lb/
mmBtu.
Ei = Hourly average NOX emission rate during 
unit operation, lb/mmBtu.
n = Number of hourly rates during calendar quarter. 
[GRAPHIC] [TIFF OMITTED] TP21MY98.032

(Eq. F-10)

Where:

Ea = Average NOX emission rate for the 
calendar year, lb/mmBtu.

[[Page 28187]]

Ei = Hourly average NOX emission rate during 
unit operation, lb/mmBtu.
m = Number of hourly rates for which Ei is available in 
the calendar year.

    3.5  Round all NOX emission rates to the nearest 0.01 
lb/mmBtu prior to January 1, 2000 and to the nearest 0.001 lb/mmBtu 
on and after January 1, 2000.

    70. Section 4 of appendix F to part 75 is amended by revising 
sections 4.1, 4.2, 4.3, and 4.4.1 to read as follows:

4. Procedures for CO2 Mass Emissions

* * * * *
    4.1  When CO2 concentration is measured on a wet 
basis, use the following equation to calculate hourly CO2 
mass emissions rates (in tons/hr):

Eh = KChQh

(Eq. F-11)

Where:

Eh = Hourly CO2 mass emission rate during unit 
operation, tons/hr.
K = 5.7 X 10-7 for CO2, (tons/scf) /
%CO2.
Ch = Hourly average CO2 concentration during 
unit operation, wet basis, percent CO2. For boilers, a 
minimum concentration of 5.0 percent CO2 may be 
substituted for the measured concentration when the hourly average 
concentration of CO2 is < 5.0 percent CO2, 
provided that this minimum concentration of 5.0 percent 
CO2 is also used in the calculation of heat input for 
that hour. For stationary gas turbines, a minimum concentration of 
1.0 percent CO2 may be substituted for measured diluent 
gas concentration values during hours when the hourly average 
concentration of CO2 is < 1.0 percent CO2, 
provided that this minimum concentration of 1.0 percent 
CO2 is also used in the calculation of heat input for 
that hour.
Qh = Hourly average volumetric flow rate during unit 
operation, wet basis, scfh.

    4.2  When CO2 concentration is measured on a dry 
basis, use Equation F-2 to calculate the hourly CO2 mass 
emission rate (in tons/hr) with a K-value of 5.7  x  10-7 
(tons/scf) percent CO2, where Eh = hourly 
CO2 mass emission rate, tons/hr and Chp = 
hourly average CO2 concentration in flue, dry basis, 
percent CO2.
    4.3  Use the following equations to calculate total 
CO2 mass emissions for each calendar quarter (Equation F-
12) and for each calendar year (Equation F-13): 
[GRAPHIC] [TIFF OMITTED] TP21MY98.033

(Eq. F-12)

Where:

E(CO2)q = Quarterly total CO2 mass emissions, 
tons.
Eh = Hourly CO2 mass emission rate, tons/hr.
th = Unit operating time, in hours or fraction of an hour 
(in equal increments that can range from one hundredth to one 
quarter of an hour, at the option of the owner or operator).
HR = Number of hourly CO2 mass emission rates 
available during calendar quarter.
* * * * *
    4.4  * * *
    4.4.1  Use appropriate F and Fc factors from section 
3.3.5 of this appendix in the following equation to determine hourly 
average CO2 concentration of flue gases (in percent by 
volume):
  
  
  
   
[GRAPHIC] [TIFF OMITTED] TP21MY98.034

(Eq. F-14a)

Where:

CO2d = Hourly average CO2 concentration during 
unit operation, percent by volume, dry basis.
F, Fc = F-factor or carbon-based Fc-factor 
from section 3.3.5 of this appendix.
20.9 = Percentage of O2 in ambient air.
O2d = Hourly average O2 concentration during unit 
operation, percent by volume, dry basis. For boilers, a maximum 
concentration of 14.0 percent O2 may be substituted for 
the measured concentration when the hourly average concentration of 
O2 is > 14.0 percent O2, provided that this 
maximum concentration of 14.0 percent O2 is also used in 
the calculation of heat input for that hour. For stationary gas 
turbines, a maximum concentration of 19.0 percent O2 may 
be substituted for measured diluent gas concentration values during 
hours when the hourly average concentration of O2 is > 
19.0 percent O2, provided that this maximum concentration 
of 19.0 percent O2 is also used in the calculation of 
heat input for that hour.

 [GRAPHIC] [TIFF OMITTED] TP21MY98.035

or
(Eq. F-14b)

Where:

CO2w = Hourly average CO2 concentration during 
unit operation, percent by volume, wet basis.
O2w = Hourly average O2 concentration during 
unit operation, percent by volume, wet basis. For boilers, a maximum 
concentration of 14.0 percent O2 may be substituted for 
the measured concentration when the hourly average concentration of 
O2 is > 14.0 percent O2, provided that this 
maximum concentration of 14.0 percent O2 is also used in 
the calculation of heat input for that hour. For stationary gas 
turbines, a maximum concentration of 19.0 percent O2 may 
be substituted for measured diluent gas concentration values during 
hours when the hourly average concentration of O2 is > 
19.0 percent O2, provided that this maximum concentration 
of 19.0 percent O2 is also used in the calculation of 
heat input for that hour.
F, Fc = F-factor or carbon-based Fc-factor 
from section 3.3.5 of this appendix.
20.9 = Percentage of O2 in ambient air.
%H2O = Moisture content of gas in the stack, percent.
* * * * *
    71. Section 5 of appendix F to part 75 is amended by revising 
sections 5, 5.1, 5.2, 5.5, 5.5.1, and 5.5.2 and by adding new sections 
5.3, 5.6, and 5.7 to read as follows:

5. Procedures for Heat Input

    Use the following procedures to compute heat input rate to an 
affected unit (in mmBtu/hr or mmBtu/day):
    5.1  Calculate and record heat input rate to an affected unit on 
an hourly basis, except as provided below. The owner or operator may 
choose to use the provisions specified in Sec. 75.16(e) or in 
section 2.1.2 of appendix D to this part in conjunction with the 
procedures provided below to apportion heat input among each unit 
using the common stack or common pipe header.

[[Page 28188]]

    5.2  For an affected unit that has a flow monitor (or approved 
alternate monitoring system under subpart E of this part for 
measuring volumetric flow rate) and a diluent gas (O2 or 
CO2) monitor, use the recorded data from these monitors 
and one of the following equations to calculate hourly heat input 
rate (in mmBtu/hr).
    5.2.1  When measurements of CO2 concentration are on 
a wet basis, use the following equation:
[GRAPHIC] [TIFF OMITTED] TP21MY98.036

(Eq. F-15)

Where:

HI = Hourly heat input rate during unit operation, mmBtu/hr.
Qw = Hourly average volumetric flow rate during unit 
operation, wet basis, scfh.
Fc = Carbon-based F-factor, listed in section 3.3.5 of 
this appendix for each fuel, scf/mmBtu.
%CO2w = Hourly concentration of CO2 during 
unit operation, percent CO2 wet basis. For boilers, a 
minimum concentration of 5.0 percent CO2 may be 
substituted for the measured concentration when the hourly average 
concentration of CO2 is < 5.0 percent CO2, 
provided that this minimum concentration of 5.0 percent 
CO2 is also used in the calculation of CO2 
mass emissions for that hour. For stationary gas turbines, a minimum 
concentration of 1.0 percent CO2 may be substituted for 
measured diluent gas concentration values during hours when the 
hourly average concentration of CO2 is < 1.0 percent 
CO2, provided that this minimum concentration of 1.0 
percent CO2 is also used in the calculation of 
CO2 mass emissions for that hour.
5.2.2  When measurements of CO2 concentration are on a 
dry basis, use the following equation:
[GRAPHIC] [TIFF OMITTED] TP21MY98.037

(Eq. F-16)

Where:

HI = Hourly heat input rate during unit operation, mmBtu/hr.
Qh = Hourly average volumetric flow rate during unit 
operation, wet basis, scfh.
Fc = Carbon-based F-Factor, listed above in section 3.3.5 
of this appendix for each fuel, scf/mmBtu.
%CO2d = Hourly concentration of CO2 during 
unit operation, percent CO2 dry basis. For boilers, a 
minimum concentration of 5.0 percent CO2 may be 
substituted for the measured concentration when the hourly average 
concentration of CO2 is < 5.0 percent CO2, 
provided that this minimum concentration of 5.0 percent 
CO2 is also used in the calculation of CO2 
mass emissions for that hour. For stationary gas turbines, a minimum 
concentration of 1.0 percent CO2 may be substituted for 
measured diluent gas concentration values during hours when the 
hourly average concentration of CO2 is < 1.0 percent 
CO2, provided that this minimum concentration of 1.0 
percent CO2 is also used in the calculation of 
CO2 mass emissions for that hour.
%H2O = Moisture content of gas in the stack, percent.

    5.2.3  When measurements of O2 concentration are on a 
wet basis, use the following equation:
[GRAPHIC] [TIFF OMITTED] TP21MY98.038

(Eq. F-17)

Where:

HI = Hourly heat input rate during unit operation, mmBtu/hr.
Qw = Hourly average volumetric flow rate during unit 
operation, wet basis, scfh.
F = Dry basis F-Factor, listed above in section 3.3.5 of this 
appendix for each fuel, dscf/mmBtu.
%O2w = Hourly concentration of O2 during unit 
operation, percent O2 wet basis. For boilers, a maximum 
concentration of 14.0 percent O2 may be substituted for 
the measured concentration when the hourly average concentration of 
O2 is > 14.0 percent O2, provided that this 
maximum concentration of 14.0 percent O2 is also used in 
the calculation of CO2 mass emissions for that hour. For 
stationary gas turbines, a maximum concentration of 19.0 percent 
O2 may be substituted for measured diluent gas 
concentration values during hours when the hourly average 
concentration of O2 is > 19.0 percent O2, 
provided that this maximum concentration of 19.0 percent 
O2 is also used in the calculation of CO2 mass 
emissions for that hour.
%H2O = Hourly average stack moisture content, percent by 
volume.
    5.2.4  When measurements of O2 concentration are on a 
dry basis, use the following equation:
[GRAPHIC] [TIFF OMITTED] TP21MY98.039


[[Page 28189]]


(Eq. F-18)

Where:

HI = Hourly heat input rate during unit operation, mmBtu/hr.
Qw = Hourly average volumetric flow during unit operation, wet 
basis, scfh.
F = Dry basis F-factor, listed above in section 3.3.5 of this 
appendix for each fuel, dscf/mmBtu.
%H2O = Moisture content of the stack gas, percent.
%O2d = Hourly concentration of O2 during unit 
operation, percent O2 dry basis. For boilers, a maximum 
concentration of 14.0 percent O2 may be substituted for 
the measured concentration when the hourly average concentration of 
O2 is > 14.0 percent O2, provided that this 
maximum concentration of 14.0 percent O2 is also used in 
the calculation of CO2 mass emissions for that hour.. For 
stationary gas turbines, a maximum concentration of 19.0 percent 
O2 may be substituted for measured diluent gas 
concentration values during hours when the hourly average 
concentration of O2 is > 19.0 percent O2, 
provided that this maximum concentration of 19.0 percent 
O2 is also used in the calculation of CO2 mass 
emissions for that hour.

5.3  Heat Input Summation (for Heat Input Determined Using a Flow 
Monitor and Diluent Monitor)

    5.3.1  Calculate total quarterly heat input for a unit or common 
stack using a flow monitor and diluent monitor to calculate heat 
input, using the following equation:
[GRAPHIC] [TIFF OMITTED] TP21MY98.040

(Eq. F-18a)

Where:

HIq = Total heat input for the quarter, mmBtu.
HIi = Hourly heat input rate during unit operation, using 
Equation F-15, F-16, F-17, or F-18, mmBtu/hr.
ti = Hourly operating time for the unit or common stack, 
hour or fraction of an hour (in equal increments that can range from 
one hundredth to one quarter of an hour, at the option of the owner 
or operator).
    5.3.2  Calculate total cumulative heat input for a unit or 
common stack using a flow monitor and diluent monitor to calculate 
heat input, using the following equation:
[GRAPHIC] [TIFF OMITTED] TP21MY98.041

(Eq. F-18b)

Where:

HIc = Total heat input for the year to date, mmBtu.
HIq = Total heat input for the quarter, mmBtu.

5.4  [Reserved]

    5.5  For a gas-fired or oil-fired unit that does not have a flow 
monitor and is using the procedures specified in appendix D to this 
part to monitor SO2 emissions or for any unit using a 
common stack for which the owner or operator chooses to determine 
heat input by fuel sampling and analysis, use the following 
procedures to calculate hourly heat input rate in mmBtu/hr. The 
procedures of section 5.5.3 of this appendix shall not be used to 
determine heat input from a coal unit that is required to comply 
with the provisions of this part for monitoring, recording, and 
reporting NOX mass emissions under a state or federal 
NOX mass emission reduction program.
    5.5.1  When the unit is combusting oil, use the following 
equation to calculate hourly heat input rate:
[GRAPHIC] [TIFF OMITTED] TP21MY98.042

(Eq. F-19)

Where:

HIo = Hourly heat input rate from oil, mmBtu/hr.
Mo = Mass rate of oil consumed per hour, as determined 
using procedures in appendix D to this part, in lb/hr, tons/hr, or 
kg/hr.
GCVo = Gross calorific value of oil, as measured by ASTM 
D240-87 (Reapproved 1991), ASTM D2015-91, or ASTM D2382-88 for each 
oil sample under section 2.2 of appendix D to this part, Btu/unit 
mass (incorporated by reference under Sec. 75.6).
106 = Conversion of Btu to mmBtu. When performing oil 
sampling and analysis solely for the purpose of the missing data 
procedures in Sec. 75.36, oil samples for measuring GCV may be taken 
weekly, and the procedures specified in appendix D to this part for 
determining the mass rate of oil consumed per hour are optional.
    5.5.2 When the unit is combusting gaseous fuels, use the 
following equation to calculate heat input rate from gaseous fuels 
for each hour:
[GRAPHIC] [TIFF OMITTED] TP21MY98.043

(Eq. F-20)

Where:

HIg=Hourly heat input rate from gaseous fuel, mmBtu/hour.
Qg=Metered flow rate of gaseous fuel combusted during 
unit operation, hundred cubic feet.
GCVg=Gross calorific value of gaseous fuel, as determined 
by sampling (for each delivery for gaseous fuel in lots, for each 
daily gas sample for gaseous fuel delivered by pipeline, for each 
hourly average for gas measured hourly with a GCH, or for each 
monthly sample of pipeline natural gas, or as verified by the 
contractual supplier at least once every month pipeline natural gas 
is combusted, as specified in section 2.3 of appendix D to this 
part) using ASTM D1826-88, ASTM D3588-91, ASTM D4891-89, GPA 
Standard 2172-86 ``Calculation of Gross Heating Value, Relative 
Density and Compressibility Factor for Natural Gas Mixtures from 
Compositional Analysis,'' or GPA Standard 2261-90 ``Analysis for 
Natural Gas and Similar Gaseous Mixtures by Gas Chromatography,'' 
Btu/100 scf (incorporated by reference under Sec. 75.6).
106=Conversion of Btu to mmBtu.
* * * * *

5.6  Heat Input Rate Apportionment for Units Sharing a Common Stack 
or Pipe

    5.6.1  Where applicable, the owner or operator of an affected 
unit that determines heat input rate at the unit level by 
apportioning the heat input monitored at a common stack or common 
pipe using megawatts should apportion the heat input rate using the 
following equation:
[GRAPHIC] [TIFF OMITTED] TP21MY98.044

(Eq. F-21a)

Where:

HIi=Heat input rate for a unit, mmBtu/hr.
HICS=Heat input rate at the common stack or pipe; mmBtu/
hr.
MWi=Gross electrical output, MWe.
ti=Operating time at a particular unit, hour or fraction 
of an hour (in equal increments that can range from one hundredth to 
one quarter of an hour, at the option of the owner or operator).
tCS=Operating time at common stack, hour or fraction of 
an hour (in equal increments that can range from one hundredth to 
one quarter of an hour, at the option of the owner or operator).
n=Total number of units using the common stack.
i=Designation of a particular unit.

    5.6.2  Where applicable, the owner or operator of an affected 
unit that determines the heat input rate at the unit level by 
apportioning the heat input rate monitored at a common stack or 
common pipe using steam load should apportion the heat input rate 
using the following equation:

[[Page 28190]]

[GRAPHIC] [TIFF OMITTED] TP21MY98.045


(Eq. F-21b)

Where:

HIi=Heat input rate for a unit, mmBtu/hr.
HICS=Heat input rate at the common stack or pipe, mmBtu/
hr.
SF=Gross steam load, lb/hr.
ti=Operating time at a particular unit, hour or fraction 
of an hour (in equal increments that can range from one hundredth to 
one quarter of an hour, at the option of the owner or operator).
tCS=Operating time at common stack, hour or fraction of 
an hour (in equal increments that can range from one hundredth to 
one quarter of an hour, at the option of the owner or operator).
n=Total number of units using the common stack.
i=Designation of a particular unit.

5.7  Heat Input Rate Summation for Units with Multiple Stacks or 
Pipes

    The owner or operator of an affected unit that determines the 
heat input rate at the unit level by summing the heat input rates 
monitored at multiple stacks or multiple pipes should sum the heat 
input rates using the following equation:
[GRAPHIC] [TIFF OMITTED] TP21MY98.046

(Eq. F-21c)

Where:

HIUnit=Heat input rate for a unit, mmBtu/hr.
HIs=Heat input rate for each stack or duct leading from 
the unit, mmBtu/hr.
tUnit=Operating time for the unit, hour or fraction of 
the hour (in equal increments that can range from one hundredth to 
one quarter of an hour, at the option of the owner or operator).
ts=Operating time during which the unit is exhausting 
through the stack or duct, hour or fraction of the hour (in equal 
increments that can range from one hundredth to one quarter of an 
hour, at the option of the owner or operator).

    72. Section 8 of appendix F to part 75 is added to read as follows:

8. Procedures for NOX Mass Emissions

    The owner or operator of a unit that is required to monitor, 
record, and report NOX mass emissions under a state or 
federal NOX mass emission reduction program must use the 
procedures in section 8.1 to account for hourly NOX mass 
emissions, and the procedures in section 8.2 to account for 
quarterly, seasonal, and annual NOX mass emissions if the 
provisions of subpart H of this part are adopted as requirements 
under such a program.
    8.1  Use the following procedures to calculate hourly 
NOX mass emissions in lbs for the hour.
    8.1.1  If both NOX emission rate and heat input are 
monitored at the same unit or stack level (e.g, the NOX 
emission rate value and heat input value both represent all of the 
units exhausting to the common stack), use the following equation:

[GRAPHIC] [TIFF OMITTED] TP21MY98.068

(Eq. F-23)

Where:

MNOx(h)=NOX mass emissions in lbs for the 
hour.
Eh=Hourly average NOX emission rate for hour 
h, lb/mmBtu.
Hih=Hourly average heat input rate for hour h, mmBtu/hr.
th=Monitoring location operating time for hour h, in 
hours or fraction of an hour (in equal increments that can range 
from one hundredth to one quarter of an hour, at the option of the 
owner or operator). If the combined NOX emission rate and 
heat input are monitored for all of the units in a common stack, the 
monitoring location operating time is equal to the total time when 
any of those units was exhausting through the common stack.

    8.1.2  If NOX emission rate is measured at a common 
stack and heat input is measured at the unit level, sum the hourly 
heat inputs at the unit level according to the following formula:
[GRAPHIC] [TIFF OMITTED] TP21MY98.047

(Eq. F-24)

Where:

HICS=Hourly average heat input rate for hour h for the 
units at the common stack, mmBtu/hr.
tCS=Common stack operating time for hour h, in hours or 
fraction of an hour (in equal increments that can range from one 
hundredth to one quarter of an hour, at the option of the owner or 
operator)(e.g., total time when any of the units which exhaust 
through the common stack are operating).
HIu=Hourly average heat input rate for hour h for the 
unit, mmBtu/hr.
tu=Unit operating time for hour h, in hours or fraction 
of an hour (in equal increments that can range from one hundredth to 
one quarter of an hour, at the option of the owner or operator). Use 
the hourly heat input rate at the common stack level and the hourly 
average NOX emission rate at the common stack level and 
the procedures in section 8.1.1 of this appendix to determine the 
hourly NOX mass emissions at the common stack.

    8.1.3  If a unit has multiple ducts and NOX emission 
rate is only measured at one duct, use the NOX emission 
rate measured at the duct, the heat input measured for the unit, and 
the procedures in section 8.1.1 of this appendix to determine 
NOX mass emissions.
    8.1.4  If a unit has multiple ducts and NOX emission 
rate is measured in each duct, heat input shall also be measured in 
each duct and the procedures in section 8.1.1 of this appendix shall 
be used to determine NOX mass emissions.
    8.2  Use the following procedures to calculate quarterly, 
cumulative ozone season, and cumulative yearly NOX mass 
emissions, in tons:
[GRAPHIC] [TIFF OMITTED] TP21MY98.048

(Eq. F-25)

Where:

M(NOX)time period=NOX mass emissions in tons 
for the given time period (quarter, cumulative ozone season, 
cumulative year-to-date).
M(NOX)h=NOX mass emissions in lbs for the 
hour.
p=The number of hours in the given time period (quarter, cumulative 
ozone season, cumulative year-to-date).
    8.3  Specific provisions for monitoring NOX mass 
emissions from common stacks. The owner or operator of a unit 
utilizing a common stack may account for NOX mass 
emissions using either of the following methodologies, if the 
provisions of subpart H are adopted as requirements of a state or 
federal NOX mass reduction program:
    8.3.1  The owner or operator may determine both NOX 
emission rate and heat input at the common stack and use the 
procedures in section 8.1.1 of this appendix to determine hourly 
NOX mass emissions.
    8.3.2  The owner or operator may determine the NOX 
emission rate at the common stack and the heat input at each of the 
units and use the procedures in section 8.1.2 of this appendix to 
determine the hourly NOX mass emissions.

APPENDIX G TO PART 75--DETERMINATION OF CO2 EMISSIONS

* * * * *
    73. Section 2 of appendix G to part 75 is amended by revising the 
term ``Wc'' that follows Equation G-1 to read as follows:

[[Page 28191]]

2. Procedures for Estimating CO2 Emissions From 
Combustion

2.1  * * *

(Eq. G-1)

Where:
* * * * *
WC=Carbon burned, lb/day, determined using fuel sampling 
and analysis and fuel feed rates. Collect at least one fuel sample 
during each week that the unit combusts coal, one sample per each 
shipment for oil and diesel fuel, and one fuel sample for each 
delivery for gaseous fuel in lots, for each daily gas sample for 
gaseous fuel delivered by pipeline, or for each monthly sample of 
pipeline natural gas. Collect coal samples from a location in the 
fuel handling system that provides a sample representative of the 
fuel bunkered or consumed during the week. Determine the carbon 
content of each fuel sampling using one of the following methods: 
ASTM D3178-89 or ASTM D5373-93 for coal; ASTM D5291-92 ``Standard 
Test Methods for Instrumental Determination of Carbon, Hydrogen, and 
Nitrogen in Petroleum Products and Lubricants,'' ultimate analysis 
of oil, or computations based upon ASTM D3238-90 and either ASTM 
D2502-87 or ASTM D2503-82 (Reapproved 1987) for oil; and 
computations based on ASTM D1945-91 or ASTM D1946-90 for gas. Use 
daily fuel feed rates from company records for all fuels and the 
carbon content of the most recent fuel sample under this section to 
determine tons of carbon per day from combustion of each fuel. (All 
ASTM methods are incorporated by reference under Sec. 75.6). Where 
more than one fuel is combusted during a calendar day, calculate 
total tons of carbon for the day from all fuels.
* * * * *
    74. Appendix G to part 75 is amended by adding a new section 5 and 
Table G-1 to read as follows:

5. Missing Data Substitution Procedures for Fuel Analytical Data

    Use the following procedures to substitute for missing fuel 
analytical data used to calculate CO2 mass emissions 
under this appendix.

5.1  Missing Carbon Content Data Prior to 1/1/2000

    Prior to January 1, 2000, follow either the procedures of this 
section or the procedures of section 5.2 of this appendix to 
substitute for missing carbon content data. On and after January 1, 
2000, use the procedures of section 5.2 of this appendix to 
substitute for missing carbon content data, not the procedures of 
this section.

5.1.1  Most Recent Previous Data

    Substitute the most recent, previous carbon content value 
available for that fuel type (gas, oil, or coal) of the same grade 
(for oil) or rank (for coal). To the extent practicable, use a 
carbon content value from the same fuel supply. Where no previous 
carbon content data are available for a particular fuel type or rank 
of coal, substitute the default carbon content from Table G-1 below.

5.1.2  [Reserved]

5.2  Missing Carbon Content Data on and After 1/1/2000

    Prior to January 1, 2000, follow either the procedures of this 
section or the procedures of section 5.1 of this appendix to 
substitute for missing carbon content data. On and after January 1, 
2000, use the procedures of this section to substitute for missing 
carbon content data.

5.2.1  Missing Weekly Samples

    If carbon content data are missing for weekly coal samples or 
composite oil samples from continuous sampling, substitute the 
highest carbon content from the previous four carbon samples 
available. If no previous carbon content data are available, use the 
default carbon content from Table G-1, below.

5.2.2  Manual Sample From Storage Tank

    If carbon content data are missing for manual oil or diesel fuel 
samples taken from the storage tank after transfer of a new delivery 
of fuel, substitute the highest carbon content from all samples in 
the previous calendar year. If no previous carbon content data are 
available from the previous calendar year, use the default carbon 
content from Table G-1, below.

5.2.3  As-Delivered Sample

    If carbon content data are missing for as-delivered samples of 
oil, diesel fuel, or gaseous fuel delivered in lots, substitute the 
highest carbon content from all deliveries of that fuel in the 
previous calendar year. If no previous carbon content data are 
available for that fuel from the previous calendar year, use the 
default carbon content from Table G-1, below.

5.2.4  Sample of Gaseous Fuel Supplied by Pipeline

    If carbon content data are missing for a gaseous fuel that is 
supplied by a pipeline and sampled on either a monthly or a daily 
basis for sulfur and gross calorific value, substitute the highest 
carbon content available for that fuel from the previous calendar 
year. If no previous carbon content data are available for that fuel 
from the previous calendar year, use the default carbon content from 
Table G-1, below.

   Table G-1.--Missing Data Substitution Procedures for Missing Carbon  
                              Content Data                              
------------------------------------------------------------------------
                                                        Missing data    
          Parameter            Sampling technique/      substitution    
                                    frequency             procedure     
------------------------------------------------------------------------
Oil and coal carbon content.  All oil and coal      Most recent,        
                               samples, prior to     previous carbon    
                               January 1, 2000.      content value      
                                                     available for that 
                                                     grade of oil.      
                              Weekly coal sample    Highest carbon in   
                               or Flow               previous 4 weekly  
                               proportional/weekly   samples.           
                               composite oil                            
                               sample (beginning                        
                               no later than                            
                               January 1, 2000).                        
                              In storage tank       Maximum carbon      
                               (after addition of    content from all   
                               fuel to tank)         samples in previous
                               (beginning no later   calendar year.     
                               than January 1,                          
                               2000).                                   
                              As delivered (in      Maximum carbon      
                               delivery truck or     content from all   
                               barge) (beginning     deliveries in      
                               no later than         previous calendar  
                               January 1, 2000).     year.              
Gas carbon content..........  All gaseous fuel      Most recent,        
                               samples, prior to     previous carbon    
                               January 1, 2000.      content value      
                                                     available for that 
                                                     type of gaseous    
                                                     fuel.              
                              Gaseous fuel in       Maximum carbon      
                               lots--as-delivered    content of all     
                               sampling (beginning   samples in previous
                               no later than         calendar year.     
                               January 1, 2000).                        
                              Gaseous fuel          Maximum carbon      
                               delivered by          content of all     
                               pipeline that is      samples in previous
                               sampled for sulfur    calendar year.     
                               content--daily                           
                               sampling (beginning                      
                               no later than                            
                               January 1, 2000).                        
                              Pipeline natural gas  Maximum carbon      
                               that is not sampled   content of all     
                               for sulfur content--  samples in previous
                               monthly sampling      calendar year.     
                               for GCV and carbon                       
                               only (beginning no                       
                               later than January                       
                               1, 2000).                                
Default coal carbon content.  All.................  Anthracite: 90.0    
                                                     percent.           
                                                    Bituminous: 85.0    
                                                     percent.           
                                                    Subbituminous/      
                                                     Lignite: 75.0      
                                                     percent.           
Default oil carbon content..  All.................  90.0 percent.       

[[Page 28192]]

                                                                        
Default gas carbon content..  All.................  Natural gas: 75.0   
                                                     percent.           
                                                    Other gaseous fuels:
                                                     90.0 percent.      
------------------------------------------------------------------------

5.3  Gross Calorific Value Data

    For a gas-fired unit using the procedures of section 2.3 of this 
appendix to determine CO2 emissions, substitute for 
missing gross calorific value data used to calculate heat input by 
following the missing data procedures for gross calorific value in 
section 2.4 of appendix D to this part.

Appendix H To Part 75--Revised Traceability Protocol No. 1

    75. Appendix H to part 75 is removed and reserved.
    76. Appendix I to part 75 is added as follows:

Appendix I To Part 75--Optional F-Factor/Fuel Flow Method

1. Applicability

    1.1  This procedure may be used in lieu of continuous flow 
monitors for the purpose of determining volumetric flow from gas-
fired units, as defined in Sec. 72.2 of this chapter, or oil-fired 
units, as defined in Sec. 72.2 of this chapter, provided that the 
units burn only pipeline natural gas, natural gas, and/or fuel oil. 
These procedures use fuel flow measurement, fuel sampling data, 
CO2 (or O2) CEMS data, and F-factors to 
determine the flow rate of the stack gas. These procedures may only 
be used during those hours when only one type of fuel is combusted.
    1.2  Apply to the Administrator, in a certification application, 
for approval to use this method in lieu of a continuous flow 
monitor, no later than the deadlines for the certification of 
continuous emission monitoring systems specified in Secs. 75.20 and 
75.63.

2. Procedure

2.1  Initial Certification and Recertification Testing

    Either of the following procedures may be used to perform 
initial certification and recertification testing of the appendix I 
excepted flow monitoring system:

2.1.1  Component-by-Component Certification Testing

    Test both the fuel flowmeter component and the CO2 
(or O2) monitor component separately, following the 
procedures of this part. Determine BAFSystem and 
BAFCO2 or BAFO2, using the procedures in 
section 3.7 of this appendix.

2.1.1.1  Certification of the Fuel Flowmeter

    Test the fuel flowmeter according to the procedures and 
performance specifications in section 2.1.5 of appendix D to this 
part.

2.1.1.2  Certification of the CO2 (or O2) Monitor

    Test the CO2 or O2 monitor according to 
the procedures and performance specifications in appendix A to this 
part. Notwithstanding the requirements of appendix A to this part, 
calculate the BAF of the CO2 or O2 monitor 
according to section 3.7 of this appendix.

2.1.2  System Certification Testing

    Test the entire appendix I flow monitoring system to meet the 
relative accuracy requirements for flow, as found in section 3.3.4 
of appendix A to this part, using the applicable procedures in 
sections 6.5 through 6.5.2.2 of appendix A to this part. Use the 
fuel sampling data for density and carbon content to calculate the 
hourly volumetric flow rate according to section 2.3 of this 
appendix. Perform the bias test and, if necessary, calculate a bias 
adjustment factor for the appendix I flow monitoring system using 
the procedures in section 7.6 of appendix A to this part. Also 
perform the 7-day calibration error test, cycle time test, and 
linearity check on the CO2-or O2-diluent 
monitor.

2.2  On-Going Quality Assurance Testing

2.2.1  Daily Assessments

    The CO2 or O2 monitor shall meet the daily 
assessment requirements in section 2.1 of appendix B to this part.

2.2.2  Quarterly Assessments

    The CO2 or O2 monitor shall meet the 
quarterly assessment requirements in section 2.2 of appendix B to 
this part.

2.2.3  Semiannual or Annual Assessments

2.2.3.1  Component-by-Component Assessments

    Test both the fuel flowmeter and the CO2 (or 
O2) monitor separately. Determine BAFSystem 
and BAFCO2 or BAFO2 using the procedures in 
section 3.7 of this appendix.

2.2.3.1.1  Assessment of the Fuel Flowmeter

    The fuel flowmeter shall meet the periodic quality assurance 
requirements in section 2.1.6 of appendix D to this part. The fuel 
flowmeter shall meet the flowmeter accuracy specification in section 
2.1.5 of appendix D to this part.

2.2.3.1.2  Relative Accuracy Assessment of the CO2 (or 
O2) Monitor

    Test the CO2 or O2 monitor for relative 
accuracy according to the applicable procedures in sections 6.5 
through 6.5.2.2 of appendix A to this part. Determine the relative 
accuracy test frequency (i.e., semiannual or annual) using section 
2.3.1 and figure 2 in appendix B to this part. Perform the bias test 
and calculate any bias adjustment factor, as specified in section 
3.7.1 of this appendix for the CO2 monitor or as 
specified in section 3.7.2 of this appendix for the O2 
monitor.

2.2.3.2  System Relative Accuracy Assessment

    Test the entire appendix I flow monitoring system to meet the 
relative accuracy requirements for flow, as found in section 3.3.4 
of appendix A to this part, using the procedures in section 6.5.2 of 
appendix A to this part. Use Reference Method 2 (or its allowable 
alternatives) in appendix A to part 60 of this chapter to obtain the 
reference method flow rate value for each run. Use the appropriate 
equation selected from Eq. I-1 through Eq. I-9 to calculate the 
Appendix I flow rate value for each RATA run. Base the fuel sampling 
on section 2.3 of this appendix. Determine the schedule for future 
relative accuracy tests using the provisions of section 2.3.1 and 
figure 2 of appendix B to this part for a flow monitoring system. 
Perform the bias test and, if necessary, calculate a bias adjustment 
factor for the appendix I flow monitoring system using the 
procedures in section 7.6 of appendix A to this part.

2.3  Fuel Sampling and Analysis

2.3.1  Carbon Content of Oil

    Determine carbon content of the oil by using the following 
procedures. Collect at least one sample per each shipment for oil 
and diesel fuel. Determine the carbon content of the fuel sampling 
using one of the following methods: ASTM D5291-92 ``Standard Test 
Methods for Instrumental Determination of Carbon, Hydrogen, and 
Nitrogen in Petroleum Products and Lubricants,'' ultimate analysis 
of oil, or computations based upon ASTM D3238-90 and either ASTM 
D2502-87 or ASTM D2503-82 (Reapproved 1987) for oil.

2.3.2  Density of Oil

    Determine the density of oil using the procedures in section 2.2 
of appendix D to this part.

2.3.3  Gross Calorific Value of Natural Gas

    Determine gross calorific value of natural gas by using the 
procedures in section 5.5.2 of appendix F to this part.

3. Calculations

3.1  Hourly Volumetric Flow during Combustion of Oil Only for 
Systems that Use a CO2 Monitor and a Volumetric Oil 
Flowmeter
[GRAPHIC] [TIFF OMITTED] TP21MY98.049

(Eq. I-1)


[[Page 28193]]


Where:

Qs=Volumetric stack flow rate, adjusted for bias, in 
scfh.
BAFsystem=Bias adjustment factor for the system, as 
determined by Equation I-10A or I-10B (for component-by-component 
testing) in section 3.7 of this appendix or by Equation I-11 (for 
system testing) in section 3.8 of this appendix.
V=Volumetric oil flow rate, gal/hr.
=Oil density, lb/gal.
%C=Percent carbon by weight.
%CO2=CO2 concentration, percent by volume.
32.08=Conversion factor, 385 scf CO2/12 lb C, volume of 
CO2 emitted for each pound carbon in oil.

3.2  Hourly Volumetric Flow during Combustion of Oil Only for 
Systems that Use an O2 Monitor and a Volumetric Oil 
Flowmeter

    3.2.1  If relative accuracy is determined on a system basis, use 
the following equation to determine the volumetric stack flow rate:
[GRAPHIC] [TIFF OMITTED] TP21MY98.050

(Eq. I-2)

Where:

Qs=Volumetric stack flow rate, adjusted for bias, in 
scfh.
BAFsystem=Bias adjustment factor for the system, as 
determined by Equation I-11 (for system testing) in section 3.8 of 
this appendix.
V=Volumetric oil flow rate, gal/hr.
=Oil density, lb/gal.
%C=Percent carbon by weight.
%O2d=Dry basis O2 concentration, percent by 
volume.
%H2O=Percent moisture in the flue gas.
207.6379=Conversion factor, 385 scf CO2/12 lb C x 9190 
dscf O2/1420 scf CO2, volume of O2 
emitted for each pound carbon in oil.

    3.2.2  If relative accuracy is determined on a component by 
component basis, use the following equation to determine the 
volumetric stack flow rate:
[GRAPHIC] [TIFF OMITTED] TP21MY98.051

(Eq. I-3)

Where:

Qs Volumetric stack flow rate, adjusted for bias, in 
scfh.
BAFO2=Bias adjustment factor for the O2 
monitor, as determined by section 3.7.2 of this appendix.
V=Volumetric oil flow rate, gal/hr.
=Oil density, lb/gal.
%C=Percent carbon by weight.
%O2d=Dry basis O2 concentration, percent by 
volume.
%H2O=Percent moisture in the flue gas.
1.12=Default multiplier used to compensate for systematic error in 
the demonstration data.
207.6379=Conversion factor, 385 scf CO2/12 lb C x 9190 
dscf O2/1420 scf CO2, volume of O2 
emitted for each pound carbon in oil.

3.3  Hourly Volumetric Flow during Combustion of Oil Only for 
Systems that Use a CO2 Monitor and a Mass Oil Flowmeter
[GRAPHIC] [TIFF OMITTED] TP21MY98.052

(Eq. I-4)

Where:

Qs=Volumetric stack flow rate, adjusted for bias, in 
scfh.
BAFsystem=Bias adjustment factor for the system, as 
determined by Equation I-10A or I-10B (for component by component 
testing) in section 3.7 of this appendix or by Equation I-11 (for 
system testing) in section 3.8 of this appendix.
M=Oil mass flow rate, lb/hr.
%C=Percent carbon by weight.
%CO2=CO2 concentration, percent by volume.
32.08=Conversion factor, 385 scf CO2/12 lb C, volume of 
CO2 emitted for each pound carbon in oil.

3.4  Hourly Volumetric Flow during Combustion of Oil Only for 
Systems that Use an O2 Monitor and a Mass Oil Flowmeter

    3.4.1  If relative accuracy is determined on a system basis, use 
the following equation to determine the volumetric stack flow rate:
[GRAPHIC] [TIFF OMITTED] TP21MY98.053

(Eq. I-5)

Where:

Qs=Volumetric stack flow rate, adjusted for bias, in 
scfh.
BAFsystem=Bias adjustment factor for the system, as 
determined by Equation I-11 (for system testing) in section 3.8 of 
this appendix.
M=Oil mass flow rate, lb/hr.
%C=Percent carbon by weight.
%O2d=Dry basis O2 concentration, percent by 
volume.
%H2O=Percent moisture in the flue gas.
207.6379=Conversion factor, 385 scf CO2/12 lb C x 9190 
dscf O2/1420 scf CO2, volume of O2 
emitted for each pound carbon in oil.

    3.4.2  If relative accuracy is determined on a component by 
component basis, use the following equation to determine the 
volumetric stack flow rate:
[GRAPHIC] [TIFF OMITTED] TP21MY98.054


[[Page 28194]]


(Eq. I-6)

Where:

Qs=Volumetric stack flow rate, adjusted for bias, in 
scfh.
BAFO2=Bias adjustment factor for the O2 monitor, as 
determined by section 3.7.2 of this appendix.
M=Oil mass flow rate, lb/hr.
%C=Percent carbon by weight.
%O2d=Dry basis O2 concentration, percent by 
volume.
%H2O=Percent moisture in the flue gas.
1.12=Default multiplier used to compensate for systematic error in 
the demonstration data.
207.6379=Conversion factor, 385 scf CO2/12 lb C x 9190 
dscf O2/1420 scf CO2, volume of O2 
emitted for each pound carbon in oil.

3.5  Hourly Volumetric Flow during Combustion of Natural Gas Only 
for Systems that Use a CO2 Monitor and a Volumetric Gas 
Flowmeter
[GRAPHIC] [TIFF OMITTED] TP21MY98.055

(Eq. I-7)

Where:

Qs=Volumetric stack flow rate, adjusted for bias, in 
scfh.
BAFsystem=Bias adjustment factor for the system, as 
determined by Equation I-10A or I-10B (for component by component 
testing) in section 3.7 of this appendix or by Equation I-11 (for 
system testing) in section 3.8 of this appendix.
V=Volumetric gas flow rate, 100 scfh.
GCV=Gross calorific value of the gaseous fuel, Btu/scf.
Fc=Carbon-based F-factor of 1040 scf CO2/mmBtu 
for natural gas, from section 3 of appendix F to this part.
%CO2=CO2 concentration, percent by volume.
0.01=Conversion factor, 10-6 mmBtu/Btu x 10\2\ scf/100 
scf x 10\2\ (conversion of fraction to percentage).

3.6  Hourly Volumetric Flow during Combustion of Natural Gas Only 
for Systems that Use an O2 Monitor and a Volumetric Gas 
Flowmeter

3.6.1  Determining Flow for Systems that Are Tested on a System Basis
[GRAPHIC] [TIFF OMITTED] TP21MY98.056

(Eq. I-8)

Where:

Q2=Volumetric stack flow rate, adjusted for bias, in 
scfh.
BAFsystem=Bias adjustment factor for the system, as 
determined by Equation I-11 (for system testing) in section 3.8 of 
this appendix.
V=Volumetric gas flow rate, 100 scfh.
GCV=Gross calorific value of the natural gas, Btu/scf.
Fd=Dry basis, O2-based F-factor for natural 
gas, 8,710 dscf/mmBtu.
%O2d=Dry basis O2 concentration, percent by 
volume.
%H2O=Percent moisture in the flue gas.
0.01=Conversion factor, 10-6 mmBtu/Btu x 10\2\ scf/100 
scf x 10\2\ (conversion of fraction to percentage).

3.6.2  Determining Flow for Systems that are Tested on a Component-by-
Component Basis
[GRAPHIC] [TIFF OMITTED] TP21MY98.057

(Eq. I-9)

Where:

Qs=Volumetric stack flow rate, adjusted for bias, in 
scfh.
BAFO2=Bias adjustment factor for the O2 
monitor, as determined by section 3.7.2 of this appendix.
V=Volumetric gas flow rate, 100 scfh.
GCV=Gross calorific value of the natural gas, Btu/scf.
Fd=Dry basis, O2-based F-factor for natural 
gas, 8,710 dscf/mmBtu.
%O22d=Dry basis O2 concentration, percent by 
volume.
%Hd2O=Percent moisture in the flue gas.
1.12=Default multiplier used to compensate for systematic error in 
the demonstration data.
0.01=Conversion factor, 10-6 mmBtu/Btu x 102 
scf/100 scf x 102 (conversion of fraction to percentage).

3.7  Bias Adjustment Factor for a System Tested Component-by-
Component

3.7.1  Calculation of the System Bias Adjustment Factor, 
BAFsystem, for CO2 Monitor

    Calculate the mean difference of the relative accuracy test data 
for the CO2 monitor, d, using Equation A-7 in section 
7.3.1 of appendix A to this part. Calculate the confidence 
coefficient (cc) using Equation A-9 in section 7.3.3 of appendix A 
to this part. If d < -cc, where d is defined by Equation A-7, 
calculate the bias adjustment factor for a system tested component 
by component, as follows:
[GRAPHIC] [TIFF OMITTED] TP21MY98.058

(Eq. I-10A)

If d  -cc, then
BAFsystem=1.12

(Eq. I-10B)
Where:

BAFsystem=Overall bias adjustment factor for the appendix 
I flow monitoring system.
1.12=Default multiplier used to compensate for systematic error in 
the demonstration data.
d=Mean difference between the reference method and continuous 
emission monitoring system (RMi-CEMi) as 
defined in Equation A-7 in section 7.3.1 of appendix A to this part.
CEM=Mean of the data values provided by the CO2 monitor 
during the relative accuracy test audit.

3.7.2  Calculation of the Component Bias Adjustment Factor, 
BAFO2, for O2 Monitor

    Perform the bias test for the O2 monitor using the 
procedures in section 7.6 of appendix A to this part and, if 
necessary, calculate a bias adjustment factor.

3.8  Bias Adjustment Factor for a System Tested on a System Level

    Calculate the bias adjustment factor for a system tested on a 
system level, as follows:

BAFSystem=GAFflow rate

(Eq. I-11)

Where:

BAFsystem=Overall bias adjustment factor for the appendix 
I flow monitoring system.
BAFflow rate=Bias adjustment factor from relative 
accuracy testing using Reference Method 2 for volumetric flow rate.

4. Missing Data

    4.1 The owner or operator shall provide substitute volumetric 
flow data using the flow missing data procedures in subpart D of 
this part.
4.2  [Reserved]

5. Recordkeeping and Reporting

    Follow the applicable monitoring plan provisions of Sec. 75.53, 
the applicable general recordkeeping provisions of Sec. 75.57, the 
specific recordkeeping provisions of Sec. 75.58(g), the 
certification recordkeeping provisions of Sec. 75.59(d)(1), and the 
quality assurance test recordkeeping provisions of Sec. 75.59(d)(2). 
Maintain a quality assurance/quality control plan, as specified in 
appendix

[[Page 28195]]

B to this part. Follow the reporting provisions of Secs. 75.60 
through 75.67.

    77. Appendix J to part 75 is removed and reserved.
[FR Doc. 98-11749 Filed 5-20-98; 8:45 am]
BILLING CODE 6560-50-P